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EX-32.2 - EXHIBIT 32.2 - Sabine Pass Liquefaction, LLCspliq201310-kexhibit322.htm
EX-32.1 - EXHIBIT 32.1 - Sabine Pass Liquefaction, LLCspliq201310-kexhibit321.htm
EX-31.2 - EXHIBIT 31.2 - Sabine Pass Liquefaction, LLCspliq201310-kexhibit312.htm
EX-31.1 - EXHIBIT 31.1 - Sabine Pass Liquefaction, LLCspliq201310-kexhibit311.htm




 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
 
Commission File No. 333-192373 
Sabine Pass Liquefaction, LLC 
(Exact name of registrant as specified in its charter)

Delaware
 
27-3235920
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
700 Milam Street, Suite 800
 
 
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 ¨    No x
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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes ¨   No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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


 
 
 
 
Signatures

i




CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS


This annual report contains certain statements that are, or may be deemed to be, "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). 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 trains ("Trains"), or any 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 such 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 SPAs or other 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.


ii




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 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 an indirect 49.2% 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.

1




Our Liquefaction Project

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 capacity of up to 265,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. We are developing Trains 5 and 6 and commenced the regulatory approval process for these Trains in February 2013.

We have received authorization from the Federal Energy Regulatory Commission (the "FERC") to site, construct and operate Trains 1 through 4. We have also filed an application with the FERC for the approval to construct Trains 5 and 6. The U.S. Department of Energy (the "DOE") has granted us an order authorizing the export of up to the equivalent of 16 mtpa (approximately 803 Bcf/yr) of LNG to all nations with which trade is permitted for a 20-year term beginning on the earlier of the date of first export from Train 1 or August 7, 2017. The DOE further issued orders authorizing the export of an additional 503.3 Bcf/yr in total of domestically produced LNG from the Sabine Pass LNG terminal to free trade agreement ("FTA") countries providing for national treatment for trade in natural gas for a 20-year term. 

As of December 31, 2013, the overall project completion for Trains 1 and 2 and Trains 3 and 4 of the Liquefaction Project were approximately 54% and 20%, 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 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, which has not yet received regulatory approval for construction. 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, 2013, 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.

2




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 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 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.

In addition, Cheniere Marketing, LLC ("Cheniere Marketing"), an indirect wholly owned subsidiary of Cheniere, has entered into an SPA with us (the "Cheniere Marketing SPA") to purchase, at Cheniere Marketing's option, up to 104,000,000 MMBtu/yr of LNG. We have the right each year during the term of the SPA to reduce the annual contract quantity based on our assessment of how much LNG we can produce in excess of that required for other customers. Cheniere Marketing may purchase incremental LNG volumes at a price of 115% of Henry Hub plus up to $3.00 per MMBtu for the most profitable 36,000,000 MMBtu of cargoes sold each year by Cheniere Marketing; and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing.

Natural Gas Transportation and Supply

For our feed gas 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 other third party pipeline companies. We have entered into enabling agreements with third parties, and will continue to enter into such agreements in order to secure feed gas for the Liquefaction Project.

Construction
    
Trains 1 through 4 are being designed, constructed and commissioned by Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") using the ConocoPhillips Optimized Cascade® technology, a proven technology deployed in numerous LNG projects around the world. 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) is approximately $4.1 billion and $3.8 billion, respectively, reflecting amounts incurred under change orders through December 31, 2013. Total expected capital costs for Trains 1 through 4 are estimated to be between $9.0 billion and $10.0 billion before financing costs, including estimated owner's costs and contingencies.


3




Terminal Use Agreement

In July 2012, Cheniere Investments assigned to us a terminal use agreement ("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, which may occur as early as late 2015. 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 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.

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 LNG 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 natural gas liquefaction facilities near Corpus Christi, Texas and has entered into one SPA for the sale of LNG from this liquefaction facility, and may continue to enter into commercial agreements with respect to this 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, will also be subject to market-based price competition.

Governmental Regulation

The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. This regulatory burden 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, as amended ("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 2012 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 the Liquefaction Project, including the siting, construction and operation of Trains 1 through 4. 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

4




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. 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 or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud.

DOE Export License

The DOE has authorized the export of up to 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 FTA 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 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 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 an additional 503.3 Bcf/yr of domestically produced LNG to non-FTA countries are pending.

Exports of natural gas to countries with which the United States has an FTA are "deemed to be consistent with the public interest" and authorization to export LNG to FTA countries shall be granted by the DOE without "modification or delay". FTA countries which import LNG now or will do so by 2016 include Chile, Mexico, Singapore, South Korea and the Dominican Republic. Exports of natural gas to countries with which the United States does not have an FTA 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, 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 U.S. Army Corps of Engineers ("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. The USACE acted in the capacity as a cooperating agency in the FERC's NEPA review process. The application to amend the Sabine Pass LNG

5




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 by September 2014.

We will also need to obtain a modification to the Sabine Pass LNG terminal's existing wastewater discharge permit to authorize discharges from the liquefaction facilities prior to the commencement of operation of the Liquefaction Project.

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 newly established 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") determines, by rulemaking, must 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. This legislation requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the swaps regulatory provisions of the Dodd-Frank Act. The CFTC had adopted rules imposing new position limits on certain core futures and equivalent swaps contracts for or linked to certain physical commodities, including Henry Hub natural gas, that market participants could hold with exceptions for certain bona fide hedging transactions.

The final rules that the CFTC adopted on November 18, 2011 imposing position limits on certain core futures and equivalent swaps contracts for physical commodities, including Henry Hub natural gas, were vacated by federal district court on September 28, 2012. On November 5, 2013, the CFTC proposed new position limits rules that would modify and expand the applicability of position limits on certain core futures and equivalent swaps contracts for or linked to certain physical commodities, including Henry Hub natural gas, that market participants could hold with exceptions for certain bona fide hedging transactions.

The CFTC has determined, by rule, that certain interest rate swaps and certain credit default swaps must be mandatorily cleared, but the CFTC has not yet proposed rules determining 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 exchange-trading requirements for our swaps entered to hedge our commercial risks, these 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 adopt rules that would require our Swap Dealer counterparties to enter into credit support documentation with us and/or require us to post initial and variation margin; however, the CFTC's and other regulators' margin rules are not yet final and therefore the application of those provisions to us is uncertain at this time. Provisions from other titles 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, and impact the liquidity of certain swaps products, all of which could increase our business costs.

6





Environmental Regulation
 
The Liquefaction Project is subject to various federal, state and local laws and regulations relating to the protection of the environment. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial civil and criminal fines and penalties for non-compliance.
 
Clean Air Act ("CAA")
 
The Liquefaction Project is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that the construction and operation of our proposed 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. 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 to discharge 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 are 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.

Employees and Labor Relations
 
We have no employees. We have contracts with subsidiaries of Cheniere and Cheniere Partners for operations, maintenance, and management services. As of January 31, 2014, Cheniere and its subsidiaries had 423 full-time employees, including 235 employees who directly supported the Liquefaction Project.
 

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Available Information

Our principal executive offices are located at 700 Milam Street, Suite 800, 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 Securities and Exchange Commission ("SEC"). The public may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers, like us, that file electronically with the SEC.

ITEM 1A.                      RISK FACTORS
 
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The risk factors in this report are grouped into the following categories: 
Risks Relating to Our Financial Matters; and
Risks Relating to the Completion of Our 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, 2013, we had zero cash and cash equivalents, 1,059.7 million of restricted cash and cash equivalents and $4.1 billion of total debt outstanding (before debt discounts). We 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 capital markets. Furthermore, our 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 $194.5 million, $85.2 million and $36.5 million for the years ended December 31, 2013, 2012 and 2011, 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 cash flows from operations under any SPA until late 2015, at the earliest. Any delays beyond the expected development period for Train 1 would prolong, and could increase the level of, our operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully and timely complete the applicable Train.


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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.

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

Each of our SPAs contain 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 could have an adverse impact on our ability to hedge risks associated with our business and on our results of operations and cash flows.

Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter ("OTC") derivatives market and entities, such as us, that participate in that market. The provisions of that title of the Dodd-Frank Act and the rules of the CFTC and the SEC adopted and proposed to be adopted thereunder, regulate certain swaps entities, require clearing of certain swaps by clearing organizations and execution of certain swaps on contract markets or swap execution facilities, and require certain reporting and recordkeeping of swaps. They also give the CFTC the authority to establish 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. The CFTC's rules establishing position limits were vacated by a federal district court in September 2012. However, on November 5, 2013, the CFTC proposed new position limits rules that would modify and expand the applicability of position limits on certain core futures and equivalent swaps contracts for or linked to certain physical commodities, including Henry Hub natural gas, that market participants could hold with exceptions for certain bona fide hedging transactions.

The CFTC has designated certain interest rate swaps and certain credit default swaps for mandatory clearing and set compliance dates for three different categories of market participants who are parties to such swaps, the earliest of which was March 11, 2013 and the latest of which was September 9, 2013. The CFTC has not yet proposed rules designating any other

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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 to hedge our commercial risks, 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. In addition, for uncleared swaps, the CFTC or federal banking regulators may require our counterparties to require that we enter into credit support documentation and/or post initial and variation margin; however, the proposed margin rules are not yet final, and therefore the application of those provisions to us is uncertain at this time. 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, 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 and the related rules 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 risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, 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 interest rate 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. Our SPAs with Total and Centrica 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 of Total and Centrica 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 engineering, procurement and construction 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

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

Any delay in completion of a Train could cause a delay in the receipt of revenues projected therefrom, or cause a loss of one or more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity, and prospects.

Our ability to complete development of additional Trains will be contingent on our ability to obtain additional funding.

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. 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. If there are changes in the global climate, storm frequency and intensity may increase; should it result in rising seas, our coastal operations may be impacted.

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. Approval of the FERC 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. 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

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Section 3 of the NGA for authorization to site, construct and operate two additional Trains is currently pending and will be subject to an environmental assessment by the FERC and comment from the public and intervenors. 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, 2014, Cheniere and its subsidiaries had 423 full-time employees, including 235 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.

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 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 its option, up to 104,000,000 MMBtu/yr of LNG. 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.


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

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

design and engineer each Train to operate in accordance with specifications;
engage and retain third-party subcontractors and procure equipment and supplies;
respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
attract, develop and retain skilled personnel, including engineers;
post required construction bonds and comply with the terms thereof;
manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
maintain their own financial condition, including adequate working capital.
Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable liquefaction facility, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of Bechtel and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the applicable liquefaction facility or result in a contractor's unwillingness to perform further work on the Liquefaction Project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are relying on third-party engineers to estimate the future capacity ratings and performance capabilities of 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, and this could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.


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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.

Decreases in the demand for and price of LNG and natural gas could affect the performance of our SPA customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The development of domestic LNG facilities and projects generally is based on assumptions about the future availability of natural gas, price of natural gas and LNG, and the prospects for international natural gas and LNG markets. Natural gas 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:

relatively minor changes in the supply of, and demand for, natural gas in relevant markets;
political conditions in natural gas producing regions;
the extent of domestic production and importation of natural gas in relevant markets;
the level of demand for LNG and natural gas in relevant markets, including the effects of economic downturns or upturns;
weather conditions;
the competitive position of natural gas as a source of energy compared with other energy sources; and
the effect of government regulation on the production, transportation and sale of 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 adversely affect the performance of our SPA customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.


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Cyclical or other changes in the demand for LNG and natural gas may adversely affect our proposed liquefaction facilities and the performance of our customers and could reduce our operating revenues and may cause us operating losses.

The economics of our proposed liquefaction facilities could be subject to cyclical swings, reflecting alternating periods of under-supply and over-supply of LNG import or export capacity and available natural gas, principally due to the combined impact of several factors, including:

competitive liquefaction capacity in North America, which could divert natural gas from our proposed liquefaction facilities;
insufficient LNG receiving capacity or over-supply of natural gas liquefaction capacity worldwide;
insufficient LNG tanker capacity;
reduced demand and lower prices for natural gas;
increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
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;
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.
These factors could materially and adversely affect our ability, and the ability of our current and prospective customers, to procure customers for LNG, or to procure natural gas to be liquefied and exported to international markets, at economical prices, or at all.

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.


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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 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 believe that there is sufficient capacity on the Creole Trail Pipeline to accommodate all of our natural gas supply requirements for Trains 1 and 2 but not for additional Trains. We have entered into transportation precedent agreements to secure firm pipeline transpiration capacity with CTPL and other third party pipelines and plan to secure additional capacity, but we may not be able to do so on commercially reasonable terms or at all, which would 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:


16






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;
increases in capacity and utilization of nuclear power and related facilities; and
displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
Terrorist attacks or military campaigns may adversely impact our business.

A terrorist or military incident involving an LNG facility or 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 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; 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 greenhouse gases, 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.


17






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.
 
 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, 2013, 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.
PART II
 
ITEM 5.     MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED MEMBER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
 
Not applicable.


18






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 Operation and our Financial Statements and the accompanying notes thereto included elsewhere in this report.
 
 
Period from June 24, 2010 (Date of Inception) Through December 31, 2013
 
Year Ended December 31,
 
Period from June 24, 2010 (Date of Inception) Through December 31, 2010
 
 
 
2013
 
2012
 
2011
 
 
 
 
 
(in thousands)
Income Statement Data:
 
 
 
 
 
 
 
 
 
 
Revenues
 
$

 
$

 
$

 
$

 
$

Expenses
 
268,299

 
136,136

 
85,783

 
36,511

 
9,869

Loss from operations
 
(268,299
)
 
(136,136
)
 
(85,783
)
 
(36,511
)
 
(9,869
)
Loss on early extinguishment of debt
 
(131,576
)
 
(131,576
)
 

 

 

Net loss
 
(326,027
)
 
(194,490
)
 
(85,157
)
 
(36,511
)
 
(9,869
)
 
 
As of December 31,
 
 
2013
 
2012
 
2011
 
2010
 
 
(in thousands)
Balance Sheet Data (as of end of period):
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$

 
$

 
$

 
$

Restricted cash and cash equivalents (current)
 
192,144

 
75,133

 

 

Non-current restricted cash and cash equivalents
 
867,590

 
196,319

 

 

Property, plant and equipment, net
 
4,412,580

 
1,228,720

 
279

 

Total assets
 
5,941,972

 
1,710,380

 
1,390

 
61

Long-term debt, net of discount
 
4,111,562

 
100,000

 

 

Total equity (deficit)
 
1,638,265

 
1,467,239

 
(46,380
)
 
(9,869
)

19






ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
 
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 included elsewhere in this report. 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 include 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 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 nominal production capacity of approximately 4.5 mtpa of LNG.

Overview of Significant Events
 
Our significant accomplishments since January 1, 2013 and through the filing date of this Form 10-K include the following:
We issued an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 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" and collectively with the 2021 Senior Notes and the 2022 Senior Notes, the "Senior Notes"). Net proceeds from these offerings are intended to be used to pay a portion of the capital costs incurred in connection with the construction of Trains 1 through 4 of the Liquefaction Project;
We entered into four credit facilities (collectively, the "2013 Liquefaction Credit Facilities") totaling $5.9 billion (which were subsequently reduced to $5.0 billion in connection with the issuance of the 2022 Senior Notes) to be used for costs associated with the construction of Trains 1 through 4 of the Liquefaction Project;
We issued a notice to proceed to Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") under the lump sum turnkey contract for the engineering, procurement and construction of Train 3 and Train 4 (the "EPC Contract (Trains 3 and 4)"); and
We entered into an LNG sale and purchase agreement ("SPA") with Centrica plc ("Centrica") that commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 91.25 million 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.

20






Liquidity and Capital Resources
 
Cash and Cash Equivalents
 
As of December 31, 2013, we had zero cash and cash equivalents and $1,059.7 million of current and non-current restricted cash and cash equivalents.

Liquefaction Facilities

Our Liquefaction Project is being developed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. 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. We are developing Trains 5 and 6 and commenced the regulatory approval process for these Trains in February 2013.

We have received authorization from the Federal Energy Regulatory Commission (the "FERC") to site, construct and operate Trains 1 through 4. We have also filed an application with the FERC for the approval to construct Trains 5 and 6. The U.S. Department of Energy (the "DOE") has granted us an order authorizing the export of up to the equivalent of 16 mtpa (approximately 803 Bcf/yr) of LNG to all nations with which trade is permitted for a 20-year term beginning on the earlier of the date of first export from Train 1 or August 7, 2017. The DOE further issued orders authorizing the export of an additional 503.3 Bcf/yr in total of domestically produced LNG from the Sabine Pass LNG terminal to free trade agreement ("FTA") countries providing for national treatment for trade in natural gas for a 20-year term. 

As of December 31, 2013, the overall project completion for Trains 1 and 2 and Trains 3 and 4 of the Liquefaction Project were approximately 54% and 20%, 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 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, which has not yet received regulatory approval for construction. 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 SPA with us to purchase, at Cheniere Marketing's option, up to 104,000,000 MMBtu/yr of LNG. We have the right each year during the term of the SPA to reduce the annual contract quantity based on its assessment of how much LNG it can produce in excess of that required for other customers. Cheniere Marketing may purchase incremental LNG volumes at a price of 115% of Henry Hub plus up to $3.00 per MMBtu for the most profitable 36,000,000 MMBtu of cargoes sold each year by Cheniere Marketing; and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing.


21






Natural Gas Transportation and Supply

For our feed gas 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 other third party pipeline companies. We have entered into enabling agreements with third parties, and will continue to enter into such agreements in order to secure feed gas for the Liquefaction Project.

Construction
    
Trains 1 through 4 are being designed, constructed and commissioned by Bechtel. We have entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Train 1 and Train 2 (the "EPC Contract (Trains 1 and 2)") and 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, 2013. 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.

Terminal Use Agreement

In July 2012, Cheniere Energy Investments, LLC ("Cheniere Investments"), a wholly owned subsidiary of Cheniere Partners, assigned to us a terminal use agreement ("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, which may occur as early as late 2015. 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 borrowings, equity contributions from Cheniere Partners and cash flows under the SPAs. We believe that with the net proceeds of borrowings and unfunded commitments under the 2013 Liquefaction Credit Facilities (as defined below), 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 by late 2015, when Train 1 is anticipated to achieve initial LNG production.


22






Senior Secured Notes

As of December 31, 2013, we had three series of senior secured notes outstanding:
$2.0 billion of the 2021 Senior Notes;
$1.0 billion of the 2022 Senior Notes; and
$1.0 billion of the 2023 Senior Notes (collectively with the 2021 Senior Notes and the 2022 Senior Notes, the "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, or December 15, 2021, with respect to the 2022 Senior Notes, or January 15, 2023, with respect to the 2023 Senior Notes, we may redeem all or a part of the Senior Notes at a redemption price equal to the "make-whole" price set forth in the indenture governing the Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. We also may at any time on or after November 1, 2020, with respect to the 2021 Senior Notes, or December 15, 2021, with respect to the 2022 Senior Notes, or January 15, 2023, with respect to the 2023 Senior Notes, redeem the Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount 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 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.

We may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than our current outstanding indebtedness, including the Senior Notes and the 2013 Liquefaction Credit Facilities described below.

2013 Liquefaction Credit Facilities

We have four credit facilities aggregating $5.0 billion, 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, and 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") 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.

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 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.


23






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, 2013, 2012 and 2011 and the period from June 24, 2010 (date of inception) through December 31, 2013. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, that are referred to elsewhere in this report. Additional discussion of these items follows the table.
 
 
Year Ended December 31,
 
Period from June 24, 2010 (Date of Inception) Through December 31, 2013
 
 
2013
 
2012
 
2011
 
 
 
(in thousands)
Sources of cash and cash equivalents
 
 
 
 
 
 
 
 
Proceeds from debt issuances and credit facilities
 
$
4,112,500

 
$
100,000

 
$

 
$
4,212,500

Contributions from Cheniere Partners
 
338,276

 
1,623,849

 

 
1,962,125

Advances—affiliate
 

 

 
37,701

 
44,479

Total sources of cash and cash equivalents
 
4,450,776

 
1,723,849

 
37,701

 
6,219,104

Uses of cash and cash equivalents
 
 
 
 
 
 
 
 
Plant, property and equipment, net
 
(3,082,195
)
 
(1,113,999
)
 
(211
)
 
(4,196,405
)
Investment in restricted cash and cash equivalents, net of uses of restricted cash and cash equivalents
 
(949,347
)
 
(352,216
)
 

 
(1,301,563
)
Debt issuance and deferred financing costs
 
(309,404
)
 
(212,412
)
 
(650
)
 
(522,466
)
Repayment of 2012 Liquefaction Credit Facility
 
(100,000
)
 

 

 
(100,000
)
Operating cash flow
 

 

 
(36,840
)
 
(43,618
)
Advances—affiliate
 

 
(44,479
)
 

 
(44,479
)
Other
 
(9,830
)
 
(743
)
 

 
(10,573
)
Total uses of cash and cash equivalents
 
(4,450,776
)
 
(1,723,849
)
 
(37,701
)
 
(6,219,104
)
Net increase (decrease) in cash and cash equivalents
 

 

 

 

Cash and cash equivalents-beginning of period
 

 

 

 

Cash and cash equivalents-end of period
 
$

 
$

 
$

 
$


Proceeds from Debt Issuances and Repayment of 2012 Liquefaction Credit Facility

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. Net proceeds from those offerings are intended to be used to pay a portion of the capital costs incurred in connection with the construction of the Liquefaction Project. In May 2013, we closed 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 Trains 1 through 4 of the Liquefaction Project. We made a $100.0 million borrowing under the 2013 Liquefaction Credit Facilities in June 2013 after meeting the required conditions precedent. In November 2013, we issued an aggregate principal amount of $1.0 billion of the 2022 Senior Notes to be used to pay a portion of the capital costs incurred in connection with the construction of the Liquefaction Project.
    
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. 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.

Contributions from Cheniere Partners

During the years ended December 31, 2013 and 2012, we received equity contributions from Cheniere Partners in amounts totaling $338.3 million and $1,623.9 million, respectively.


24






Advances—affiliate

From our inception to the closing of the 2012 Liquefaction Credit Facility, Cheniere Partners had provided all funding related to the Liquefaction Project through advances, which were repayable upon demand. For the year ended December 31, 2011 and from June 24, 2010 (the date of our inception) through December 31, 2011, we received advances from Cheniere Partners in amounts totaling $37.7 million and $44.5 million, respectively.

Upon the closing of our 2012 Liquefaction Credit Facility in July 2012, Cheniere Partners settled all amounts we owed to them from advances affiliate and we reclassified the amounts as equity contributions from Cheniere Partners.

Property, Plant and Equipment, Net

LNG terminal costs, net primarily related to the construction of Trains 1 through 4 of the Liquefaction Project. In June 2012, we began capitalizing costs associated with Trains 1 and 2 of the Liquefaction Project, and in May 2013, we began capitalizing costs associated with Trains 3 and 4 of the Liquefaction Project.

Investment in Restricted Cash and Cash Equivalents, Net of Uses of Restricted Cash and Cash Equivalents

During 2013, we invested $949.3 million in restricted cash and cash equivalents, net of uses of restricted cash and cash equivalents. This investment in restricted cash and cash equivalents was primarily a result of the $4,041.4 million investment in restricted cash and cash equivalents primarily related to the net proceeds from the Senior Notes and the 2013 Liquefaction Credit Facilities. This investment in restricted cash and cash equivalents was partially offset by the use of $3,092.0 million of restricted cash and cash equivalents primarily related to the construction of the Liquefaction Project.

During 2012, we invested $352.2 million in restricted cash and cash equivalents. We invested $1,467.0 million of restricted cash and cash equivalents from equity contributions received from Cheniere Partners that was partially offset by the use of $1,114.7 million of restricted cash for the construction of Trains 1 and 2 of the Liquefaction Project.

Debt Issuance and Deferred Financing Costs

Debt issuance and deferred financing costs in the year ended December 31, 2013 resulted from amounts paid by us related to the 2013 Liquefaction Credit Facilities and the Senior Notes.

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.

Operating Cash Flow

Our operations to date have consisted of pre-construction and construction activities associated with the Liquefaction Project. We used $36.8 million and $43.6 million of cash and cash equivalents in operating activities during the year ended December 31, 2011, and during the period from June 24, 2010 (the date of our inception) through December 31, 2011, respectively, for the development of the Liquefaction Project. Net cash and cash equivalents used in operating activities was zero in the years ended December 31, 2013 and 2012 as a result of funding our operating activities exclusively through the use of restricted cash and cash equivalents instead of cash and cash equivalents. All cash and cash equivalents were restricted under the terms and conditions of the 2012 Liquefaction Credit Facility and the 2013 Liquefaction Credit Facilities.


25






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, 2013 (in thousands).
 
 
Payments Due for Years Ended December 31,
 
 
Total
 
2014
 
2015 - 2016
 
2017 - 2018
 
Thereafter
Construction and purchase obligations (1)
 
$
4,261,240

 
$
2,210,541

 
$
1,840,670

 
$
210,029

 
$

Long-term debt (2)
 
4,100,000

 

 

 

 
4,100,000

Interest Payments (2)
 
2,219,512

 
291,607

 
583,389

 
583,214

 
761,302

Operating lease obligations (3)
 
58,584

 
908

 
1,782

 
1,540

 
54,354

Service contracts (4)
 
5,591,767

 
77,346

 
160,630

 
479,861

 
4,873,930

Total
 
$
16,231,103

 
$
2,580,402

 
$
2,586,471

 
$
1,274,644

 
$
9,789,586

 
(1)
Construction and purchase obligations primarily relate to EPC Contract (Trains 1 and 2) and EPC Contract (Trains 3 and 4). A discussion of these obligations can be found in Note 11—"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, 2012. Please read Note 9—"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 11—"Commitments and Contingencies" and Note 12—"Related Party Transactions" of our Notes to Financial Statements.
(4)
Service contracts primarily relate to services agreements and a TUA with Sabine Pass LNG. A discussion of these obligations can be found in Note 11—"Commitments and Contingencies" and Note 12—"Related Party Transactions" of our Notes to Financial Statements.
Results of Operations
 
We are a development stage company, currently in the construction phase, and no operating revenues have been recorded to date.

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 commitments pursuant to 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 until substantial completion of each Train. 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 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.


26






2012 vs. 2011

Our net loss was $85.2 million in 2012 compared to a net loss of $36.5 million in 2011. The increase in loss was primarily the result of increased development expenses. For the year ended December 31, 2012, we recorded a net loss of $85.2 million, principally arising from $40.3 million of technical, consulting, legal and other professional fees associated with front-end engineering and design work, obtaining an order from the FERC authorizing construction of Trains 1 through 4 and performing other required permitting work, and $35.3 million of general and administrative expenses for costs incurred to manage the construction of Trains 1 and 2. Our $36.5 million net loss in the year ended December 31, 2011 was primarily a result of development activities related to Trains 1 and 2 of the Liquefaction Project.

Off-Balance Sheet Arrangements
 
As of December 31, 2013, 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. Actual results could differ from the estimates and assumptions used.

Estimates used in the assessment of impairment of our long-lived assets are the most significant of our estimates. There are numerous uncertainties inherent in estimating future cash flows of assets. The accuracy of any cash flow estimate is a function of judgment used in determining the amount of cash flows generated. As a result, cash flows may be different from the cash flows that we use to assess impairment of our assets. 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. Significant negative industry or economic trends, including reduced estimates of future cash flows of 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 of 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.

Other items subject to estimates and assumptions include asset retirement obligations, valuations of derivative instruments and collectability of accounts receivable and other assets. As future events and their effects cannot be determined accurately, actual results could differ significantly from our estimates.
 
Derivatives

We use derivative instruments from time to time to hedge the exposure to the variability in expected future cash flows attributable to the future sale of LNG inventory and to hedge the exposure to the volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities.

Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. 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. To date, all of our derivative positions fair value determinations have been made by management using quoted prices in active markets for similar assets or liabilities. The ultimate fair value of our derivative instruments is uncertain, and we believe that it is possible that a change in the estimated fair value will occur in the near future as interest rates change.

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

27






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, we begin to apply mark-to-market accounting at that time. 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.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, restricted cash and cash equivalents and accounts payable approximate fair value because of the short maturity of those instruments. We use available market data and valuation methodologies to estimate the fair value of debt.

Asset Retirement Obligations

We recognize asset retirement obligations ("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 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.

Recent Accounting Standards

In February 2013, the Financial Accounting Standards Board ("FASB") issued guidance that requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under GAAP that provide additional detail on these amounts. This standard is effective prospectively for reporting periods beginning after December 15, 2012. We adopted this standard effective January 1, 2013. The adoption of this guidance did not have an impact on our financial position, results of operations or cash flows, as it only expanded disclosures.

In December 2011 and February 2013, the FASB issued guidance that requires entities to disclose both gross and net information about both derivatives and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting agreement. The objective of the disclosure is to facilitate comparison between those entities that prepare their financial statements on the basis of GAAP and those entities that prepare their financial statements on the basis of International Financial Reporting Standards. Retrospective presentation for all comparative periods

28






presented is required. We adopted this guidance effective January 1, 2013. The adoption of this guidance did not have an impact on our financial position, results of operations or cash flows, as it only expanded disclosures.

There are currently no new accounting standards that have been issued that will have a significant impact on our financial position, results of operations or cash flows upon adoption.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Commodity Price Risk

We have entered into certain derivative instruments to hedge the exposure to variability in expected future cash flows attributable to the future sale of 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 table below provides information about our LNG Inventory Derivatives that are sensitive to changes in natural gas prices and interest rates as of December 31, 2013 (in thousands, except for volume and price range data):

Hedge Description
 
Hedge Instrument
 
Contract Volume (MMBtu)
 
Price Range ($/MMBtu)
 
Final Hedge Maturity Date
 
Fair Value (in thousands)
 
VaR (in thousands)
LNG Inventory Derivatives
 
Fixed price natural gas swaps
 
842,473
 
3.732 - 4.475
 
April 2014
 
$
156

 
$
2


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 resulted in a change in the fair value of the Interest Rate Derivatives of $31.2 million. The table below provides information about our Interest Rate Derivatives that are sensitive to changes in the forward 1-month LIBOR curve as of December 31, 2013:
Hedge Description
 
Hedge Instrument
 
Initial Notional Amount
 
Maximum Notional Amount
 
Fixed Interest Rate Range (%)
 
Final Hedge Maturity Date
 
Fair Value (in thousands)
 
10% Change in LIBOR (in thousands)
Interest Rate Derivatives
 
Interest rate swaps
 
$20.0 million
 
$3.6 billion
 
1.99
 
May 2020
 
$
84,639

 
$
31,161




29






ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
INDEX TO FINANCIAL STATEMENTS
 
SABINE PASS LIQUEFACTION, LLC



30






REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Member
Sabine Pass Liquefaction, LLC


We have audited the accompanying balance sheets of Sabine Pass Liquefaction, LLC (a development stage limited liability company) as of December 31, 2013 and 2012, and the related statements of operations, comprehensive loss, member's equity (deficit), and cash flows for each of the three years in the period ended December 31, 2013 and the period from June 24, 2010 (date of inception) through 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 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013 and the period from June 24, 2010 (date of inception) through December 31, 2013, in conformity with U.S. generally accepted accounting principles.



/s/    Ernst & Young LLP
Ernst & Young LLP
Houston, Texas
February 21, 2014





















31






SABINE PASS LIQUEFACTION, LLC
(A DEVELOPMENT STAGE LIMITED LIABILITY COMPANY)
BALANCE SHEETS
(in thousands)
 
 
December 31,
 
 
2013
 
2012
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$


$

Restricted cash and cash equivalents
 
192,144


75,133

Accounts receivable—affiliate

 
1,167

 

Advances to affiliate
 
9,430

 
3,962

Prepaid expenses and other
 
4,511

 
4,440

Total current assets
 
207,252

 
83,535

 
 
 
 
 
Non-current restricted cash and cash equivalents
 
867,590


196,319

Property, plant and equipment, net
 
4,412,580


1,228,720

Debt issuance costs, net
 
296,040

 
200,067

Non-current derivative assets

 
98,123

 

Other
 
60,387

 
1,739

Total assets
 
$
5,941,972


$
1,710,380

LIABILITIES AND MEMBER'S EQUITY (DEFICIT)
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
8,067

 
$
73,693

Accounts payable—affiliates
 
460

 
15,242

Accrued liabilities
 
144,575

 
26,293

Accrued liabilities—affiliates
 
25,559

 
1,489

Derivative liabilities

 
13,484

 
$

Total current liabilities
 
192,145

 
116,717

 
 
 
 
 
Long-term debt
 
4,111,562


100,000

Long-term derivative liability
 

 
26,424

Commitments and contingencies
 


 


 
 
 
 
 
Member's equity, including equity accumulated during development stage of $1,638.3 million and $1,467.2 million at December 31, 2013 and December 31, 2012, respectively
 
 
 
 
Member's equity
 
1,638,265

 
1,494,479

Accumulated other comprehensive loss
 

 
(27,240
)
Total member's equity
 
1,638,265


1,467,239

Total liabilities and member's equity
 
$
5,941,972

 
$
1,710,380














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

32






SABINE PASS LIQUEFACTION, LLC
(A DEVELOPMENT STAGE LIMITED LIABILITY COMPANY)
STATEMENTS OF OPERATIONS
(in thousands)
 
 
Year Ended December 31,
 
Period from June 24, 2010 (Inception) Through December 31, 2013
 
 
2013
 
2012
 
2011
 
Revenues
 
$


$


$

 
$

 
 
 
 
 
 
 
 
 
Expenses
 
 

 
 

 
 

 
 
Development expense
 
11,540

 
37,341

 
32,406

 
89,561

Development expense—affiliate
 
1,392

 
2,955

 
4,049

 
9,989

General and administrative expense
 
3,305

 
1,359

 
49

 
4,715

General and administrative expense—affiliate
 
93,064

 
33,951

 

 
127,015

Terminal use agreement maintenance expense
 
26,228

 
10,058

 

 
36,286

Terminal use agreement maintenance expense—affiliate
 
394

 

 

 
394

Depreciation expense
 
213

 
119

 
7

 
339

Total expenses
 
136,136

 
85,783


36,511

 
268,299

 
 
 
 
 
 
 
 
 
Loss from operations
 
(136,136
)

(85,783
)

(36,511
)
 
(268,299
)
 
 
 
 
 
 
 
 
 
Other income (expense)
 
 

 
 

 
 

 
 
Interest expense
 
(10,796
)
 
(139
)
 

 
(10,935
)
Loss on early extinguishment of debt
 
(131,576
)




 
(131,576
)
Derivative gain
 
83,266

 
679

 

 
83,945

Other Income
 
752

 
86

 

 
838

Total other income (expense)
 
(58,354
)
 
626

 

 
(57,728
)
 
 
 
 
 
 
 
 
 
Net loss
 
$
(194,490
)

$
(85,157
)

$
(36,511
)
 
$
(326,027
)























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

33






SABINE PASS LIQUEFACTION, LLC
(A DEVELOPMENT STATE LIMITED LIABILITY COMPANY)
STATEMENTS OF COMPREHENSIVE LOSS
(in thousands)
 
 
Year Ended December 31,
 
Period from June 24, 2010 (Inception) Through December 31, 2013
 
 
2013
 
2012
 
2011
 
Net loss
 
$
(194,490
)
 
$
(85,157
)
 
$
(36,511
)
 
$
(326,027
)
Other comprehensive income (loss)
 
 
 
 
 
 
 
 
Interest rate cash flow hedges
 
 
 
 
 
 
 
 
Loss on settlements retained in other comprehensive income
 
(30
)
 
(136
)
 

 
(166
)
Change in fair value of interest rate cash flow hedges
 
21,297

 
(27,104
)
 

 
(5,807
)
Losses reclassified into earnings as a result of discontinuance of cash flow hedge accounting
 
5,973

 

 

 
5,973

Total other comprehensive income (loss)
 
27,240

 
(27,240
)
 

 

Comprehensive loss
 
$
(167,250
)
 
$
(112,397
)
 
$
(36,511
)
 
$
(326,027
)




































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

34






SABINE PASS LIQUEFACTION, LLC
(A DEVELOPMENT STATE LIMITED LIABILITY COMPANY)
STATEMENTS OF MEMBER'S EQUITY (DEFICIT)
(in thousands)
 
Sabine Pass LNG-LP, LLC
 
Accumulated Other Comprehensive Income (Loss)
 
Total Member's Equity (Deficit)
Balance at June 24, 2010 (inception)
$

 
$

 
$

Net loss
(9,869
)
 

 
(9,869
)
Balance at December 31, 2010
(9,869
)
 

 
(9,869
)
Net loss
(36,511
)
 

 
(36,511
)
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


































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

35






SABINE PASS LIQUEFACTION, LLC
(A DEVELOPMENT STAGE LIMITED LIABILITY COMPANY)
STATEMENTS OF CASH FLOWS
(in thousands)
 
 
Year Ended December 31,
 
Period from June 24, 2010 (Inception) Through December 31, 2013
 
 
2013
 
    2012
 
    2011
 
Cash flows from operating activities
 
 
 
 
 
 
 
 
Net loss
 
$
(194,490
)
 
$
(85,157
)
 
$
(36,511
)
 
$
(326,027
)
Adjustments to reconcile net loss to net cash used in operating activities:
 
 
 
 
 
 
 
 
Use of restricted cash and cash equivalents for certain operating activities
 
161,065

 
80,764

 

 
241,829

Depreciation
 
2,917

 
119

 
7

 
3,043

Non-cash terminal use agreement maintenance expense

 
26,731

 
9,612

 

 
36,343

Non-cash derivative (gain)
 
(83,667
)
 
(679
)
 

 
(84,346
)
Loss on extinguishment of debt
 
131,576

 

 

 
131,576

Changes in operating assets and liabilities:
 
 
 
 
 
 
 
 
Accounts receivable—affiliates
 
(1,167
)
 

 
 
 
(1,167
)
Accounts payable
 
20

 
(704
)
 
(368
)
 
20

Accounts payable—affiliates
 
(10,927
)
 
11,179

 

 
252

Accrued liabilities
 
(187
)
 
(1,077
)
 
(566
)
 
(54
)
Accrued liabilities—affiliates
 
12,592

 
366

 
698

 
13,910

Advances to affiliate
 
(5,017
)
 
(4,414
)
 

 
(9,431
)
Prepaid expenses & other
 
(39,446
)
 
(10,009
)
 
(100
)
 
(49,566
)
Net cash used in operating activities
 

 

 
(36,840
)
 
(43,618
)
 
 
 
 
 
 
 
 
 
Cash flows from investing activities
 
 

 
 

 
 

 
 
Property, plant and equipment
 
(3,082,195
)
 
(1,113,999
)
 
(211
)
 
(4,196,405
)
Use of restricted cash and cash equivalents for the acquisition for property, plant and equipment
 
3,092,025

 
1,114,742

 

 
4,206,767

Advances under long-term contracts and other
 
(9,830
)
 
(743
)
 

 
(10,573
)
Net cash used in investing activities
 

 

 
(211
)
 
(211
)
 
 
 
 
 
 
 
 
 
Cash flows from financing activities
 
 

 
 

 
 

 
 
Proceeds from Senior Notes

 
4,012,500

 

 

 
4,012,500

Proceeds from 2013 Liquefaction Credit Facilities
 
100,000

 

 

 
100,000

Proceeds from (repayment of) 2012 Liquefaction Credit Facility facility
 
(100,000
)
 
100,000

 

 

Contributions from Cheniere Partners
 
338,276

 
1,623,849

 

 
1,962,125

Investment in restricted cash and cash equivalents
 
(4,041,372
)
 
(1,466,958
)
 

 
(5,508,330
)
Debt issuance and deferred financing costs
 
(309,404
)
 
(212,412
)
 
(650
)
 
(522,466
)
Advances—affiliate
 

 
(44,479
)
 
37,701

 

Net cash provided by financing activities
 

 

 
37,051

 
43,829

 
 
 
 
 
 
 
 
 
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.

36




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 liquefied natural gas ("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 an indirect 49.2% owned subsidiary of Cheniere Energy, Inc. ("Cheniere"), a Houston-based energy company primarily engaged in LNG-related businesses. As used in these notes to financial statements, the terms "Sabine Pass Liquefaction," "we," "us," "Company" and "our" refer to Sabine Pass Liquefaction.

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 capacity of up to 265,000 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.

We are a development stage company formed on June 24, 2010 with no revenues from operations to date. Operations to date have been devoted to pre-construction and construction activities of the Liquefaction Project. The accompanying financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. Our ultimate profitability will depend on, among other factors, obtaining financing, and completion of construction and commencement of commercial operations of the Liquefaction Project. As of December 31, 2013, we had a cumulative net loss of $326.0 million. In addition, Cheniere Partners has committed to provide financing necessary to financially support us. No owner of Sabine Pass Liquefaction is liable for Sabine Pass Liquefaction's debts, liabilities or obligations beyond such owner's capital contribution.
  
NOTE 2—BASIS OF PRESENTATION
 
Our financial statements were prepared in accordance with accounting principles generally accepted in the United States of America ("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.

Because we are a development stage enterprise, we have presented our financial statements in accordance with guidance applicable to development stage entities. Our Statements of Operations also include expense allocations for certain corporate functions historically performed by Cheniere, including allocations of material general corporate expenses related to executive oversight, accounting, treasury, tax, legal, procurement and information technology. These allocations are based primarily on specific identification of time and/or activities associated with Sabine Pass Liquefaction, employee headcount or capital expenditures. Our management believes the assumptions underlying the financial statements, including the assumptions regarding allocating general corporate expenses from Cheniere, are reasonable. Nevertheless, the financial statements may not include all of the actual expenses that would have been incurred had we been a stand-alone company during the periods presented and may not reflect our results of operations, financial position and cash flows had we been a stand-alone company during the periods presented. Actual costs that would have been incurred if we had been a stand-alone company would depend on multiple factors, including the organization's structure and strategic decisions made in various areas, including information technology and infrastructure.


37




SABINE PASS LIQUEFACTION, LLC. 
NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
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. 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. This presentation does not impact the total amount of operating, investing or financing cash flows related to these items, however, they 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.

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.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments 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 operations.

Management reviews property, plant and equipment for impairment periodically and whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. We have recorded no impairments related to property, plant and equipment for the years ended December 31, 2013, 2012 and 2011 or the period from June 24, 2010 (date of inception) through December 31, 2013.


38




SABINE PASS LIQUEFACTION, LLC. 
NOTES TO FINANCIAL STATEMENTS—CONTINUED

Derivatives

We use derivative instruments from time to time to hedge the exposure to the variability in expected future cash flows attributable to the future sale of LNG inventory and to hedge exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities described in Note 9—"Long-Term Debt".

Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. 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.  To date, all of our derivative positions' fair value determinations have been made by management using quoted prices in active markets for similar assets or liabilities.  The ultimate fair value of our derivative instruments is uncertain, and we believe it is possible that a change in the estimated fair value will occur in the near future as commodity prices and interest rates change.

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, we begin to apply mark-to-market accounting at that time. 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.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of the short maturity of those instruments. We use available market data and valuation methodologies to estimate the fair value of debt.

Concentration of Credit Risk

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

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. 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 LNG sale and purchase agreements ("SPAs") with unaffiliated third parties. We are dependent on the respective counterparties' creditworthiness and their willingness to perform under their respective SPAs.

39




SABINE PASS LIQUEFACTION, LLC. 
NOTES TO FINANCIAL STATEMENTS—CONTINUED


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, 2013, the tax basis of our assets and liabilities was $10.6 million less than the reported amounts of our assets and liabilities.

Pursuant to the indentures governing our long-term debt (the "Senior Notes Indentures"), 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.

Debt Issuance Costs

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 expense.

Asset Retirement Obligations

We recognize asset retirement obligations ("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.


40




SABINE PASS LIQUEFACTION, LLC. 
NOTES TO FINANCIAL STATEMENTS—CONTINUED

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. Actual results could differ from the estimates and assumptions used.

Estimates used in the assessment of impairment of our long-lived assets are the most significant of our estimates.  There are numerous uncertainties inherent in estimating future cash flows of assets or business segments.  The accuracy of any cash flow estimate is a function of judgment used in determining the amount of cash flows generated.  As a result, cash flows may be different from the cash flows that we use to assess impairment of our assets.  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.  Significant negative industry or economic trends, including reduced estimates of future cash flows of our business or disruptions to our business could lead to an impairment charge of our long-lived assets and other intangible 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 of 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.

Other items subject to estimates and assumptions include asset retirement obligations, valuations of derivative instruments and collectability of accounts receivable and other assets.

As future events and their effects cannot be determined accurately, actual results could differ significantly from our estimates. 

NOTE 4—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 2012, we entered into a construction/term loan facility in an amount up to $3.6 billion (the "2012 Liquefaction Credit Facility"). In 2013, we closed an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 2021 (the "2021 Senior Notes"), $1.0 billion of 6.25% Senior Secured Notes due 2022 (the "2022 Senior Notes") and $1.0 billion of 5.625% Senior Secured Notes due 2023 (the "2023 Senior Notes" and collectively with the 2021 Senior Notes and the 2022 Senior Notes, the "Senior Notes"). In May 2013, we closed four credit facilities aggregating $5.9 billion (collectively, the "2013 Liquefaction Credit Facilities"), which amended and restated the 2012 Liquefaction Credit Facility. See Note 9—"Long-Term Debt". Under the terms and conditions of the 2012 Liquefaction Credit Facility and 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. As of December 31, 2013 and 2012, we classified $192.1 million and $75.1 million, respectively, as current restricted cash and cash equivalents for the payment of current liabilities related to the Liquefaction Project and $867.6 million and $196.3 million, respectively, as non-current restricted cash and cash equivalents for future Liquefaction Project construction costs.


41




SABINE PASS LIQUEFACTION, LLC. 
NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 5—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of LNG terminal costs and fixed assets, as follows (in thousands):
 
 
December 31,
 
 
2013
 
2012
LNG terminal costs
 
 
 
 
LNG terminal
 
$
98

 
$

LNG terminal construction-in-process
 
4,412,077

 
1,228,391

Total LNG terminal costs, net
 
4,412,175

 
1,228,391

 
 
 
 
 
Fixed assets
 
 

 
 

Vehicles

 
309

 
154

Machinery and equipment
 
301

 
301

Other

 
135

 

Accumulated depreciation
 
(340
)
 
(126
)
Total fixed assets, net
 
405

 
329

Property, plant and equipment, net
 
$
4,412,580

 
$
1,228,720

 

In June 2012, we began capitalizing costs associated with Trains 1 and 2 of the Liquefaction Project, and in May 2013, we began capitalizing costs associated with Trains 3 and 4 of the Liquefaction Project. For the years ended December 31, 2013 and 2012 and for the period from June 24, 2010 (date of inception) through December 31, 2013, we capitalized $183.6 million, $35.1 million, and $218.7 million of interest expense related to the construction of Trains 1 through 4 of the Liquefaction Project, respectively.

NOTE 6—DEBT ISSUANCE COSTS
    
We have incurred debt issuance costs in connection with our long-term debt. These costs are deferred and are being amortized over the term of the related debt.  Upon early retirement or amendment to a debt agreement, certain fees are written off to expense. For the years ended December 31, 2013, 2012 and 2011 and for the period from June 24, 2010 (date of inception) through December 31, 2013, we amortized $38.9 million$12.7 millionzero and $51.6 million, respectively, of debt issuance costs. In addition, for the years ended December 31, 2013, 2012 and 2011 and for the period from June 24, 2010 (date of inception) through December 31, 2013, we wrote off $118.3 millionzerozero and $118.3 million, respectively, of debt issuance costs related to early extinguishments of debt.

As of December 31, 2013, we had recorded $296.0 million of debt issuance costs directly associated with the arrangement of debt financing, net of accumulated amortization, as follows (in thousands): 
Long-Term Debt
 
Debt Issuance Costs
 
Amortization Period
 
Accumulated
Amortization
 
Net Costs
2013 Liquefaction Credit Facilities
 
$
257,924

 
7.0 years
 
$
(46,400
)
 
$
211,524

2021 Senior Notes
 
45,325

 
8.0 years
 
(3,910
)
 
41,415

2022 Senior Notes
 
22,226

 
8.3 years
 
(195
)
 
22,031

2023 Senior Notes
 
22,230

 
10.0 years
 
(1,160
)
 
21,070

Total
 
$
347,705

 
 
 
$
(51,665
)
 
$
296,040



42




SABINE PASS LIQUEFACTION, LLC. 
NOTES TO FINANCIAL STATEMENTS—CONTINUED

NOTE 7—ACCRUED LIABILITIES
 
As of December 31, 2013 and 2012, accrued liabilities (including affiliate) consisted of the following (in thousands):
 
 
December 31, 2013
 
December 31, 2012
Interest and related debt fees
 
$
65,153

 
$
155

Affiliate
 
25,559

 
1,489

LNG liquefaction costs
 
79,422

 
26,138

Total accrued liabilities
 
$
170,134

 
$
27,782


NOTE 8—ADVANCES FROM AFFILIATE

Prior to the closing of our 2012 Liquefaction Credit Facility, Cheniere Partners had provided all funding related to the Liquefaction Project from our inception through advances, which were repayable upon demand. Cheniere Partners did not charge interest on these advances. As of December 31, 2011, we classified $44.5 million as current liabilities on our Balance Sheets. Upon the closing of our 2012 Liquefaction Credit Facility in July 2012, Cheniere Partners settled $166.8 million that represented all amounts we owed them from advances to equity. Accordingly, we reclassified the outstanding advances from advances from affiliate to equity.

NOTE 9—LONG-TERM DEBT

As of December 31, 2013 and 2012, our long-term debt consisted of the following (in thousands):
 
 
December 31,
 
 
2013
 
2012
Long-term debt
 
 
 
 
2021 Senior Notes

 
$
2,000,000

 
$

2022 Senior Notes
 
1,000,000

 

2023 Senior Notes

 
1,000,000

 

2012 Liquefaction Credit Facility

 

 
100,000

2013 Liquefaction Credit Facilities

 
100,000

 

Total long-term, debt
 
4,100,000

 
100,000

 
 
 
 
 
Long-term debt premium
 
 
 
 
2021 Senior Notes

 
11,562

 

Total long-term debt, net of premium
 
$
4,111,562

 
$
100,000


Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2013 (in thousands): 
 
 
Payments Due for the Years Ended December 31,
 
 
Total
 
2014
 
2015 to 2016
 
2017 to 2018
 
Thereafter
Debt:
 
 
 
 
 
 
 
 
 
 
2021 Senior Notes
 
2,000,000

 

 

 

 
2,000,000

2022 Senior Notes
 
1,000,000

 

 

 

 
1,000,000

2023 Senior Notes
 
1,000,000

 

 

 

 
1,000,000

2013 Liquefaction Credit Facilities
 
100,000

 

 

 

 
100,000

Debt
 
$
4,100,000

 
$

 
$

 
$

 
$
4,100,000



43




SABINE PASS LIQUEFACTION, LLC. 
NOTES TO FINANCIAL STATEMENTS—CONTINUED

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, we also issued $1.0 billion 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%. Interest on the Senior Notes is payable semi-annually in arrears.

The Senior Notes are governed by a common indenture (the "Indenture") with substantially similar restrictive covenants. 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, or December 15, 2021, with respect to the 2022 Senior Notes, or January 15, 2023, with respect to the 2023 Senior Notes, we may redeem all or a part 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 also may at any time on or after November 1, 2020, with respect to the 2021 Senior Notes, or December 15, 2021, with respect to the 2022 Senior Notes, or January 15, 2023, with respect to the 2023 Senior Notes, redeem the Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.
    
In connection with the issuance of the 2022 Senior Notes, we also entered into a registration rights agreement (the "2022 Liquefaction Registration Rights Agreement"). Under the 2022 Liquefaction Registration Rights Agreement, we have agreed to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange the 2022 Senior Notes for a like aggregate principal amount of SEC-registered notes with terms identical in all material respects to the 2022 Senior Notes (other than with respect to restrictions on transfer or to any increase in annual interest rate) within 360 days after November 25, 2013.  Under specified circumstances, we may be required to file a shelf registration statement to cover resales of the Senior Notes.  If we fail to satisfy this obligation, we may be required to pay additional interest to holders of the 2022 Senior Notes under certain circumstances.

2013 Liquefaction Credit Facilities

In May 2013, we closed 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 a $100.0 million borrowing under the 2013 Liquefaction Credit Facilities in June 2013 after meeting the required conditions precedent.

We had $5.0 billion of available commitments under the 2013 Liquefaction Credit Facilities as of December 31, 2013 as a result of our initial $100.0 million borrowing and the termination of approximately $885.0 million of commitments in connection with issuance of the 2022 Senior Notes in November 2013 as described below.
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

44




SABINE PASS LIQUEFACTION, LLC. 
NOTES TO FINANCIAL STATEMENTS—CONTINUED

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, and 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 the second borrowing and 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 10—"Financial Instruments".

In November 2013, we issued the 2022 Senior Notes and a portion of the available commitments pursuant to the 2013 Liquefaction Credit Facilities was terminated. Net proceeds from the offering of approximately $978 million are intended to be used to pay a portion of the capital costs in connection with the construction of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2013 Liquefaction Credit Facilities. The 2022 Senior Notes are pari passu in right of payment with all existing and future senior debt of Sabine Pass Liquefaction. As a result of our issuance of the 2022 Notes in November 2013, we have terminated $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.

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. 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.

The 2012 Liquefaction Credit Facility had a maturity date of the earlier of July, 31, 2019 or the second anniversary of the completion date of Trains 1 and 2 of the Liquefaction Project. Borrowings under the 2012 Liquefaction Credit Facility could have been 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 a $100.0 million borrowing under the 2012 Liquefaction Credit Facility in August 2012 after meeting the required conditions precedent.

Borrowings under the 2012 Liquefaction Credit Facility bore interest at a variable rate equal to, at our election, LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans was 3.50% during construction and 3.75% during operations. Interest on LIBOR loans was due and payable at the end of each LIBOR period. The 2012 Liquefaction Credit Facility required us to pay certain up-front fees to the agents and lenders in the aggregate amount of approximately $178 million and provided 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. Annual administrative fees were also required to be paid to the agent and the trustee. The principal of loans made under the 2012 Liquefaction Credit Facility had to be repaid in quarterly installments, commencing with the last day of the first calendar quarter ending at least three months following the completion of

45




SABINE PASS LIQUEFACTION, LLC. 
NOTES TO FINANCIAL STATEMENTS—CONTINUED

Trains 1 and 2 of the Liquefaction Project. Scheduled repayments were based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2012 Liquefaction Credit Facility.

Under the terms and conditions of the 2012 Liquefaction Credit Facility, all cash held by us was controlled by the collateral agent. These funds could only be released by the collateral agent upon satisfaction of certain terms and conditions related to the use of proceeds, and the cash balance of $100.0 million held in these accounts as of December 31, 2012 was classified as restricted on our Balance Sheets.

The 2012 Liquefaction Credit Facility contained conditions precedent for the second borrowing and any subsequent borrowings, as well as customary affirmative and negative covenants. Our obligations under the 2012 Liquefaction Credit Facility were secured by substantially all of our assets as well as all of our membership interests, and a security interest in Cheniere Partners' rights under the Unit Purchase Agreement with Blackstone dated May 14, 2012 on a pari passu basis with the Senior Notes.

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 10—"Financial Instruments".

In February 2013, we issued the 2021 Senior Notes to refinance a portion of the 2012 Liquefaction Credit Facility, and a portion of available commitments pursuant to the 2012 Liquefaction Credit Facility was suspended. In April 2013, we issued an aggregate principal amount of $500.0 million of additional 2021 Senior Notes and $1.0 billion of 2023 Senior Notes, and as a result, 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 in the year ended December 31, 2013.

NOTE 10—FINANCIAL INSTRUMENTS
 
Derivative Instruments

Cheniere Marketing, LLC ("Cheniere Marketing") has entered into certain financial derivatives, on our behalf, to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory ("LNG Inventory Derivatives") and 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").

The following table (in thousands) shows the fair value of our LNG Inventory Derivatives and Interest Rate Derivatives that are required to be measured at fair value on a recurring basis as of December 31, 2013 and 2012, which are classified as other current assets, other current liabilities, other non-current assets and other non-current liabilities in our Balance Sheets.
 
Fair Value Measurements as of
 
December 31, 2013
 
December 31, 2012
 
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 liability
$

 
$
156

 
$

 
$
156

 
$

 
$

 
$

 
$

Interest Rate Derivatives asset (liability)

 
84,639

 

 
84,639

 

 
(26,424
)
 

 
(26,424
)

The estimated fair values of our LNG Inventory Derivatives are the amount 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

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SABINE PASS LIQUEFACTION, LLC. 
NOTES TO FINANCIAL STATEMENTS—CONTINUED

rates, credit spreads and other relevant data. 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.

LNG Inventory Derivatives

We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value. The changes in fair value are reported in earnings.

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 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. We are required by these financial institutions to use margin deposits as credit support for our commodity derivative activities. Collateral of $0.2 million and zero was deposited for such contracts, which has not been reflected in the derivative fair value tables, is included in the other current assets balance as of December 31, 2013 and 2012, respectively.

The following table (in thousands) shows the fair value and location of our LNG Inventory Derivatives on our Balance Sheets:
 
 
 
 
Fair Value Measurements as of
 
Balance Sheet Location
 
December 31, 2013
 
December 31, 2012
LNG Inventory Derivatives liability
Prepaid expenses and other
 
$
156

 
$


The following table (in thousands) shows the changes in the fair value and settlements of our LNG Inventory Derivatives recorded in derivative gain on our Statements of Operations during the years ended December 31, 2013, 2012, 2011 and for the period from June 24, 2010 (date of inception) through December 31, 2013:
 
Year Ended December 31,
 
Period from June 24, 2010 (date of Inception) Through December 31, 2013
 
2013
 
2012
 
2011
 
LNG Inventory Derivatives gain
$
476

 
$

 
$

 
$
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