UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2014

OR

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

 For the transition period fromto

Commission File No. 333-192373

Sabine Pass Liquefaction, LLC

(Exact name of registrant as specified in its charter)

Delaware	27-3235920
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
700 Milam Street, Suite 1900 Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

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

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

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

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

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

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

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

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	10
Item 1B. Unresolved Staff Comments	20
Item 3. Legal Proceedings	20
Item 4. Mine Safety Disclosure	20
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	21
Item 6. Selected Financial Data	21
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A. Quantitative Disclosures about Market Risk	31
Item 8. Financial Statements and Supplementary Data	32
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	58
Item 9A. Controls and Procedures	58
Item 9B. Other Information	58
PART III
Item 10. Directors, Executive Officers of Our General Partner and Corporate Governance	59
Item 11. Executive Compensation	59
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Unitholder Matters	59
Item 13. Certain Relationships and Related Transactions, and Director Independence	59
Item 14. Principal Accountant Fees and Services	59
PART IV
Item 15. Exhibits and Financial Statement Schedules	60
Signatures	66

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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 natural gas liquefaction project, or any expansions or portions thereof, by certain dates, or at all; 

• statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of liquefied natural gas (“LNG”) 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 natural gas liquefaction trains (“Trains”), including statements concerning the engagement of any engineering, procurement and construction (“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 LNG sale and purchase agreement (“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 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 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 Securities and Exchange Commission (“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.

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DEFINITIONS

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

• Bcf/d means billion cubic feet per day;

• Bcf/yr means billion cubic feet per year;

• Bcfe means billion cubic feet equivalent;

• EPC means engineering, procurement and construction;

• Henry Hub means 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;

• LNG means liquefied natural gas, a product of natural gas consisting primarily of methane (CH4) that is in liquid form at near atmospheric pressure;

• MMBtu means million British thermal units, an energy unit;

• MMBtu/d means million British thermal units per day;

• MMBtu/yr means million British thermal units per year;

• mtpa means million metric tonnes per annum;

• SPA means an LNG sale and purchase agreement;

• Train means a compressor train used in the industrial process to convert natural gas into LNG; and

• TUA means terminal use agreement.

PART I

ITEMS 1. and 2.        BUSINESS AND PROPERTIES

General

We are a Delaware limited liability company formed by Cheniere Energy Partners, L.P. (“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 (the “Sabine Pass LNG terminal”) adjacent to the existing regasification facilities owned and operated by Sabine Pass LNG, L.P. (“Sabine Pass LNG”).  We plan to construct up to six Trains which are in various stages of development. Each Train is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG. We and Sabine Pass LNG are each indirect wholly owned subsidiaries of Cheniere Energy Investments, LLC (“Cheniere Investments”), which is a wholly owned subsidiary of Cheniere Partners. Cheniere Partners is a publicly traded limited partnership formed in November 2006 and is a 55.9% owned subsidiary of Cheniere Energy Partners LP Holdings, LLC, which is in turn an 80.1% owned subsidiary of Cheniere Energy, Inc. (“Cheniere”), a Houston-based energy company primarily engaged in LNG-related businesses.

Our Business Strategy

Our primary objective is to generate stable cash flows by:

• completing construction and commencing operation of our Trains;

• 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 Pass deep water shipping channel less than four miles from the Gulf Coast and includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9

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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 Federal Energy Regulatory Commission (the “FERC”) to site, construct and operate Trains 1 through 4. 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. On September 30, 2013, we filed an application with the FERC for the approval to site, construct and operate Trains 5 and 6.

The U.S. Department of Energy (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 countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas (“FTA countries”) for a 30-year term, beginning on the earlier of the date of first export or September 7, 2020; and to all countries without a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted (“non-FTA countries”) for a 20-year term, beginning on the earlier of the date of first export or August 7, 2017. 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. Additionally, the DOE further issued orders authorizing us to export an additional 503.3 Bcf/yr in total of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 20-year term. Our applications for authorization to export that same 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to non-FTA countries are currently pending at the DOE.

As of December 31, 2014, the overall project completion percentages for Trains 1 and 2 and Trains 3 and 4 of the Liquefaction Project were approximately 81% and 54%, respectively, which are ahead of the contractual schedule. Based on our current construction schedule, we anticipate that Train 1 will produce LNG as early as late 2015, and Trains 2, 3 and 4 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 - 4	Trains 5 & 6
DOE export authorization	Received	Received FTA Pending Non-FTA
Definitive commercial agreements	Completed 16.0 mtpa	T5: Completed T6: 2015
- BG Gulf Coast LNG, LLC	5.5 mtpa
- Gas Natural Fenosa	3.5 mtpa
- KOGAS	3.5 mtpa
- GAIL (India) Ltd.	3.5 mtpa
- Total Gas & Power N.A.		2.0 mtpa
- Centrica plc		1.75 mtpa
EPC contract	Completed	2015
Financing	Completed	2015
- Equity commitments
- Debt commitments
FERC authorization	Completed
- FERC Order		2015
- Certificate to commence construction		2015
Issue Notice to Proceed	Completed	2015
Commence operations	2015 - 2017	2018/2019

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Customers

We have entered into four fixed-price, 20-year SPAs with third parties that in the aggregate equate to 16 mtpa (approximately 803 Bcf/yr) of LNG that commence with the date of first commercial delivery for Trains 1 through 4, which are fully permitted. In addition, we have entered into two fixed-price, 20-year SPAs with third parties for another 3.75 mtpa of LNG that commence with the date of first commercial delivery for Train 5. However, we have not yet received regulatory approval for construction of Train 5. Under the 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 cargoes 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 the specified Train. As of December 31, 2014, 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 these customers is approximately $2.3 billion annually for Trains 1 through 4, and $2.9 billion annually if we make a positive final investment decision with respect to Train 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. The Total and Centrica SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision with respect to Train 5, which must be satisfied by June 30, 2015 or either party to the respective SPA may terminate its SPA.

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In addition, Cheniere Marketing, LLC (“Cheniere Marketing”), an indirect wholly owned subsidiary of Cheniere, has entered into an amended and restated SPA with us (the “Cheniere Marketing SPA”) to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

Natural Gas Transportation and Supply

For our natural gas feedstock transportation requirements, we have entered into transportation precedent agreements to secure firm pipeline transportation capacity with Cheniere Creole Trail Pipeline, L.P. (“CTPL”), a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. We have also entered into enabling agreements and long-term natural gas purchase agreements with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2014, we have secured up to approximately 2,162,000,000 MMBtu of natural gas feedstock through long-term natural gas purchase agreements.

Construction

Trains 1 through 4 are being designed, constructed and commissioned by Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”). 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)”) and Trains 3 and 4 (the “EPC Contract (Trains 3 and 4),” and together with the EPC Contract (Trains 1 and 2), the “EPC Contracts”) under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause us to enter into a change order, or we agree with Bechtel to a change order.

The total contract price of the EPC Contract (Trains 1 and 2) and the total contract price of the EPC Contract (Trains 3 and 4) are approximately $4.1 billion and $3.8 billion, respectively, reflecting amounts incurred under change orders through December 31, 2014. Total expected capital costs for Trains 1 through 4 are estimated to be between $9.0 billion and $10.0 billion before financing costs and between $12.0 billion and $13.0 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

Final Investment Decision on Train 5 and Train 6

We will contemplate making a final investment decision to commence construction of Train 5 and Train 6 of the Liquefaction Project based upon, among other things, entering into an EPC contract, entering into acceptable commercial arrangements, receiving regulatory authorizations and obtaining adequate financing to construct the Trains.

Terminal Use Agreement

In July 2012, Cheniere Investments assigned to us a TUA with Sabine Pass LNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG, which will provide us access to additional facilities needed for us to deliver LNG to our SPA customers. We have reserved approximately 2.0 Bcf/d of regasification capacity, and we are obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year, continuing until at least 20 years after we deliver our first commercial cargo at the Liquefaction Project. Sabine Pass LNG has no obligation to provide us with certain services such as (i) harbor, mooring and escort services for LNG vessels, including the provision of tugboats, (ii) the transportation of natural gas downstream from the Sabine Pass LNG terminal or the construction of any pipelines to provide such transportation or (iii) the marketing of natural gas. We also entered into a terminal use rights assignment and agreement (“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 Sabine Pass LNG.  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

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applicable permits and other authorizations. This regulatory requirement increases the 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 proposed 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 and Sabine Pass LNG’s 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. The FERC approval requires us and Sabine Pass LNG to obtain certain additional FERC approvals as construction progresses. To date, we and Sabine Pass LNG have been able to obtain these approvals as needed. On October 9, 2012, we and Sabine Pass LNG applied to amend the FERC approval to reflect certain modifications to the Liquefaction Project, and on August 2, 2013, the FERC issued an order approving the modifications. On October 25, 2013, we and Sabine Pass LNG 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. On February 20, 2014, the FERC issued an order granting the request. The need for these approvals has not materially affected the construction progress. The FERC’s approval to site, construct and operate Trains 5 and 6 will also be required. In this regard, on September 30, 2013, we, Sabine Pass LNG and Sabine Pass Liquefaction Expansion, LLC filed an application with the FERC for authorization to add Trains 5 and 6 to the Liquefaction Project. Throughout the life of our proposed liquefaction facilities, we and Sabine Pass LNG will be subject to regular reporting requirements to the FERC and the U.S. Department of Transportation regarding the operation and maintenance of the facilities.

The EPAct amended the NGA to prohibit market manipulation, and increased civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC, up to $1.0 million per day per violation. In accordance with the EPAct, the FERC issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement of material fact or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud or deceit upon any entity.

DOE Export License

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, beginning on the earlier of the date of first export or September 7, 2020; and to non-FTA countries for a 20-year term, beginning on the earlier of the date of first export or August 7, 2017. 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.

Additionally, the DOE further issued three orders authorizing the export of an additional 503.3 Bcf/yr in total of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 20-year term. One order authorized the export of 101 Bcf/yr of domestically produced LNG pursuant to the SPA with Total, beginning on the earlier of the date of first export or July 11, 2021; the second order authorized the export of 88.3 Bcf/yr of domestically produced LNG pursuant to the SPA with Centrica, beginning on the earlier of the date of first export or July 12, 2021; and the third order authorized the export of 314 Bcf/yr of domestically produced LNG, beginning on the earlier of the date of first export or January 22, 2022. Additional applications to the DOE for permits to allow the export of the additional 503.3 Bcf/yr of domestically produced LNG to non-FTA countries are pending.

Exports of natural gas to FTA countries “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

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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 (“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 Trains 1 through 4 was submitted in January 2011. The process included a public comment period which commenced in March 2011 and closed in April 2011. The revised Section 10/404 Permit was received from the USACE in March 2012. An application for a further revision to the Section 10/404 Permit, to address wetlands impacted by the construction of Trains 5 and 6, is currently pending before the USACE. We do not anticipate obtaining this permit until after FERC issues an order approving the expansion of the Liquefaction Project. In addition, a Section 10/404 permit application is pending with respect to the expansion of the Creole Trail Pipeline. Both of these permits, if issued, will require us to provide mitigation to compensate for the wetlands impacted by the respective projects. The application to amend the Sabine Pass LNG terminal’s existing Title V and PSD permits to authorize construction of Trains 1 through 4 was initially submitted in December 2010 and revised in March 2011. The process included a public comment period from June 2011 to August 2011 and a public hearing in August 2011. The final revised Title V and PSD permits were issued by the LDEQ in December 2011. Although these permits are final, a petition with the EPA has been filed pursuant to the Clean Air Act requesting that the EPA object to the Title V permit. The EPA has not ruled on this petition. In June 2012, we applied to the LDEQ for a further amendment to the Title V and PSD permits to reflect proposed modifications to the Liquefaction Project that were filed with the FERC in October 2012. The LDEQ issued the amended PSD and Title V permits in March 2013. These permits are final. In September 2013, we applied to the LDEQ for another amendment to our PSD and Title V permits seeking approval to, among other things, construct and operate Trains 5 and 6. We anticipate, but cannot guarantee, that the revised Title V and PSD permits authorizing, among other things, construction and operation of Trains 5 and 6 will be issued in the second quarter of 2015.

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 regasification and liquefaction facilities are 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

Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (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 swaps that the Commodity Futures Trading Commission (the “CFTC”) designated by rule to be cleared, (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, and (5) enhance the CFTC’s rulemaking and enforcement authority, including the authority to establish position limits on certain swaps and futures products. As required by the Dodd-Frank Act, the CFTC, the SEC and other regulators have been promulgating rules and regulations implementing the swaps regulatory provisions of the Dodd-Frank Act, although neither the CFTC nor the SEC has yet adopted all of the rules required by the Dodd-Frank Act. As a result of the Dodd-Frank Act’s provisions, the CFTC, in order to regulate excessive speculation in commodities, must adopt rules imposing new position limits

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on futures and options contracts and economically equivalent physical commodity swaps, on 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.

After a court vacated the final rules that the CFTC adopted imposing position limits on certain core futures and equivalent swaps contracts for physical commodities, including Henry Hub natural gas, the CFTC published in the Federal Register on December 12, 2013, proposed new position limits rules that would modify and expand the applicability of position limits on the amounts of core futures and equivalent swaps contracts of such types that market participants could hold, subject to exceptions for certain bona fide hedging transactions. An extended comment period on such proposed position limits rules has expired, but the CFTC has not yet acted to adopt the proposed rules.

Pursuant to rules adopted by the CFTC, six classes of over-the-counter (“OTC”) interest rate and credit default swaps must be cleared on a designated clearing organization and also must be 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 and trade execution, but could do so in the future. Although we expect to qualify for the “end-user exception” from the mandatory clearing and exchange-trading requirements applicable to any swaps we enter into to hedge our commercial risks, the mandatory clearing and exchange-trading requirements may apply to other market participants, such as our counterparties (who may be registered as Swap Dealers), and the application of such rules may change the cost and availability of the swaps that we use for hedging. For uncleared swaps, the CFTC or federal banking regulators may require our counterparties to require us to enter into credit support documentation with them and/or require us to post initial and variation margin with respect to our uncleared swaps. On September 24, 2014, the banking regulators published in the Federal Register proposed joint rules to establish minimum margin and capital requirements for registered Swap Dealers, Major Swap Participants, security-based Swap Dealers, and major security-based swap participants regulated by the banking regulators, although those requirements would not require collection of initial or variation margin from non-financial end users. On October 3, 2014, the CFTC published in the Federal Register similar proposed rules for initial and variation margin requirements. The proposed CFTC rules establish initial and variation margin requirements for Swap Dealers and Major Swap Participants, but do not require these entities to collect margin from non-financial end users. However, the proposed rules are not yet final and therefore the application of those provisions to us is uncertain at this time. On January 12, 2015, President Obama signed into law legislation modifying the Dodd-Frank Act and clarifying that any rules for the collection of initial or variation margin for uncleared swaps shall not apply to non-financial end users that qualify for the end user exception to clearing. Other provisions of the Dodd-Frank Act may also cause our derivatives counterparties to spin off some or all of their derivatives activities to a separate entity, and such separate entity, who could be our counterparty in future swaps, may not be as creditworthy as the current counterparty. 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, the CFTC is directed generally to prevent manipulation and fraud in two markets: (a) physical commodities traded in interstate commerce, including physical energy and other commodities, as well as (b) financial instruments, such as futures, options and swaps. Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-manipulation, anti-fraud and anti-disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation 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.

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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, results of operations 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 with respect to Train 6, 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 nine 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.

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Our ability to enter into additional long-term sale and purchase agreements to underpin the development of additional Trains, sell any quantities of LNG available under the SPA 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 29 Tcf between 2012 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 85%, from approximately 237 mtpa, or 11.5 Tcf, in 2012, to 438 mtpa, or 21.4 Tcf, in 2025 and that LNG production from existing facilities and new facilities already under construction will be able to supply the market with 337 mtpa in 2025, resulting in a market need for construction of an additional 101 mtpa of LNG production.  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 to the recent 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, 2015, futures prices indicate that LNG exported from the U.S. continues to be competitive with LNG from alternative sources, supporting the need for additional long-term, medium-term and short-term contracting of LNG from the Liquefaction Project.

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, 2015, Cheniere and its subsidiaries had 642 full-time employees, including 371 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.

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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 Proposed 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, 2014, we had zero cash and cash equivalents, $0.6 billion of restricted cash and cash equivalents and $6.5 billion of total debt outstanding (before debt discounts). 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 Trains 5 and 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. Furthermore, 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 have not been profitable historically. We may not achieve profitability or generate positive operating cash flow in the future.

We had net losses of $376.9 million, $194.5 million and $85.2 million for the years ended December 31, 2014, 2013 and 2012, 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.

In addition, 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 any significant cash flows from the Liquefaction Project until late 2015, at the earliest. Any delays beyond the expected development period for Train 1 could cause, and could increase the level of, our operating losses. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate 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 BG, Gas Natural Fenosa, KOGAS, GAIL, Total and Centrica, each of which has entered into an SPA with us and agreed to pay us approximately $723 million, $454 million, $548 million, $548 million, $314 million and $274 million annually, respectively. 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.

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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: (i) upon the occurrence of certain events of force majeure; (ii) if we fail to make available specified scheduled cargo quantities; (iii) delays in the commencement of commercial operations; and (iv) if the conditions precedent contained in the Total and Centrica SPAs are not met or waived by specified dates. 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 results of operations or liquidity.

To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we will 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 provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations that may have an effect on our derivatives could have an adverse impact on our ability to hedge risks associated with our business and on our results of operations and cash flows.

The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder by the CFTC and SEC 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. As mandated by the Dodd-Frank Act, the CFTC has proposed rules setting limits on the positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, including Henry Hub natural gas, held by market participants, with exceptions for certain bona fide hedging transactions. If the position limits in the proposed rules or other similar position limits were imposed, our ability to execute our hedging strategies described above could be compromised.

Under the swaps regulatory provisions of the Dodd-Frank Act, and the rules adopted thereunder, we could have to clear on a designated 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 markets. 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 failed to qualify for that exception as to any swap we enter into and had to clear that swap over a designated clearing organization, we may have to post margin with respect to such swap, our cost of entering into and maintaining such swap could increase and the flexibility we enjoy with respect to entering into uncleared OTC swaps could be diminished. In addition, 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 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. 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. Although the CFTC and federal banking regulators have proposed rules to require certain types of market participants to collect and post initial and variation margin with respect to uncleared swaps and such rules currently do not require the collection of margin from non-financial end users, if we did not qualify as a non-financial end user as to any of our swaps or the final rules adopted by the CFTC and the federal banking regulators required that the counterparties to our uncleared swaps collect margin from us, our cost of entering into and maintaining swaps would be increased. Provisions of the Dodd-Frank

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Act may also cause our derivatives counterparties to spin off some or all of their derivatives activities to a separate entity, which could be our counterparty in future swaps and which entity may not be as creditworthy as the current counterparty.

The Dodd-Frank Act’s swaps regulatory provisions, the related rules described above and the record keeping, reporting and business conduct rules imposed by the Dodd-Frank Act on other swaps market participants, as well as the regulations imposing the Basel III capital requirements on certain swaps market participants, could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), 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, and increase our exposure to less creditworthy counterparties. 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 results of operations and cash flows may become more volatile and could be otherwise adversely affected.

Risks Relating to the Completion of Our Proposed 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.

The Liquefaction Project will require very significant financial resources, which may not be available on terms reasonably acceptable to us or at all. The Total and Centrica SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision to construct Train 5. If these conditions are not met by June 30, 2015, each party may terminate its respective SPA.

It will take several years to construct our proposed liquefaction facilities, and we do not expect Train 1 to produce LNG until late 2015, at the earliest. Even if successfully constructed, our proposed liquefaction facilities 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

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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 additional Trains 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 Trains 5 and 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 additional Trains, 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 the applicable Train, 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 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.

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

The design, construction and operation of LNG terminals, including the Liquefaction Project, and other facilities, and the import and 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 four Trains, the FERC order requires us to obtain certain additional approvals in conjunction with ongoing construction and operations of our proposed liquefaction facilities. In addition, our application to the FERC under Section 3 of the NGA for authorization to site, construct and operate two additional Trains at the Liquefaction Project is currently pending. The environmental assessment by the FERC was issued in December 2014 and the public comment period has closed with comments from the Sierra Club (as an intervenor) and the EPA (as a cooperating agency). We also have pending applications with the DOE for authorization to export LNG to FTA and 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, 2015, Cheniere and its subsidiaries had 642 full-time employees, including 371 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 Sabine Pass LNG under which Sabine Pass LNG derives economic benefits, we have entered into a transportation

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agreement with a subsidiary of Cheniere Partners to transport natural gas to our proposed liquefaction facilities 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 a natural gas liquefaction facility near Corpus Christi, Texas and may enter into commercial arrangements with respect to this liquefaction facility that might otherwise have been entered into with respect to Train 6.

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

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

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

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

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

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

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

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

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

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

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

Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the 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.

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We are relying on third-party engineers to estimate the future capacity ratings and performance capabilities of our proposed liquefaction facilities, 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 our proposed liquefaction facilities. 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:

• additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG from the Sabine Pass LNG terminal;

• competitive liquefaction capacity in North America, which could divert natural gas from our proposed liquefaction facilities;

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• 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 price 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 our proposed liquefaction facilities 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 have recently been and may continue to 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 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 can be or 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 our proposed liquefaction facilities 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

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liquefaction projects on commercially reasonable terms;

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

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

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

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

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

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

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

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

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

• work stoppages or other labor disturbances at the shipyards;

• bankruptcy or other financial crisis of shipbuilders;

• quality or engineering problems;

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

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

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

We have contracted for firm capacity for our natural gas feedstock transportation requirements for the Liquefaction Project.  We cannot control the regulatory and permitting approvals or third parties’ construction times, 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.

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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 resouces; 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.

There are numerous regulatory approaches currently in effect or being considered to address GHG emissions, including possible future United States treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, and regulation by the EPA. In addition, as we consume natural gas at the Sabine Pass LNG terminal, a future carbon tax or other regulation may be imposed on us directly.

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 Pass deep water shipping channel 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 our proposed liquefaction facilities or in the LNG industry would have a significantly greater impact on our financial condition and results of operations 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

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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 results of operations.

 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, 2014, there were no threatened or pending legal matters that would have a material impact on our results of operations, financial position or cash flows.

ITEM 4.     MINE SAFETY DISCLOSURE

None.

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PART II

ITEM 5.     MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED MEMBER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES

Not applicable.

ITEM 6.    SELECTED FINANCIAL DATA

Selected financial data set forth below are derived from our audited Financial Statements for the periods indicated. 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,												Period from June 24, 2010 (Date of Inception) Through December 31, 2010
	2014			2013			2012			2011
	(in thousands)
Income Statement Data:
Revenues	$	—		$	—		$	—		$	—		$	—
Expenses	120,039			136,136			85,783			36,511			9,869
Loss from operations	(120,039		)	(136,136		)	(85,783		)	(36,511		)	(9,869		)
Loss on early extinguishment of debt	(114,335		)	(131,576		)	—			—			—
Net loss	(376,853		)	(194,490		)	(85,157		)	(36,511		)	(9,869		)

	December 31,
	2014		2013		2012		2011			2010
	(in thousands)
Balance Sheet Data (as of end of period):
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash and cash equivalents (current)	155,810		192,144		75,133		—			—
Non-current restricted cash and cash equivalents	457,053		867,590		196,319		—			—
Property, plant and equipment, net	6,962,395		4,412,580		1,228,720		279			—
Total assets	7,945,745		5,941,972		1,710,380		1,390			61
Long-term debt, net of discount	6,517,266		4,111,562		100,000		—			—
Total equity (deficit)	1,272,401		1,638,265		1,467,239		(46,380		)	(9,869		)

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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 Energy Partners, L.P. (“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 Sabine Pass LNG, L.P. (“Sabine Pass LNG”). We plan to construct up to six Trains, which are in various stages of development. Each Train 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, 2014 and through the filing date of this Form 10-K include the following:

• In April 2014, we entered into a $325.0 million senior letter of credit and reimbursement agreement (the “Senior LC Agreement”) that we are using for the issuance of letters of credit on our behalf for certain working capital requirements related to the Liquefaction Project.

• In May 2014, we issued an aggregate principal amount of $2.0 billion of 5.75% Senior Secured Notes due 2024 (the “2024 Senior Notes”) and $0.5 billion of 5.625% Senior Secured Notes due 2023 (the “2023 Senior Notes”). Net proceeds from the offering of approximately $2.5 billion were used to repay our outstanding indebtedness under the 2013 Liquefaction Credit Facilities (as described below), and the remaining proceeds are being used to pay a portion of the capital costs associated with the construction of the first four Trains of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2013 Liquefaction Credit Facilities.

• In August 2014, we entered into an amended and restated SPA with Cheniere Marketing, LLC (“Cheniere Marketing”), a wholly owned subsidiary of Cheniere, to allow Cheniere Marketing to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

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Liquidity and Capital Resources

Cash and Cash Equivalents

As of December 31, 2014, we had zero cash and cash equivalents and $0.6 billion of current and non-current restricted cash and cash equivalents.

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 Federal Energy Regulatory Commission (the “FERC”) to site, construct and operate Trains 1 through 4. 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. On September 30, 2013, we filed an application with the FERC for the approval to site, construct and operate Trains 5 and 6.

The U.S. Department of Energy (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 countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas (“FTA countries”) for a 30-year term, beginning on the earlier of the date of first export or September 7, 2020; and to all countries without a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted (“non-FTA countries”) for a 20-year term, beginning on the earlier of the date of first export or August 7, 2017. 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. Additionally, the DOE further issued orders authorizing us to export an additional 503.3 Bcf/yr in total of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 20-year term. Our applications for authorization to export that same 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to non-FTA countries are currently pending at the DOE.

As of December 31, 2014, the overall project completion percentages for Trains 1 and 2 and Trains 3 and 4 of the Liquefaction Project were approximately 81% and 54%, respectively, which are ahead of the contractual schedule. Based on our current construction schedule, we anticipate that Train 1 will produce LNG as early as late 2015, and Trains 2, 3 and 4 are expected to commence operations on a staggered basis thereafter.

Customers

We have entered into four fixed-price, 20-year SPAs with third parties that in the aggregate equate to 16 mtpa (approximately 803 Bcf/yr) of LNG that commence with the date of first commercial delivery for Trains 1 through 4, which are fully permitted. In addition, we have entered into two fixed-price , 20-year SPAs with third parties for another 3.75 mtpa of LNG that commence with the date of first commercial delivery for Train 5. However, we have not yet received regulatory approval for construction of Train 5. These two SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision with respect to Train 5, which must be satisfied by June 30, 2015 or either party to the respective SPA may terminate its SPA. Under the 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 cargoes 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 the specified Train.

In aggregate, the fixed fee portion to be paid by these customers is approximately $2.3 billion annually for Trains 1 through 4, and $2.9 billion annually if we make a positive final investment decision with respect to Train 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 amended and restated SPA with us to purchase, at Cheniere Marketing’s option, any LNG produced by us in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

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Natural Gas Transportation and Supply

For our natural gas feedstock transportation requirements, we have entered into transportation precedent agreements to secure firm pipeline transportation capacity with CTPL, a wholly owned subsidiary of Cheniere Partners, and third-party pipeline companies. We have also entered into enabling agreements and long-term natural gas purchase agreements with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of December 31, 2014, we have secured up to approximately 2,162,000,000 MMBtu of natural gas feedstock through long-term natural gas purchase agreements.

Construction

Trains 1 through 4 are being designed, constructed and commissioned by Bechtel Oil, Gas, and Chemicals, Inc. (“Bechtel”). 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)”) and Trains 3 and 4 (the “EPC Contract (Trains 3 and 4)”) under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause us to enter into a change order, or we agree with Bechtel to a change order.

The total contract price of the EPC Contract (Trains 1 and 2) and the total contract price of the EPC Contract (Trains 3 and 4) are approximately $4.1 billion and $3.8 billion, respectively, reflecting amounts incurred under change orders through December 31, 2014. Total expected capital costs for Trains 1 through 4 are estimated to be between $9.0 billion and $10.0 billion before financing costs and between $12.0 billion and $13.0 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

Final Investment Decision on Train 5 and Train 6

We will contemplate making a final investment decision to commence construction of Train 5 and Train 6 of the Liquefaction Project based upon, among other things, entering into an EPC contract, entering into acceptable commercial arrangements, receiving regulatory authorizations and obtaining adequate financing to construct the Trains.

Terminal Use Agreement

In July 2012, Cheniere Energy Investments, LLC (“Cheniere Investments”), a wholly owned subsidiary of Cheniere Partners, assigned to us a TUA with Sabine Pass LNG to provide berthing for LNG vessels and for the unloading, loading, storage and regasification of LNG, which will provide us access to additional facilities needed for us to deliver LNG to our SPA customers. We have reserved approximately 2.0 Bcf/d of regasification capacity, and we are obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year, continuing until at least 20 years after we deliver our first commercial cargo at the Liquefaction Project. Sabine Pass LNG has no obligation to provide us with certain services such as (i) harbor, mooring and escort services for LNG vessels, including the provision of tugboats, (ii) the transportation of natural gas downstream from the Sabine Pass LNG terminal or the construction of any pipelines to provide such transportation or (iii) the marketing of natural gas. We also entered into a terminal use rights assignment and agreement (“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 Sabine Pass LNG.  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.

Capital Resources

We currently expect that our capital resources requirements with respect to Trains 1 through 4 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, unfunded commitments under the 2013 Liquefaction Credit Facilities and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 4 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 late 2015, when Train 1 is anticipated to achieve initial LNG production.

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Senior Secured Notes

As of December 31, 2014, we had four 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 6.250% Senior Secured Notes due 2022 (the “2022 Senior Notes”; collectively with the 2021 Senior Notes, the 2023 Senior Notes and the 2024 Senior Notes, the “Senior Notes”);

• $1.5 billion of the 2023 Senior Notes; and

• $2.0 billion of the 2024 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 November 1, 2020, with respect to the 2021 Senior Notes; December 15, 2021, with respect to the 2022 Senior Notes; January 15, 2023, with respect to the 2023 Senior Notes; or February 15, 2024, with respect to the 2024 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, plus accrued and unpaid interest, if any, to the date of redemption. We may also at any time on or after November 1, 2020, with respect to the 2021 Senior Notes; December 15, 2021, with respect to the 2022 Senior Notes; January 15, 2023, with respect to the 2023 Senior Notes; or February 15, 2024, with respect to the 2024 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 common indenture governing the Senior Notes, 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 and a debt service coverage ratio test of 1.25:1.00 is satisfied.

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 2013 Liquefaction Credit Facilities and the Senior LC Agreement described below.

2013 Liquefaction Credit Facilities

In May 2013, we entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 Liquefaction Credit Facilities”). In conjunction with our issuance in May 2014 of the 2024 Senior Notes and the additional issuance of the 2023 Senior Notes (the “Additional 2023 Senior Notes”), in an aggregate principal amount of $2.5 billion before premium, we terminated approximately $2.1 billion of commitments under the 2013 Liquefaction Credit Facilities. As a result, as of December 31, 2014, we have available commitments aggregating $2.7 billion under the 2013 Liquefaction Credit Facilities, which will be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Liquefaction Project. The principal of the loans made under the 2013 Liquefaction Credit Facilities must be repaid in quarterly installments, commencing with the earlier of the last day of the first full calendar quarter after the Train 4 completion date, as defined in the 2013 Liquefaction Credit Facilities, or September 30, 2018. Loans under the 2013 Liquefaction Credit Facilities bear interest at a variable rate per annum equal to, at our election, the London Interbank Offered Rate (“LIBOR”) or the base rate, plus the applicable margin. The applicable margins for LIBOR loans range from 2.3% to 3.0% prior to the completion of Train 4 and from 2.3% to 3.25% after such completion, depending on the applicable 2013 Liquefaction Credit Facility. The 2013 Liquefaction Credit Facilities also require us to pay a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of undrawn commitments. Interest on LIBOR loans and the commitment fees are due and payable at the end of each LIBOR period and quarterly, respectively.

Under the terms of the 2013 Liquefaction Credit Facilities, we are required to hedge not less than 75% 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.

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2012 Liquefaction Credit Facility

In July 2012, we entered into a construction/term loan facility in an amount up to $3.6 billion (the “2012 Liquefaction Credit Facility”), which was available to us in four tranches solely to fund the Liquefaction Project costs for Trains 1 and 2, the related debt service reserve account up to an amount equal to six months of scheduled debt service and the return of equity and affiliate subordinated debt funding to Cheniere or its affiliates up to an amount that would result in senior debt being no more than 65% of Cheniere Partners’ total capitalization. Borrowings under the 2012 Liquefaction Credit Facility were based on LIBOR plus 3.50% during construction and 3.75% during operations. We were also required to pay commitment fees on the undrawn amount. The 2012 Liquefaction Credit Facility was amended and restated with the 2013 Liquefaction Credit Facilities and $100.0 million of outstanding borrowings under the 2012 Liquefaction Credit Facility were repaid in full.

Senior LC Agreement

In April 2014, we entered into the Senior LC Agreement that we use for the issuance of letters of credit for certain working capital requirements related to the Liquefaction Project.  We pay (a) a commitment fee in an amount equal to an annual rate of 0.75% of an amount equal to the unissued portion of letters of credit available pursuant to the Senior LC Agreement and (b) a letter of credit fee equal to an annual rate of 2.5% of the undrawn portion of all letters of credit issued under the Senior LC Agreement. If draws are made upon any letters of credit issued under the Senior LC Agreement, the amount of the draw will be deemed a loan issued to us.  We are required to pay the full amount of this loan on or prior to the business day immediately succeeding the deemed issuance of the loan.  These loans bear interest at a rate of 2.0% plus the base rate as defined in the Senior LC Agreement. 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 Senior LC Agreement.

Sources and Uses of Cash

The following table summarizes (in thousands) the sources and uses of our cash and cash equivalents for the years ended December 31, 2014, 2013 and 2012. 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,
	2014			2013			2012
Sources of cash and cash equivalents
Proceeds from issuances of long-term debt	$	2,584,500		$	4,112,500		$	100,000
Use of restricted cash and cash equivalents for the acquisition of property, plant and equipment	2,587,565			3,092,025			1,114,742
Contributions from Cheniere Partners	11,734			338,276			1,623,849
Total sources of cash and cash equivalents	5,183,799			7,542,801			2,838,591
Uses of cash and cash equivalents
Investment in restricted cash and cash equivalents	(2,316,547		)	(4,041,372		)	(1,466,958		)
Property, plant and equipment, net	(2,548,855		)	(3,082,195		)	(1,113,999		)
Repayments of long-term debt	(177,000		)	(100,000		)	—
Debt issuance and deferred financing costs	(102,687		)	(309,404		)	(212,412		)
Other	(38,710		)	(9,830		)	(45,222		)
Total uses of cash and cash equivalents	(5,183,799		)	(7,542,801		)	(2,838,591		)
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 Long-Term Debt, Repayment of Long-Term Debt and Debt Issuance and Deferred Financing Costs

In May 2014, we issued the 2024 Senior Notes and the Additional 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 this offering in May 2014. During the year ended December 31, 2014, we repaid $177.0 million of borrowings under the 2013 Liquefaction Credit Facilities upon the issuance of the Additional 2023 Senior Notes and the 2024 Senior Notes.

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In February 2013 and April 2013, we issued an aggregate principal amount of $2.0 billion, before premium, of the 2021 Senior Notes. In April 2013, we also issued $1.0 billion of the 2023 Senior Notes. In November 2013, we issued $1.0 billion of 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 Liquefaction 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 Liquefaction Credit Facilities and the senior notes issued by us during the year.

In July 2012, we entered into the $3.6 billion 2012 Liquefaction Credit Facility with a syndicate of lenders. The 2012 Liquefaction Credit Facility was intended to be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 and 2 of the Liquefaction Project. Debt issuance and deferred financing costs in the year ended December 31, 2012 resulted from amounts paid by us upon the closing of the 2012 Liquefaction Credit Facility.

Uses of Restricted Cash and Cash Equivalents for the Acquisition of Property, Plant and Equipment and Property, Plant and Equipment

During the years ended December 31, 2014, 2013 and 2012, we used $2,587.6 million, $3,092.0 million and $1,114.7 million, respectively, of restricted cash and cash equivalents for investing activities to primarily fund $2,548.9 million, $3,082.2 million and $1,114.0 million, respectively, of construction costs for Trains 1 through 4 of the Liquefaction Project.  Trains 1 and 2 and Trains 3 and 4 of the Liquefaction Project satisfied the criteria for capitalization in June 2012 and May 2013, respectively. Accordingly, costs associated with the construction of Trains 1 through 4 of the Liquefaction Project have been recorded as construction-in-process since those dates.

Contributions from Cheniere Partners

During the years ended December 31, 2014, 2013 and 2012, we received equity contributions from Cheniere Partners in amounts totaling $11.7 million, $338.3 million and $1,623.8 million, respectively. The decrease in equity contributions is a result of utilizing our borrowings instead of equity contributions from Cheniere Partners to finance our capital resource requirements in the years ended December 31, 2014 and 2013.

Investment in Restricted Cash and Cash Equivalents

In the year ended December 31, 2014, we invested $2,316.5 million in restricted cash and cash equivalents. This investment in restricted cash and cash equivalents is primarily related to the net proceeds from the 2024 Senior Notes and the Additional 2023 Senior Notes issued in May 2014. In the year ended December 31, 2013, we invested $4,041.4 million in restricted cash and cash equivalents. This investment in restricted cash and cash equivalents is primarily related to the net proceeds from the 2021 Senior Notes, 2022 Senior Notes and 2023 Senior Notes issued in 2013 and from contributions from Cheniere Partners. In the year ended December 31, 2012, we invested $1,467.0 million in restricted cash and cash equivalents. This investment in restricted cash and cash equivalents is primarily related to the equity contributions received from Cheniere Partners.

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Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2014 (in thousands):

	Payments Due for Years Ended December 31,
	Total		2015		2016 - 2017		2018 - 2019		Thereafter
Construction and purchase obligations (1)	$	1,935,067	$	1,143,399	$	791,668	$	—	$	—
Long-term debt (2)	6,500,000		—		—		—		6,500,000
Interest Payments (2)	3,095,442		408,054		816,109		815,927		1,055,352
Operating lease obligations (3)	57,698		908		1,644		1,540		53,606
Service contracts (4)	5,111,887		4,125		249,500		501,842		4,356,420
Total	$	16,700,094	$	1,556,486	$	1,858,921	$	1,319,309	$	11,965,378

(1) Construction and purchase obligations primarily relate to the EPC Contracts. A discussion of these obligations can be found in Note 10—Commitments and Contingencies of our Notes to Financial Statements.

(2) Based on the total debt balance, commitment fees on undrawn credit facilities, scheduled maturities and interest rates in effect at December 31, 2014. Please read Note 7—Long-Term Debt of our Notes to Financial Statements.

(3) Operating lease obligations primarily relate to land site leases for our Liquefaction Project. A discussion of these obligations can be found in Note 10—Commitments and Contingencies and Note 8—Related Party Transactions of our Notes to Financial Statements.

(4) Service contracts primarily relate to services agreements and a TUA with Sabine Pass LNG. Obligations arising through intercompany service agreements have not been included in this total. A discussion of these obligations can be found in Note 10—Commitments and Contingencies and Note 8—Related Party Transactions of our Notes to Financial Statements.

Results of Operations

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 $201.8 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, 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 Liquefaction 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 Liquefaction 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 Liquefaction Credit Facility in April 2013 and the 2013 Liquefaction Credit Facilities in November 2013.

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2013 vs. 2012

Our net loss was $194.5 million in 2013 compared to a net loss of $85.2 million in 2012. The increase in net loss was primarily a result of loss on the early extinguishment of debt, increased general and administrative expenses (including affiliate expense), increased terminal use agreement maintenance expense and increased interest expense partially offset by increased derivative gain and decreased development expense (including affiliate expense).

Loss on early extinguishment of debt increased $131.6 million in 2013 as compared to 2012 as a result of issuances of the Senior Notes that resulted in the termination of a portion of the commitments under the 2012 Liquefaction Credit Facility and the 2013 Liquefaction Credit Facilities. Our general and administrative expense (including affiliate expense) increased $61.1 million in 2013 as compared to 2012 primarily as a result of increased costs incurred to manage the construction of Trains 1 through 4 of the Liquefaction Project, which resulted from a management services agreement with a wholly owned subsidiary of Cheniere in which we are required to pay a wholly owned subsidiary of Cheniere a monthly fee based upon the capital expenditures incurred in the previous month for the Liquefaction Project. Terminal use agreement maintenance expense increased $16.6 million in 2013 as compared to 2012 as a result of our proportionate share of the costs incurred in order for the Sabine Pass LNG terminal to maintain a minimum quantity of inventory, which we are required to reimburse pursuant to our TUA with Sabine Pass LNG. We anticipate continuing to incur a similar amount of terminal use agreement maintenance expense until minimum inventory quantities are maintained, which we expect to occur in 2015. Interest expense increased $10.7 million in 2013 as compared to 2012 as a result of the increase in our indebtedness outstanding. Derivative gain increased $82.6 million in 2013 as compared to 2012 primarily as a result of the change in fair value of our interest rate derivatives to hedge the exposure to volatility in a portion of the floating rate interest payments under the 2013 Liquefaction Credit Facilities. Development expense (including affiliate expense) decreased $27.4 million in 2013 as compared to 2012 primarily as a result of Trains 1 and 2 satisfying the criteria for capitalization in June 2012 and Trains 3 and 4 of the Liquefaction Project satisfying the criteria for capitalization in May 2013.

Off-Balance Sheet Arrangements

As of December 31, 2014, we had no “off-balance sheet arrangements” that may have a current or future material effect on our financial position or results of operations.

Summary of Critical Accounting Estimates

The preparation of Financial Statements in conformity with generally accepted accounting principles in the United States (“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 cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, accounts payable and 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.

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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 is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may be greater than its future net undiscounted cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount 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

In May 2014, the Financial Accounting Standards Board (“FASB”) amended its guidance on revenue recognition. The core principle of this amendment is that an entity should 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 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. This guidance can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact of the provisions of this guidance on our financial position, results of operations and cash flows.

In June 2014, 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, results of operations or cash flows other than the removal of inception-to-date information about income statement line items, cash flows and equity transactions.

In August 2014, the FASB issued authoritative guidance that 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. This guidance is effective for annual reporting periods ending after December 15, 2016, and for annual periods and interim periods thereafter, with earlier adoption permitted. The adoption of this guidance is not expected to have an impact on our financial position, results of operations or cash flows.

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ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Commodity Price Risk

We have entered into certain commodity derivative instruments to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory (“LNG Inventory Derivatives”). We use one-day value at risk (“VaR”) with a 95% confidence interval and other methodologies for market risk measurement and control purposes of our LNG Inventory Derivatives. The VaR is calculated using the Monte Carlo simulation method. The VaR related to our LNG Inventory Derivatives was $26,000 as of December 31, 2014.

We have entered into certain commodity derivative instruments consisting of natural gas purchase agreements to secure natural gas feedstock for the Liquefaction Project (“Term Gas Supply Derivatives”). In order to test the sensitivity of the fair value of the Term Gas Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the Henry Hub price for natural gas. As of December 31, 2014, we estimated the fair value of our Term Gas Supply Derivatives to be $0.3 million. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would have resulted in a change in the fair value of the Term Gas Supply Derivatives of $0.4 million as of December 31, 2014.

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 the 2013 Liquefaction 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 the Interest Rate Derivatives of $16.5 million as of December 31, 2014.

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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	33
Report of Independent Registered Public Accounting Firm—KPMG LLP	34
Report of Independent Registered Public Accounting Firm—Ernst & Young LLP	35
Balance Sheets	36
Statements of Operations	37
Statements of Comprehensive Loss	38
Statements of Member’s Equity (Deficit)	39
Statements of Cash Flows	40
Notes to Financial Statements	41
Supplemental Information to Financial Statements—Quarterly Financial Data	57

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MANAGEMENT’S REPORT TO THE PARTNERS 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 (1992) 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, 2014, based on criteria in Internal Control—Integrated Framework (1992) 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 Cheniere’s Chief 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/ Charif Souki	By:	/s/ Michael J. Wortley
	Charif Souki		Michael J. Wortley
	Chief Executive Officer		Chief Financial Officer
	(Principal Executive Officer)		(Principal Financial Officer)

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Member

Sabine Pass Liquefaction, LLC:

We have audited the accompanying balance sheet of Sabine Pass Liquefaction, LLC (the Company) as of December 31, 2014, and the related statements of operations, comprehensive loss, member’s equity, and cash flows for the year then ended. 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. 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 audit provides 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, 2014, and the results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

/s/    KPMG LLP

KPMG LLP

Houston, Texas

February 19, 2015

34

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Member

Sabine Pass Liquefaction, LLC

We have audited the accompanying balance sheet of Sabine Pass Liquefaction, LLC (a development stage limited liability company) as of December 31, 2013, and the related statements of operations, comprehensive loss, member's equity (deficit), and cash flows for each of the two years in the period 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 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. 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 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 at December 31, 2013, and the results of its operations and its cash flows for each of the two years in the period 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

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SABINE PASS LIQUEFACTION, LLC

BALANCE SHEETS

(in thousands)

	December 31,
	2014		2013
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Restricted cash and cash equivalents	155,810		192,144
Accounts receivable—affiliate	2,750		1,167
Advances to affiliate	23,969		9,430
Prepaid expenses and other	3,541		4,390
Other—affiliate	153		121
Total current assets	186,223		207,252
Non-current restricted cash and cash equivalents	457,053		867,590
Property, plant and equipment, net	6,962,395		4,412,580
Debt issuance costs, net	228,913		296,040
Non-current derivative assets	11,744		98,123
Other non-current assets	99,417		60,387
Total assets	$	7,945,745	$	5,941,972
LIABILITIES AND MEMBER’S EQUITY
Current liabilities
Accounts payable	$	5,974	$	8,067
Accrued liabilities	113,538		144,575
Due to affiliates	13,051		26,019
Derivative liabilities	23,247		13,484
Total current liabilities	155,810		192,145
Long-term debt, net	6,517,266		4,111,562
Non-current derivative liabilities	268		—
Commitments and contingencies
Member’s equity	1,272,401		1,638,265
Total liabilities and member’s equity	$	7,945,745	$	5,941,972

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

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SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2014			2013			2012
Revenues	$	—		$	—		$	—
Expenses
Development expense	9,319			11,540			37,341
Development expense—affiliate	1,153			1,392			2,955
General and administrative expense	5,305			3,305			1,359
General and administrative expense—affiliate	71,065			93,064			33,951
Terminal use agreement maintenance expense	25,677			26,228			10,058
Terminal use agreement maintenance expense—affiliate	387			394			—
Depreciation expense	967			213			119
Operating and maintenance expense	6,071			—			—
Operating and maintenance expense—affiliate	95			—			—
Total expenses	120,039			136,136			85,783
Loss from operations	(120,039		)	(136,136		)	(85,783		)
Other income (expense)
Interest expense, net	(23,909		)	(10,796		)	(139		)
Loss on early extinguishment of debt	(114,335		)	(131,576		)	—
Derivative gain (loss), net	(118,541		)	83,266			679
Other income (expense)	(29		)	752			86
Total other income (expense)	(256,814		)	(58,354		)	626
Net loss	$	(376,853	)	$	(194,490	)	$	(85,157	)

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

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SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)

	Year Ended December 31,
		2014			2013			2012
Net loss		$	(376,853	)	$	(194,490	)	$	(85,157	)
Other comprehensive income (loss)
Loss on settlements of interest rate cash flow hedges retained in other comprehensive income		—			(30		)	(136		)
Change in fair value of interest rate cash flow hedges		—			21,297			(27,104		)
Losses reclassified into earnings as a result of discontinuance of cash flow hedge accounting		—			5,973			—
Total other comprehensive income (loss)		—			27,240			(27,240		)
Comprehensive loss		$	(376,853	)	$	(167,250	)	$	(112,397	)

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

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SABINE PASS LIQUEFACTION, LLC

STATEMENT OF MEMBER’S EQUITY (DEFICIT)

(in thousands)

	Sabine Pass LNG-LP, LLC			Accumulated Other Comprehensive Income (Loss)			Total Member’s Equity (Deficit)
Balance at December 31, 2011	$	(46,380	)	$	—		$	(46,380	)
Contributions from Cheniere Partners	1,623,849			—			1,623,849
Non-cash contributions from Cheniere Partners	2,167			—			2,167
Interest rate cash flow hedges	—			(27,240		)	(27,240		)
Net loss	(85,157		)	—			(85,157		)
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
Contributions from Cheniere Partners	11,734			—			11,734
Non-cash contributions to limited partner	(745		)	—			(745		)
Net loss	(376,853		)	—			(376,853		)
Balance at December 31, 2014	$	1,272,401		$	—		$	1,272,401

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

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SABINE PASS LIQUEFACTION, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2014			2013			2012
Cash flows from operating activities
Net loss	$	(376,853	)	$	(194,490	)	$	(85,157	)
Adjustments to reconcile net loss to net cash used in operating activities:
Use of restricted cash and cash equivalents for certain operating activities	175,853			161,065			80,764
Depreciation	967			2,917			119
Non-cash terminal use agreement maintenance expense	24,461			26,731			9,612
Total (gains) losses on derivatives, net	118,199			(84,299		)	(679		)
Net cash from settlement of derivative instruments	(22,093		)	632			—
Loss on extinguishment of debt	114,335			131,576			—
Changes in operating assets and liabilities:
LNG inventory	(22,963		)	—			—
Accounts payable and accrued liabilities	9,234			(167		)	(1,781		)
Due to affiliates	(2,373		)	1,665			11,545
Advances to affiliate	(14,539		)	(5,017		)	(4,414		)
Other, net	(2,644		)	(39,446		)	(10,009		)
Other, net—affiliate	(1,584		)	(1,167		)	—
Net cash provided by (used in) operating activities	—			—			—
Cash flows from investing activities
Property, plant and equipment, net	(2,548,855		)	(3,082,195		)	(1,113,999		)
Use of restricted cash and cash equivalents for the acquisition of property, plant and equipment	2,587,565			3,092,025			1,114,742
Other	(38,710		)	(9,830		)	(743		)
Net cash provided by (used in) investing activities	—			—			—
Cash flows from financing activities
Proceeds from issuances of long-term debt	2,584,500			4,112,500			100,000
Repayments of long-term debt	(177,000		)	(100,000		)	—
Contributions from Cheniere Partners	11,734			338,276			1,623,849
Investment in restricted cash and cash equivalents	(2,316,547		)	(4,041,372		)	(1,466,958		)
Debt issuance and deferred financing costs	(102,687		)	(309,404		)	(212,412		)
Advances—affiliate	—			—			(44,479		)
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.

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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 Energy Partners, L.P. (“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 (the “Sabine Pass LNG terminal”) adjacent to the existing regasification facilities owned and operated by Sabine Pass LNG, L.P. (“Sabine Pass LNG”). We are a Houston-based company with one member, Sabine Pass LNG-LP, LLC, an indirect wholly owned subsidiary of Cheniere Partners. We and Sabine Pass LNG are each indirect wholly owned subsidiaries of Cheniere Energy Investments, LLC (“Cheniere Investments”), which is a wholly owned subsidiary of Cheniere Partners. Cheniere Partners is a publicly traded limited partnership (NYSE MKT: CQP) formed in November 2006 and is 55.9% owned subsidiary of Cheniere Energy Partners LP Holdings, LLC, which is in turn an 80.1% owned subsidiary of Cheniere Energy, Inc. (“Cheniere”), a Houston-based energy company primarily engaged in LNG-related businesses.

Our Liquefaction Project is being developed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. The Sabine Pass LNG terminal is located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast and includes 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 plan to construct up to six Trains, which are in various stages of development. Each train is expected to have nominal production capacity of approximately 4.5 mtpa of LNG.

In June 2014, the Financial Accounting Standards Board (“FASB”) amended its guidance on development stage entities. The amendment removed all incremental financial reporting requirements from generally accepted accounting principles in the United States (“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, results of operations or cash flows other than the removal of inception-to-date information about income statement line items, cash flows and equity transactions.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Company,” or “Sabine Pass Liquefaction” are intended to refer to Sabine Pass Liquefaction.

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, results of operations or cash flows.

Use of Estimates

The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, 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.

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SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

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

Recurring fair-value measurements are performed for commodity derivatives and interest-rate derivatives as disclosed in Note 5—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, 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, 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 7—Long-Term 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 and Cash Equivalents

Restricted cash and cash equivalents consist 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 and cash equivalents 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 as “investments in (uses of) restricted 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 and cash equivalents as they relate to the changes to assets and liabilities in our Balance Sheets. Restricted cash and cash equivalents are 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.

LNG Inventory

LNG inventory is recorded at cost and is subject to lower of cost or market (“LCM”) adjustments at the end of each period. LNG inventory cost is determined using the average cost method. Terminal use agreement maintenance expense—affiliate represents the amount recorded related to the reimbursement to Sabine Pass LNG 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: (i) regulatory approval has been received, (ii) financing for the Train is available and (iii) 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 intangible LNG 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.

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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. In performing this test, an undiscounted cash flow analysis is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. If the sum of the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value.  We have recorded no impairments related to property, plant and equipment for 2014, 2013 and 2012.

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 the balance sheet 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, 2014 and 2013.

From time to time we have elected cash flow hedge accounting for derivatives that we use 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 is effective, are recognized in accumulated other comprehensive loss on our Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive loss into interest expense in our Statements of Operations as the hedged item is recognized. Any change in the fair value resulting from ineffectiveness is recognized immediately as derivative gain (loss) on our Statements of Operations. We use regression analysis to determine whether we expect 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 have been effective. We perform these effectiveness tests prior to designation for all new hedges and on a quarterly basis for all existing hedges. We calculate the actual amount of ineffectiveness on our cash flow hedges using the “dollar offset” method, which compares changes in the expected cash flows of the hedged transaction to changes in the value of expected cash flows from the hedge. We discontinue hedge accounting when our effectiveness tests indicate that a derivative is no longer highly effective as a hedge; when the derivative expires or is sold, terminated or exercised; when the hedged item matures, is sold or repaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but continue to hold the derivative, prospective changes in fair value of the derivative instrument are recorded in income. Once we conclude that the hedged forecasted transaction becomes probable of not occurring, the amount remaining in accumulated other comprehensive loss pertaining to the previously designated derivatives is reclassified out of accumulated other comprehensive loss and into income.

See Note 5—Derivative Instruments of our Notes to Financial Statements 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.

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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 and not netted within the derivative fair value. 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.

Long-Term Debt

Our debt consists of 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, 2014, the tax basis of our assets and liabilities was $303.9 million more than the reported amounts of our assets and liabilities.

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SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

Pursuant to the indentures governing our long-term debt, we are permitted to make distributions (“Tax Distributions”) for any fiscal year or portion thereof in which we are a limited partnership, disregarded entity or other substantially similar pass-through entity for federal and state income tax purposes. The Tax Distributions are equal to the tax that we would owe if we were a corporation subject to federal and state income tax that filed separate federal and state income tax returns, excluding the amounts covered by the state tax sharing agreement discussed immediately below. 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.

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 computed 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 3—RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents consist 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.

In July 2012, we entered into a construction/term loan facility in an amount up to $3.6 billion (the “2012 Liquefaction Credit Facility”). During 2013, we entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 Liquefaction Credit Facilities”), which amended and restated the 2012 Liquefaction Credit Facility. See Note 7—Long-Term Debt. Under the terms and conditions of the 2012 Liquefaction Credit Facility we were required, and under the 2013 Liquefaction Credit Facilities we are required, to deposit all cash received into reserve accounts controlled by a collateral trustee. Therefore, all of our cash and cash equivalents are shown as restricted cash and cash equivalents 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 “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 collectively with the 2021 Senior Notes, the 2022 Senior Notes and the 2023 Senior Notes, the “Senior Notes”) and additional 2023 Senior Notes (the “Additional 2023 Senior Notes”) in an aggregate principal amount of $0.5 billion, before premium.

As of December 31, 2014 and 2013, we classified $155.8 million and $192.1 million, respectively, as current restricted cash and cash equivalents for the payment of current liabilities related to the Liquefaction Project and $457.1 million and $867.6 million, respectively, as non-current restricted cash and cash equivalents for future Liquefaction Project construction costs.

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SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

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

	December 31,
	2014			2013
LNG terminal costs
LNG terminal	$	12,821		$	98
LNG terminal construction-in-process	6,946,242			4,412,077
Accumulated depreciation	(260		)	—
Total LNG terminal costs, net	6,958,803			4,412,175
Fixed assets
Vehicles	854			309
Furniture and fixtures	1,154			10
Machinery and equipment	339			301
Other	2,292			125
Accumulated depreciation	(1,047		)	(340		)
Total fixed assets, net	3,592			405
Property, plant and equipment, net	$	6,962,395		$	4,412,580

NOTE 5—DERIVATIVE INSTRUMENTS

Cheniere Marketing, LLC (“Cheniere Marketing”), a wholly owned subsidiary of Cheniere, has entered into the following derivative instruments, on our behalf, that are reported at fair value:

• commodity derivatives to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory (“LNG Inventory Derivatives”);

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

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

The following table (in thousands) shows the fair value of our derivative assets and liabilities that are required to be measured at fair value on a recurring basis as of December 31, 2014 and 2013, which are classified as prepaid expenses and other, non-current derivative assets and derivative liabilities in our Balance Sheets.

	Fair Value Measurements as of
	December 31, 2014										December 31, 2013
	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
LNG Inventory Derivatives asset (liability)	$	—	$	1,071		$	—	$	1,071		$	—	$	(156	)	$	—	$	(156	)
Term Gas Supply Derivatives asset	—		—			342		342			—		—			—		—
Interest Rate Derivatives asset (liability)	—		(12,036		)	—		(12,036		)	—		84,639			—		84,639

The estimated fair values of our LNG Inventory 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.

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SABINE PASS LIQUEFACTION, LLC

NOTES TO FINANCIAL STATEMENTS—CONTINUED

The fair value of our Term Gas 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 Term Gas Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of the Term Gas 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 Term Gas Supply Derivative contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, 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, 2014, the majority of our Term Gas Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow and our internal fair value models were based on a market price that equated to our own contractual pricing due to the inactive and unobservable market as well as the 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 the Term Gas 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. We estimated the fair value of our Term Gas Supply Derivatives to be $0.3 million as of December 31, 2014.

There were no transfers into or out of Level 3 for the years ended December 31, 2014 and 2013. As all of our Term Gas 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 (in thousands, except natural gas basis spread) includes quantitative information for the unobservable inputs as of December 31, 2014:

	Net Fair Value Asset	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Term Gas Supply Derivatives	$342	Basis Spread plus Liquid Location	Basis Spread	$ (0.350) - $0.035

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.

Commodity Derivatives

We recognize our commodity derivatives as either assets or liabilities and measure those instruments at fair value. The changes in the fair value of our commodity derivatives are reported in earnings.

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

		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2014			December 31, 2013
LNG Inventory Derivatives asset	Prepaid expenses and other	$	1,071		$	156
Term Gas Supply Derivatives asset	Prepaid expenses and other	76			—
Term Gas Supply Derivatives asset	Non-current derivative assets	586			—
Term Gas Supply Derivatives liability	Derivative liabilities	(53		)	—
Term Gas Supply Derivatives liability	Non-current derivative liabilities	(267		)	—

The following table (in thousands) shows the changes in the fair value and settlements of our Commodity Derivatives recorded on our Statements of Operations during the years ended December 31, 2014, 2013 and 2012:

		Year Ended December 31,
	Statement of Operation Location	2014		2013		2012
LNG Inventory Derivatives gain	Derivative gain (loss), net	$	860	$	476	$	—
Term Gas Supply Derivatives gain (1)	Operating and maintenance expense	342		—		—

(1)    There were no settlements during the reporting period.

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NOTES TO FINANCIAL STATEMENTS—CONTINUED

LNG Inventory Derivatives

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances where our LNG Inventory Derivatives are in an asset position. Our LNG Inventory 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 LNG Inventory Derivatives activities. We had a collateral call of $1.0 million and a collateral deposit of $0.2 million for such contracts, which have not been reflected in the derivative fair value tables but are included in prepaid expenses and other current assets in our Balance Sheets as of December 31, 2014 and 2013, respectively.

Term Gas Supply Derivatives

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 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 Term Gas Supply Derivatives as either assets or liabilities and measure those instruments at fair value.  Changes in the fair value of our Term Gas Supply Derivatives are reported in earnings.

As of December 31, 2014, the majority our Term Gas Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow and our internal fair value models were based on a market price that equated to our own contractual pricing due to the inactive and unobservable market as well as the conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. As of December 31, 2014, the forward notional natural gas buy position of our Term Gas Supply Derivatives was approximately 1,249.4 million MMBtu.

Interest Rate Derivatives

In August 2012 and June 2013, we entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2012 Liquefaction Credit Facility and the 2013 Liquefaction Credit Facilities, respectively. The Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2013 Liquefaction Credit Facilities.

We designated the Interest Rate Derivatives entered into in August 2012 as hedging instruments, which was required in order to qualify for cash flow hedge accounting. As a result of this cash flow hedge designation, we recognized the Interest Rate Derivatives entered into in August 2012 as an asset or liability at fair value and reflected changes in fair value through other comprehensive income in our Statements of Comprehensive Loss.

Any hedge ineffectiveness associated with the Interest Rate Derivatives entered into in August 2012 was recorded immediately as derivative gain (loss) in our Statements of Operations.  The realized gain (loss) on the Interest Rate Derivatives entered into in August 2012 was recorded as an (increase) decrease in interest expense on our Statements of Operations to the extent not capitalized as part of the Liquefaction Project. The effective portion of the gains or losses on our Interest Rate Derivatives entered into in August 2012 recorded in other comprehensive income would have been reclassified to earnings as interest payments on the 2012 Liquefaction Credit Facility impact earnings. In addition, amounts recorded in other comprehensive income are also reclassified into earnings if it becomes probable that the hedged forecasted transaction will not occur.

We did not elect to designate the Interest Rate Derivatives entered into in June 2013 as cash flow hedging instruments, and changes in fair value are recorded as derivative gain (loss) within our Statements of Operations.

During the first quarter of 2013, we determined that it was no longer probable that the forecasted variable interest payments on the 2012 Liquefaction Credit Facility would occur in the time period originally specified based on the continued development of our financing strategy for the Liquefaction Project, and, in particular, the Senior Notes described in Note 7—Long-Term Debt. As a result, all of the Interest Rate Derivatives entered into in August 2012 were no longer effective hedges, and the remaining portion of hedge relationships that were designated cash flow hedges as of December 31, 2012, were de-designated as of February 1, 2013. For de-designated cash flow hedges, changes in fair value prior to their de-designation date are recorded as other comprehensive income (loss) within our Balance Sheets, and changes in fair value subsequent to their de-designation date are recorded as derivative gain (loss) within our Statements of Operations.

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In June 2013, we concluded that the hedged forecasted transactions associated with the Interest Rate Derivatives entered into in connection with the 2012 Liquefaction Credit Facility had become probable of not occurring based on the issuances of the Senior Notes, the closing of the 2013 Liquefaction Credit Facilities, the additional Interest Rate Derivatives executed in June 2013, and our intention to continue to issue fixed rate debt to refinance the 2013 Liquefaction Credit Facilities. As a result, the amount remaining in accumulated other comprehensive income (“AOCI”) pertaining to the previously designated Interest Rate Derivatives was reclassified out of AOCI and into income. We have presented the changes in fair value and settlements subsequent to the reclassification date separate from interest expense as derivative gain (loss), net in our Statements of Operations.

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 termination of approximately $2.1 billion of commitments under the 2013 Liquefaction Credit Facilities as discussed in Note 7—Long-Term Debt.

At December 31, 2014, 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 - Not Designated	$20.0 million	$2.5 billion	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR

The following table (in thousands) shows the fair value of our Interest Rate Derivatives:

		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2014			December 31, 2013
Interest Rate Derivatives - Not Designated	Non-current derivative assets	$	11,158		$	98,123
Interest Rate Derivatives - Not Designated	Derivative liabilities	(23,194		)	(13,484		)

The following table (in thousands) details the effect of our Interest Rate Derivatives included in Other Comprehensive Income (“OCI”) and AOCI for the years ended December 31, 2014, 2013 and 2012:

	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
December 31, 2012
Interest Rate Derivatives - Designated	$	(21,290	)	$	—	$	—
Interest Rate Derivatives - De-designated	(5,814		)	—		—
Interest Rate Derivatives - Settlements	(136		)	—		—
December 31, 2013
Interest Rate Derivatives - Designated	21,297			—		5,807
Interest Rate Derivatives - Settlements	(30		)	—		166
December 31, 2014
Interest Rate Derivatives - Designated	—			—		—
Interest Rate Derivatives - De-designated	—			—		—
Interest Rate Derivatives - Settlements	—			—		—

The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives - Not Designated recorded in derivative gain (loss), net on our Statements of Operations during the years ended December 31, 2014, 2013 and 2012:

	Year Ended December 31,
	2014			2013		2012
Interest Rate Derivatives - Not Designated	$	(119,401	)	$	88,596	$	679

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Balance Sheet Presentation

Our commodity and interest rate derivatives are presented on a net basis on our Balance Sheets as described above. The following table (in thousands) shows the fair value 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			Gross Amounts Not Offset in the Balance Sheets
Offsetting Derivative Assets (Liabilities)										Derivative Instrument		Cash Collateral Received (Paid)		Net Amount
As of December 31, 2014:
LNG Inventory Derivatives	$	1,071		$	1,000		$	71		$	—	$	—	$	71
Term Gas Supply Derivatives	662			—			662			—		—		662
Term Gas Supply Derivatives	(320		)	—			(320		)	—		—		(320		)
Interest Rate Derivatives - Not Designated	11,158			—			11,158			—		—		11,158
Interest Rate Derivatives - Not Designated	(23,194		)	—			(23,194		)	—		—		(23,194		)
As of December 31, 2013:
LNG Inventory Derivatives	(156		)	(156		)	—			—		—		—
Interest Rate Derivatives - Not Designated	98,123			—			98,123			—		—		98,123
Interest Rate Derivatives - Not Designated	(13,484		)	—			(13,484		)	—		—		(13,484		)

NOTE 6—ACCRUED LIABILITIES

As of December 31, 2014 and 2013, accrued liabilities consisted of the following (in thousands):

	December 31,
	2014		2013
Interest expense and related debt fees	$	97,785	$	65,153
LNG liquefaction costs	15,753		79,422
Total accrued liabilities	$	113,538	$	144,575

NOTE 7—LONG-TERM DEBT

As of December 31, 2014 and 2013, our long-term debt consisted of the following (in thousands):

	December 31,
	2014		2013
Long-term debt
2021 Senior Notes	$	2,000,000	$	2,000,000
2022 Senior Notes	1,000,000		1,000,000
2023 Senior Notes	1,500,000		1,000,000
2024 Senior Notes	2,000,000		—
2013 Liquefaction Credit Facilities	—		100,000
Total long-term, debt	6,500,000		4,100,000
Long-term debt premium
2021 Senior Notes	10,177		11,562
2023 Senior Notes	7,089		—
Total long-term debt, net	$	6,517,266	$	4,111,562

For the years ended December 31, 2014, 2013 and 2012, we incurred $397.9 million, $241.3 million and $35.3 million of total interest cost, respectively, of which we capitalized and deferred $374.0 million, $227.9 million and $35.1 million, respectively, of interest cost, including amortization of debt issuance costs, related to the construction of Trains 1 through 4 of the Liquefaction Project.

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Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2014 (in thousands): 

	Payments Due for the Years Ended December 31,
	Total		2015		2016 to 2017		2018 to 2019		Thereafter
Debt:
2021 Senior Notes	$	2,000,000	$	—	$	—	$	—	$	2,000,000
2022 Senior Notes	1,000,000		—		—		—		1,000,000
2023 Senior Notes	1,500,000		—		—		—		1,500,000
2024 Senior Notes	2,000,000		—		—		—		2,000,000
Total Debt	$	6,500,000	$	—	$	—	$	—	$	6,500,000

Senior Notes

In February 2013 and April 2013, we issued an aggregate principal amount of $2.0 billion, before premium, of the 2021 Senior Notes. In April 2013 and May 2014, we issued an aggregate principal amount of $1.5 billion, before premium, of the 2023 Senior Notes. Borrowings under the 2021 Senior Notes and 2023 Senior Notes bear interest at a fixed rate of 5.625%. In November 2013, we issued an aggregate principal amount of $1.0 billion of the 2022 Senior Notes. Borrowings under the 2022 Senior Notes bear interest at a fixed rate of 6.25%. In May 2014, we issued an aggregate principal amount of $2.0 billion of the 2024 Senior Notes. Borrowings under the 2024 Senior Notes bear interest at a fixed rate of 5.75%. Interest on the Senior Notes is payable semi-annually in arrears.

The terms of the Senior Notes are governed by a common indenture (the “Indenture”). 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 or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of our restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, 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 our membership interests 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 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 November 1, 2020, with respect to the 2021 Senior Notes; December 15, 2021, with respect to the 2022 Senior Notes; January 15, 2023, with respect to the 2023 Senior Notes; or February 15, 2024, with respect to the 2024 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 on or after November 1, 2020, with respect to the 2021 Senior Notes; December 15, 2021, with respect to the 2022 Senior Notes; January 15, 2023, with respect to the 2023 Senior Notes; or February 15, 2024, with respect to the 2024 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.

2013 Liquefaction Credit Facilities

In May 2013, we entered into the 2013 Liquefaction Credit Facilities aggregating $5.9 billion. The 2013 Liquefaction Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation the first four Trains of the Liquefaction Project. The 2013 Liquefaction Credit Facilities will mature on the earlier of May 28, 2020 or the second anniversary of the completion date of the first four Trains of the Liquefaction Project, as defined in the 2013 Liquefaction Credit Facilities. Borrowings under the 2013 Liquefaction Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty, except for interest rate hedging and interest rate breakage costs. We made an initial $100.0 million borrowing under the 2013 Liquefaction Credit Facilities in June 2013 after meeting the required conditions precedent, and in May 2014, we repaid our borrowings under the 2013 Liquefaction Credit Facilities upon the issuance of the Additional 2023 Senior Notes and the 2024 Senior Notes. As of December 31, 2014 and 2013, we had $2.7 billion and $4.9 billion, respectively, of available commitments under the 2013 Liquefaction Credit Facilities.

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Borrowings under the 2013 Liquefaction Credit Facilities bear interest at a variable rate per annum equal to, at our election, the London Interbank Offered Rate (“LIBOR”) or the base rate, plus the applicable margin. The applicable margins for LIBOR loans range from 2.3% to 3.0% prior to the completion of Train 4 and from 2.3% to 3.25% after such completion, depending on the applicable 2013 Liquefaction Credit Facility. Interest on LIBOR loans is due and payable at the end of each LIBOR period. The 2013 Liquefaction Credit Facilities required us to pay certain up-front fees to the agents and lenders in the aggregate amount of approximately $144 million and provide for a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of the undrawn commitment due quarterly in arrears. Annual administrative fees must also be paid to the agent and the trustee. The principal of the loans made under the 2013 Liquefaction Credit Facilities must be repaid in quarterly installments, commencing with the earlier of the last day of the first full calendar quarter after the Train 4 completion date, as defined in the 2013 Liquefaction Credit Facilities, or September 30, 2018. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2013 Liquefaction Credit Facilities.

Under the terms and conditions of the 2013 Liquefaction Credit Facilities, all cash held by us is controlled by a collateral agent. These funds can only be released by the collateral agent upon satisfaction of certain terms and conditions related to the use of proceeds, and are classified as restricted on our Balance Sheets.

The 2013 Liquefaction Credit Facilities contain conditions precedent for any subsequent borrowings, as well as customary affirmative and negative covenants. Our obligations under the 2013 Liquefaction 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.

Under the terms of the 2013 Liquefaction Credit Facilities, we are required to hedge not less than 75% 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. See Note 5—Derivative Instruments.

In November 2013, in conjunction with our issuance of the 2022 Notes, we terminated approximately $885 million of commitments under the 2013 Liquefaction Credit Facilities. This termination resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2013 Liquefaction Credit Facilities of $43.3 million in November 2013.

In May 2014, in conjunction with our issuance of the 2024 Senior Notes and the Additional 2023 Senior Notes, we terminated approximately $2.1 billion of commitments under the 2013 Liquefaction Credit Facilities. This termination resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2013 Liquefaction Credit Facilities of $114.3 million in May 2014.

2012 Liquefaction Credit Facility

In July 2012, we entered into the 2012 Liquefaction Credit Facility with a syndicate of lenders. The 2012 Liquefaction Credit Facility was intended to be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 and 2 of the Liquefaction Project. Borrowings under the 2012 Liquefaction Credit Facility were based on LIBOR plus 3.50% during construction and LIBOR plus 3.75% during operations. We were also required to pay commitment fees on the undrawn amount. In May 2013, the 2012 Liquefaction Credit Facility was amended and restated with the 2013 Liquefaction Credit Facilities and $100.0 million of outstanding borrowings under the 2012 Liquefaction Credit Facility were repaid in full.

Under the terms of the 2012 Liquefaction Credit Facility, we were required to hedge not less than 75% 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. See Note 5—Derivative Instruments.

In conjunction with the issuance of the 2021 Senior Notes in February 2013 and the issuances of $500.0 million of additional 2021 Senior Notes and 2023 Senior Notes in April 2013, approximately $1.4 billion of commitments under the 2012 Liquefaction Credit Facility were terminated. The termination of these commitments in April 2013 and the amendment and restatement of the 2012 Liquefaction Credit Facility with the 2013 Liquefaction Credit Facilities in May 2013 resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2012 Liquefaction Credit Facility of $88.3 million during the year ended December 31, 2013.

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NOTES TO FINANCIAL STATEMENTS—CONTINUED

Sabine Pass Liquefaction LC Agreement

In April 2014, we entered into a $325.0 million senior letter of credit and reimbursement agreement (the “Senior LC Agreement”) that we use for the issuance of letters of credit for certain working capital requirements related to the Liquefaction Project. We pay (a) a commitment fee in an amount equal to an annual rate of 0.75% of an amount equal to the unissued portion of letters of credit available pursuant to the Senior LC Agreement and (b) a letter of credit fee equal to an annual rate of 2.5% of the undrawn portion of all letters of credit issued under the Senior LC Agreement. If draws are made upon any letters of credit issued under the Senior LC Agreement, the amount of the draw will be deemed a loan issued to us.  We are required to pay the full amount of this loan on or prior to the business day immediately succeeding the deemed issuance of the loan.  These loans bear interest at a rate of 2.0% plus the base rate as defined in the Senior LC Agreement. 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 Senior LC Agreement.

Fair Value Disclosures

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

	December 31, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2021 Senior Notes, net of premium (1)	$	2,010,177	$	1,985,050	$	2,011,562	$	1,961,273
2022 Senior Notes (1)	1,000,000		1,020,000		1,000,000		982,500
2023 Senior Notes, net of premium (1)	1,507,089		1,476,947		1,000,000		935,000
2024 Senior Notes (1)	2,000,000		1,970,000		—		—
2013 Liquefaction Credit Facilities (2)	—		—		100,000		100,000

(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, 2014 and 2013, as applicable.

(2) The Level 3 estimated fair value approximates the carrying amount because the interest rates are variable and reflective of market rates and we have the ability to call this debt at any time without penalty.

NOTE 8—RELATED PARTY TRANSACTIONS

Services Agreements

We recorded general and administrative expense—affiliate of $70.6 million, $92.6 million and $34.0 million during the years ended December 31, 2014, 2013 and 2012, 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 pursuant to which we receive all of the necessary services required to construct, operate and maintain the liquefaction facilities. Before the liquefaction facilities are 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 facilities are operational, the services include all necessary services required to operate and maintain the liquefaction facilities. Before the liquefaction facilities are 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. After substantial completion of each Train, for services performed while the liquefaction facilities are 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. Cheniere Investments provides the services required under the Liquefaction O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere.

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 facilities, excluding those matters provided

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NOTES TO FINANCIAL STATEMENTS—CONTINUED

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 facilities. We pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, we will pay a fixed monthly fee of $541,667 for services with respect to such Train.

Terminal Use Agreements

We have entered into a TUA with Sabine Pass LNG pursuant to which we have reserved approximately 2.0 Bcf/d of regasification capacity. See Note 10—Commitments and Contingencies for additional information regarding this TUA.

Cheniere Marketing SPA

Cheniere Marketing has entered into an amended and restated SPA with us (the “Cheniere Marketing SPA”) 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.

LNG Site Sublease Agreement

In June 2012, we entered into an agreement with Sabine Pass LNG to sublease a portion of its Sabine Pass LNG terminal site for the Liquefaction Project. See Note 9—Leases for additional information regarding this sublease agreement.

State Tax Sharing Agreement

In August 2012, we entered into a state tax sharing agreement with Cheniere. See Note 10—Commitments and Contingencies for additional information regarding this agreement.

Cooperation Agreement

We have entered into an agreement with Sabine Pass LNG to allow us certain rights to access the property and facilities that are owned by Sabine Pass LNG for the purpose of constructing, modifying and operating our Liquefaction Project. In consideration for access given to us, we have agreed to transfer title to Sabine Pass LNG of certain facilities, equipment and modifications. The term of this agreement is consistent with our TUA described above. As of December 31, 2014, we have conveyed $0.7 million of assets to Sabine Pass LNG under this agreement.

NOTE 9—LEASES

During the years ended December 31, 2014, 2013 and 2012, we recognized rental expense for all operating leases of $0.9 million, $0.9 million and $0.7 million, respectively.

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

Year ending December 31,	Lease Payments
2015	$	908
2016	874
2017	770
2018	770
2019	770
Thereafter (1)	53,606
Total	$	57,698

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

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LNG Site Leases

In November 2011, we entered into a land lease of 80.7 acres to be used as the laydown area during the construction of the Liquefaction Project. The lease has an initial term of 5 years, with options to renew for five1-year extensions with similar terms as the initial term.

In December 2011, we entered into a land lease of 80.6 acres to be used for the site of the Liquefaction Project. The lease has an initial term of 30 years, with options to renew for six10-year extensions with similar terms as the initial term. The annual lease payment is adjusted for inflation every 5 years based on a consumer price index, as defined in the lease agreement.

In June 2012, we entered into an agreement with Sabine Pass LNG to sublease a portion of its Sabine Pass LNG terminal site for the Liquefaction Project. The annual sublease payment is $0.5 million. The initial term of the sublease expires on December 31, 2034, with options to renew for five10-year extensions with similar terms as the initial term. The annual sublease payment is adjusted for inflation every 5 years based on a consumer price index, as defined in the sublease agreement. During the years ended December 31, 2014, 2013 and 2012, we recorded $0.5 million, $0.5 million and $0.3 million of sublease expense as general and administrative expense—affiliate on our Statements of Operations.

NOTE 10—COMMITMENTS AND CONTINGENCIES

Bechtel EPC Contract

We entered into lump sum turnkey EPC contracts for Trains 1 and 2 (the “EPC Contract (Trains 1 and 2)”) and Trains 3 and 4 (the “EPC Contract (Trains 3 and 4)”) with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) in November 2011 and December 2012, respectively.

The EPC Contract (Trains 1 and 2) provides that we will pay Bechtel a contract price of $3.9 billion, which is subject to adjustment by change order. We have the right to terminate the EPC Contract (Trains 1 and 2) for our convenience, in which case Bechtel will be paid (i) the portion of the contract price for the work performed, (ii) costs reasonably incurred by Bechtel on account of such termination and demobilization, and (iii) a lump sum of up to $30.0 million depending on the termination date.

The EPC Contract (Trains 3 and 4) provides for (i) the procurement, engineering, design, installation, training, commissioning and placing into service of Trains 3 and 4 of the Liquefaction Project and related facilities and (ii) certain modifications and improvements to Trains 1 and 2 and the Sabine Pass LNG terminal. The EPC Contract (Trains 3 and 4) provides that we will pay Bechtel a contract price of $3.8 billion, which is subject to adjustment by change order. We have the right to terminate the EPC Contract (Trains 3 and 4) for our convenience, in which case Bechtel will be paid (i) the portion of the contract price for the work performed, (ii) costs reasonably incurred by Bechtel on account of such termination and demobilization, and (iii) a lump sum of up to $30.0 million depending on the termination date.

LNG Sale and Purchase Agreements

We have entered into third-party SPAs with four customers which obligate us to purchase natural gas in sufficient quantities, liquefy the natural gas purchased, and deliver 834.0 million MMBtu per year of LNG to the customers’ vessels, subject to completion of construction of each of Trains 1 through 4 of the Liquefaction Project as specified in the customers’ SPAs. In addition, we have entered into third-party SPAs with two customers to purchase natural gas in sufficient quantities, liquefy the natural gas purchased, and deliver 196.0 million MMBtu per year of LNG to the customers’ vessels, subject to completion of regulatory approvals, securing adequate financing, reaching a positive final investment decision to construct the relevant infrastructure, and construction of Train 5 of the Liquefaction Project.

Terminal Use Agreements

We have entered into a TUA with Sabine Pass LNG 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 Sabine Pass LNG 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 Sabine Pass LNG also entered into a terminal use rights assignment and agreement

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NOTES TO FINANCIAL STATEMENTS—CONTINUED

(“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 Sabine Pass LNG.  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 (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at 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, 2014, 2013 and 2012, we recorded $26.7 million, $26.6 million and $10.1 million, respectively, as terminal use agreement maintenance expense (including affiliate) on our Statements of Operations related to this obligation.

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 Sabine Pass LNG. 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 Sabine Pass LNG continue to be made by Total to Sabine Pass LNG in accordance with its TUA.

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.

Services Agreements

We have entered into certain services agreements with affiliates. See Note 8—Related Party Transactions for information regarding such agreements.

Legal Proceedings

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2014, there were no threatened or pending legal matters that would have a material impact on our results of operations, financial position or cash flows.

NOTE 11—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2014		2013		2012
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliates)	$	117,442	$	163,830	$	99,680

56

SABINE PASS LIQUEFACTION, LLC

SUPPLEMENTAL INFORMATION TO FINANCIAL STATEMENTS

QUARTERLY FINANCIAL DATA

(unaudited)

Quarterly Financial Data—(in thousands)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2014:
Revenues	$	—		$	—		$	—		$	—
Loss from operations	(24,988		)	(38,640		)	(32,365		)	(24,046		)
Net loss	(59,840		)	(213,477		)	(43,559		)	(59,977		)
Year ended December 31, 2013:
Revenues	$	—		$	—		$	—		$	—
Loss from operations	(15,814		)	(39,756		)	(50,842		)	(29,724		)
Net loss	(33,861		)	(36,185		)	(73,036		)	(51,408		)

57

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

None.

ITEM 9A.     CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Securities Exchange Act of 1934 (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, 2014, 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 (i) 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 (ii) 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, 2014, 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, 2014, 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 approximately 29% of the outstanding equity interests of Cheniere Partners and has three representatives on the Board of Directors of Cheniere Partners’ general partner. Accordingly, Blackstone Group may be deemed an “affiliate” of Cheniere Partners, as that term is defined in Exchange Act Rule 12b-2. We have received notice from Blackstone that it may include in its Annual Report on Form 10-K for the fiscal year ended December 31, 2014 disclosures pursuant to ITRA regarding one of its portfolio companies that may be deemed to be an affiliate of Blackstone Group. Because of the broad definition of “affiliate” in Exchange Act Rule 12b-2, this portfolio company of Blackstone Group, through Blackstone Group’s ownership of Cheniere Partners, may also be deemed to be an affiliate of ours.

We have received notice from Blackstone Group that Travelport Limited (“Travelport”) has engaged in the following activities: as part of its global business in the travel industry, Travelport provides certain passenger travel-related GDS and airline IT services to Iran Air and airline IT services to Iran Air Tours. The gross revenues and net profits attributable to such activities by Travelport during the fiscal year ended December 31, 2014 have not been reported by Travelport. 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.

58

In the Form 10-Q reports of Cheniere Partners for the quarterly periods ended on March 31, 2014, June 30, 2014 and September 30, 2014, Cheniere Partners 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, 2014 and Ernst & Young LLP served as our independent auditor for the fiscal year ended December 31, 2013. The following table (in thousands) sets forth the fees paid to the respective independent auditors for professional services rendered for 2014 and 2013: 

	Fiscal 2014		Fiscal 2013
Audit Fees	$	980	$	1,284

Audit Fees—Audit fees for 2014 and 2013 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.

There were no audit-related, tax or other fees in 2014 and 2013.

Auditor Pre-Approval Policy and Procedures

Our member is not a public company and it is not listed on any stock exchange. As a result, it is not required to, and does not, have an independent audit committee, a financial expert or a majority of independent directors. Our member 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, 2014 and 2013.

59

SABINE PASS LIQUEFACTION, LLC

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	33
Report of Independent Registered Public Accounting Firm—KPMG LLP	34
Report of Independent Registered Public Accounting Firm—Ernst & Young LLP	35
Balance Sheets	36
Statements of Operations	37
Statements of Comprehensive Loss	38
Statements of Member’s Equity (Deficit)	39
Statements of Cash Flows	40
Notes to Financial Statements	41
Supplemental Information to Financial Statements—Quarterly Financial Data	57

(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 Sabine Pass Liquefaction, LLC’s Registration Statement on Form S-4 (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 Sabine Pass Liquefaction, LLC’s Registration Statement on Form S-4 (File No. 333-192373), filed on November 15, 2013)

60

Exhibit No.	Description
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, as trustee (Incorporated by reference to Exhibit 4.1 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on February 4, 2013)
4.2	Form of 5.625% Senior Secured Note due 2021 (Included as Exhibit A-1 to Exhibit 4.1 above)
4.3	First Supplemental Indenture, dated as of April 16, 2013, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1.1 to Cheniere Energy Partners, L.P.’s 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 under the Indenture (Incorporated by reference to Exhibit 4.1.2 to Cheniere Energy Partners, L.P.’s 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 under the Indenture (Incorporated by reference to Exhibit 4.1 to Cheniere Energy Partners, L.P.’s 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 under the Indenture (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on 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 under the Indenture (Incorporated by reference to Exhibit 4.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on May 22, 2014)
4.11	Form of 5.625% Senior Secured Note due 2023 (included as Exhibit A-1 to Exhibit 4.10 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 Energy Partners, L.P.’s 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 Energy Partners, L.P.’s 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 Energy Partners, L.P.’s 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 Energy Partners, L.P.’s 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 Energy Partners, L.P.’s 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 Energy Partners, L.P.’s 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 Energy Partners, L.P.’s 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 May 14, 2012, by and between Sabine Pass Liquefaction, LLC (Seller) and Cheniere Marketing, LLC (Buyer) (Incorporated by reference to Exhibit 10.7 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)

61

Exhibit No.	Description
10.9	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 Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on December 14, 2012)
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 Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on March 25, 2013)
10.11	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 Sabine Pass Liquefaction’s Current Report on Form 8-K (SEC File No. 333-192373), filed on August 11, 2014)
10.12	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 Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.13	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 Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.14	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 Energy Partners LP Holdings, LLC’s Registration Statement on Form S-1 (SEC File No. 333-191298), filed on December 2, 2013)
10.15	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 10.40 to Cheniere Energy Partners LP Holdings, LLC’s Registration Statement on Form S-1 (SEC File No. 333-191298), filed on November 15, 2013)
10.16	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 Energy Partners L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on August 3, 2012)
10.17	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 Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.18	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 Second 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 Energy Partners, L.P.’s Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 22, 2013)

62

Exhibit No.	Description
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-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 Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on May 3, 2013)
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-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 Cheniere Energy Partners LP Holdings, LLC’s Registration Statement on Form S-1 (SEC File No. 333-191298), filed on October 18, 2013)
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-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 Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 8, 2013)
10.22	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 Sabine Pass Liquefaction, LLC’s Registration Statement on Form S-4 (SEC File No. 333-192373), filed on January 28, 2014)
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-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 Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 1, 2014)
10.24	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 10.2 to the Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July 31, 2014)
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-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 Sabine Pass Liquefaction, LLC’s Registration on Form S-4 (SEC File No. 333-198358) filed on August 26, 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-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.)

63

Exhibit No.	Description
10.27	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 10.47 to Cheniere Energy Partners LP Holdings, LLC’s Registration Statement on Form S-1 (SEC File No. 333-191298), filed on October 18, 2013)
10.28	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 Line, 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 Cheniere Energy Partners LP Holdings, LLC’s Registration Statement on Form S-1 (SEC File No. 333-191298), filed on October 18, 2013)
10.29	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 (iv) 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 Cheniere Energy Partners LP Holdings, LLC’s Registration Statement on Form S-1 (SEC File No. 333-191298), filed on October 18, 2013)
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 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 Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 1, 2014)
10.31	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 Sabine Pass Liquefaction, LLC’s Registration on Form S-4 (SEC File No. 333-198358) filed on August 26, 2014)
10.32*	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.)
10.33	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 Sabine Pass LNG, L.P.’s Current Report on Form 8-K (SEC File No. 333-138916), filed on August 6, 2012)
10.34	Letter Agreement, dated May 28, 2013, by and between Sabine Pass Liquefaction, LLC and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to Sabine Pass LNG, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 138916), filed on August 2, 2013)
10.35	Amended and Restated Common Terms Agreement, dated as of May 28, 2013, among Sabine Pass Liquefaction, LLC, as borrower, the Secured Debt Holder Group Representatives, Secured Hedge Representatives and Secured Gas Hedge Representatives from time to time party thereto, and Société Générale, as the common security trustee and intercreditor agent (Incorporated by reference to Exhibit 10.5 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)

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Exhibit No.	Description
10.36	KEXIM Direct Facility Agreement, dated as of May 28, 2013, among Sabine Pass Liquefaction, LLC, as borrower, KEB NY Financial Corp., as the KEXIM Facility Agent, Société Générale, as the common security trustee and The Export-Import Bank of Korea, as the KEXIM Direct Facility Lender and as the Joint Lead Arranger (Incorporated by reference to Exhibit 10.2 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)
10.37	KEXIM Covered Facility Agreement, dated as of May 28, 2013, among Sabine Pass Liquefaction, LLC, as borrower, KEB NY Financial Corp., as the KEXIM Facility Agent, Société Générale, as the common security trustee, The Export-Import Bank of Korea and the other lenders from time to time party thereto (Incorporated by reference to Exhibit 10.3 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)
10.38	KSURE Covered Facility Agreement, dated as of May 28, 2013, among Sabine Pass Liquefaction, LLC, as borrower, The Korea Development Bank, New York Branch, as the KSURE Facility Agent, Société Générale, as the common security trustee, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.4 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)
10.39	Amended and Restated Credit Agreement (Term Loan A), dated as of May 28, 2013, among Sabine Pass Liquefaction, LLC, as borrower, Société Générale, as the commercial banks facility agent and common security trustee, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)
10.40	Senior Letter of Credit and Reimbursement Agreement, dated as of April 21, 2014, among Sabine Pass Liquefaction, LLC, as Borrower, The Bank of Nova Scotia, as Senior Issuing Bank and Senior LC Facility Administrative Agent, Société Générale, as Common Security Trustee, and the lenders named therein, as Senior LC Lenders (Incorporated by reference to Exhibit 10.1 to Sabine Pass Liquefaction, LLC’s Current Report on Form 8-K (SEC File No. 333-192373), filed on April 25, 2014)
10.41	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 Sabine Pass Liquefaction, LLC’s Registration Statement on Form S-4 (SEC File No. 333-192373), filed on November 15, 2013)
21.1	Subsidiaries of Sabine Pass Liquefaction, LLC (None)
31.1*	Certification by Chief Executive Officer required by Rule 13a-14(a) and Rule 15d-14(a) under the Exchange Act
31.2*	Certification by Chief Financial Officer required by Rule 13a-14(a) and Rule 15d-14(a) under the Exchange Act
32.1**	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith
**	Furnished herewith

65

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 19, 2015

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 19, 2015
R. Keith Teague
/s/ Michael J. Wortley	Manager and Chief Financial Officer (Principal Financial Officer)	February 19, 2015
Michael J. Wortley
/s/ Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 19, 2015
Leonard Travis
/s/ Sean T. Klimczak	Manager	February 19, 2015
Sean T. Klimczak

66