Sabine Pass LNG 10-K 2013 FY Annual report

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 Number 333-138916

Sabine Pass LNG, L.P.

(Exact name of registrant as specified in its charter) 

Delaware	20-0466069
(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.    YesoNox

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.    YesoNox

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.    YesxNoo

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  x    No o

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  o	Accelerated filer  o
Non-accelerated filer  x	Smaller reporting company  o
(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  o  No  x

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

Documents incorporated by reference: None

SABINE PASS LNG, L.P.

TABLE OF CONTENTS

PART I
Items 1. and 2. Business and Properties	1
Item 1A. Risk Factors	5
Item 1B. Unresolved Staff Comments	14
Item 3. Legal Proceedings	14
Item 4. Mine Safety Disclosure	14
PART II
Item 5. Market for Registrant's Common Equity, Related Partner Matters and Issuer Purchases of Equity Securities	14
Item 6. Selected Financial Data	15
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation	16
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	21
Item 8. Financial Statements and Supplementary Data	22
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	44
Item 9 A. Controls and Procedures	44
Item 9B. Other Information	44
PART III
Item 10. Directors, Executive Officers of Our General Partner and Corporate Governance	45
Item 11. Executive Compensation	45
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	45
Item 13. Certain Relationships and Related Transactions, and Director Independence	45
Item 14. Principal Accountant Fees and Services	46
PART IV
Item 15. Exhibits and Financial Statement Schedules	46
Signatures	50

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, "forward-looking statements" 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 regarding future levels of domestic and international natural gas production, supply or consumption or future levels of liquefied natural gas ("LNG") imports into or exports from North America and other countries worldwide, regardless of the source of such information, or the transportation 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 regarding any 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 LNG regasification, liquefaction or storage capacities that are, or may become, subject to contracts;

• statements regarding counterparties to our terminal use agreements ("TUAs") and other contracts;

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

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

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

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

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DEFINITIONS

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

• Bcf/d means billion cubic feet per day; 

• Bcfe means billion cubic feet equivalent;

• 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; and

• TUA means terminal use agreement.

PART I

ITEMS 1. and 2.        BUSINESS AND PROPERTIES

General

In 2003, we were formed by Cheniere Energy, Inc. ("Cheniere") to own, develop and operate an LNG receiving and regasification terminal in western Cameron Parish, Louisiana, less than four miles from the Gulf Coast on the Sabine Pass deepwater ship channel (our "LNG terminal"). We are a Houston-based partnership formed with one general partner, Sabine Pass LNG-GP, LLC ("Sabine Pass GP"), and one limited partner, Sabine Pass LNG-LP, LLC ("Sabine Pass LNG-LP"), both indirect subsidiaries of Cheniere. Cheniere has a 49.2% ownership interest in Cheniere Energy Partners, L.P. ("Cheniere Partners"), which is the 100% parent of Cheniere Energy Investments, LLC ("Cheniere Investments"), the 100% parent of Sabine Pass GP and Sabine Pass LNG-LP and, indirectly, us.

Unless the context requires otherwise, references to "Sabine Pass LNG", "we", "us", and "our" refer to Sabine Pass LNG, L.P. and its wholly owned subsidiaries.

LNG is natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to justify economically the use of LNG. LNG is transported using large oceangoing LNG tankers specifically constructed for this purpose. LNG receiving and regasification facilities offload LNG from LNG tankers, store the LNG prior to processing, heat the LNG to return it to a gaseous state and deliver the resulting natural gas into pipelines for transportation to market.

Our Business Strategy

Our primary business objective is to generate stable cash flows by: 

• operating the Sabine Pass LNG terminal safely, efficiently and reliably; and 

• providing services to our long-term TUA customers to generate steady and reliable revenues and operating cash flows. 

Our Business

We have constructed and are operating the Sabine Pass LNG terminal located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. We have long-term leases for three tracts of land consisting of 883 acres. We are currently operating our LNG terminal that 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 operational regasification capacity of approximately 4.0 Bcf/d.

Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"), a wholly owned subsidiary of Cheniere Partners, is developing liquefaction facilities adjacent to our existing regasification facilities in order to liquefy and export natural gas from the United States.  Cheniere Partners has reported that Sabine Pass Liquefaction has entered into six sale and purchase agreements with third-

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party customers for the export of natural gas. We have entered into a facilities sharing agreement with Sabine Pass Liquefaction to allow for the interconnection of the liquefaction facilities with our LNG terminal. We do not anticipate incurring any significant costs in connection with such interconnection. Although it is anticipated that our operating costs will increase once the liquefaction facilities commence operations as a result of greater utilization of our LNG terminal by Sabine Pass Liquefaction under its TUA, the increase in fees that Sabine Pass Liquefaction will be required to pay us under its TUA will more than cover our increased costs.

Customers

Approximately 2.0 Bcf/d of the regasification capacity at our LNG terminal has been reserved under two long-term third-party TUAs, under which our customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Capacity reservation fee TUA payments are made by our third-party TUA customers as follows:

• Total Gas & Power North America, Inc. ("Total") has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to us aggregating approximately $125 million annually for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total's obligations under its TUA of up to $2.5 billion, subject to certain exceptions; and 

• Chevron U.S.A. Inc. ("Chevron") has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to us aggregating approximately $125 million annually for 20 years that commenced July 1, 2009. Chevron Corporation has guaranteed Chevron's obligations under its TUA up to 80% of the fees payable by Chevron.

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by Sabine Pass Liquefaction. Sabine Pass Liquefaction is obligated to make monthly capacity payments to us aggregating approximately $250 million annually, continuing until at least 20 years after Sabine Pass Liquefaction delivers its first commercial cargo at Sabine Pass Liquefaction's liquefaction facilities under construction, which Cheniere Partners has reported may occur as early as late 2015. We entered into a terminal use rights assignment and agreement ("TURA") with Sabine Pass Liquefaction and Cheniere Investments, pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA during construction of Sabine Pass Liquefaction's liquefaction facilities at our LNG terminal and has the obligation to make the monthly capacity payments required by the TUA to us. Cheniere Partners has guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA.

Under each of these TUAs, we are entitled to retain 2% of the LNG delivered to our LNG terminal by our TUA customers.

Competition

We currently do not experience competition for our LNG terminal capacity because the entire approximately 4.0 Bcf/d of regasification capacity that is available at our LNG terminal has been fully reserved under three 20-year TUAs, under which each TUA customer is generally required to pay monthly fixed capacity reservation fees whether or not it uses any of its reserved capacity. If and when we have to replace any TUAs, we will compete with other then-existing LNG terminals for customers.

Governmental Regulation

Our LNG terminal 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 operating our LNG terminal, and failure to comply with such laws could result in substantial penalties.

Federal Energy Regulatory Commission ("FERC")

In order to site and construct our LNG terminal, we received and are required to maintain authorization from the FERC under Section 3 of the Natural Gas Act of 1938, as amended ("NGA"). In addition, orders from the FERC authorizing construction of an LNG terminal are typically subject to specified conditions that must be satisfied throughout operation of our LNG terminal. Throughout the life of our LNG terminal, we 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.

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In 2005, the Energy Policy Act of 2005 ("EPAct") was signed into law. The EPAct gave the FERC exclusive authority to approve or deny an application for the siting, construction, expansion or operation of an LNG terminal. 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.

Other Governmental Permits, Approvals and Authorizations

In addition to the FERC authorization under Section 3 of the NGA, the operation of our LNG terminal is also subject to additional federal permits, orders, approvals and consultations required by other federal agencies, including the U.S. Department of Energy, 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, U.S. Environmental Protection Agency ("EPA") and U.S. Department of Homeland Security.

Our LNG terminal is subject to U.S. Department of Transportation safety regulations and standards for the transportation and storage of LNG and regulations of the U.S. Coast Guard relating to maritime safety and facility security. Moreover, our LNG terminal is subject to state and local laws, rules and regulations.

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 Commodities 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 requirements and exchange-trading requirements for our swaps entered to hedge our commercial risks, these mandatory clearing requirements 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 swap 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.

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Environmental Regulation

Our LNG terminal 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")

Our LNG terminal is subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations 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")

Our LNG terminal 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")

Our LNG terminal 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 United States Army Corps of Engineers, and by the states (in Louisiana, by the Department of Environmental Quality).

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 our LNG terminal operations, we will be subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

Endangered Species Act

Our LNG terminal 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 our LNG terminal. See Note 11—"Related Party Transactions" in our Notes to Consolidated Financial Statements for a discussion of these arrangements.  Cheniere considers its current employee relations to be favorable.

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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 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 Our Business.

Risks Relating to Our Financial Matters

We have incurred a significant amount of debt, which we will need to refinance, extend or otherwise satisfy in whole or in part at or prior to maturity.

As of December 31, 2013, we had $2.1 billion of total consolidated indebtedness outstanding (before debt discounts). We may not be able to access external financial resources sufficient to enable us to refinance or repay our maturing debt.

Our substantial indebtedness and restrictions contained in existing or future debt agreements may not allow us the flexibility that we need to operate our business in an effective and efficient manner and may prevent us from taking advantage of strategic and financial opportunities that would benefit our business, including:

• limiting our ability to attract customers;

• limiting our ability to compete with other companies that are not as highly leveraged;

• limiting our flexibility in and ability to plan for or react to changing market conditions in our industry and to economic downturns, and making us more vulnerable than our less leveraged competitors to an industry or economic downturn;

• limiting our ability to use operating cash flow in other areas of our business or for distributions to our partners because we must dedicate a substantial portion of these funds to service debt, including indebtedness that we may incur in the future;

• limiting our ability to obtain additional financing to fund our capital expenditures, working capital, acquisitions, debt service requirements or liquidity needs for general business or other purposes; and

• resulting in a material adverse effect on our business, financial condition, operating results, liquidity and prospects if we are unable to service or refinance our indebtedness or obtain additional financing, as needed.

Our substantial indebtedness and the restrictive covenants contained in our existing or future debt agreements may not allow us the flexibility that we need to operate our business in an effective and efficient manner and may prevent us from taking advantage of strategic and financial opportunities that would benefit our business. If we are unsuccessful in operating our business or taking advantage of such opportunities, due to our substantial indebtedness or other factors, we may be unable to obtain, repay, refinance or extend indebtedness on commercially reasonable terms or at all.

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To service our indebtedness, we require significant amounts of cash flow from operations.

We require significant amounts of cash flow from operations in order to make annual interest payments of approximately $152 million on the Senior Notes described below. Our ability to make payments on and to refinance our indebtedness, including the Senior Notes, and to fund our capital expenditures, will depend on our ability to generate cash in the future. Our business may not generate sufficient cash flow from operations, currently anticipated costs may increase or future borrowings may not be available to us, which could cause us to be unable to pay or refinance our indebtedness, including the Senior Notes, or to fund our other liquidity needs.

Our ability to generate cash is substantially dependent upon the performance by our three customers under their TUAs, 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 dependent upon performance by Chevron and Total, each of which has entered into a TUA with us and agreed to pay us approximately $125 million annually, and with Sabine Pass Liquefaction, which is required to pay us approximately $250 million annually. We are dependent on each customer's continued willingness and ability to perform its obligations under its TUA. We are also exposed to the credit risk of the guarantors of these customers' obligations under their respective TUAs in the event that we must seek recourse under a guaranty. If any customer fails to perform its obligations under its TUA, 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 TUA.

Sabine Pass Liquefaction continues to develop its business and has recently incurred significant indebtedness in connection with constructing the first four of six proposed liquefaction trains at our LNG terminal adjacent to our existing regasification facilities. Cheniere Partners has reported that it will be late 2015 at the earliest before commercial operations, and therefore cash flows under Sabine Pass Liquefaction's LNG purchase and sale agreements, commence for the first liquefaction train. In the meantime, Cheniere Investments has obtained rights to utilize Sabine Pass Liquefaction's TUA capacity during construction of the first four liquefaction trains at our LNG terminal, which Cheniere Investments has in turn contracted with Cheniere Marketing, LLC, a wholly owned subsidiary of Cheniere ("Cheniere Marketing"), to utilize. Cheniere Partners has guaranteed the obligations of Sabine Pass Liquefaction and Cheniere Investments, and Cheniere has guaranteed the obligations of Cheniere Marketing. However, neither Cheniere Investments nor Cheniere Marketing has a credit rating, neither has unconditional agreements or arrangements for any supplies of LNG or for the utilization of the reserved capacity, neither may be able to obtain such agreements or arrangements on economical terms, or at all, and neither may have the credit support and funding available to enter into such agreements or arrangements. These factors create financial obstacles and exacerbate the risk that neither Cheniere Investments nor Cheniere Marketing, and in turn, Sabine Pass Liquefaction, will be able to satisfy the payment obligations under Sabine Pass Liquefaction's TUA, which could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Each customer's TUA for capacity at our LNG terminal is subject to termination under certain circumstances.

Each of our long-term TUAs contains various termination rights. For example, each customer may terminate its TUA if our LNG terminal experiences a force majeure delay for longer than 18 months, fails to redeliver a specified amount of natural gas in accordance with the customer's redelivery nominations or fails to accept and unload a specified number of the customer's proposed LNG cargoes. We may not be able to replace these TUAs on desirable terms, or at all, if they are terminated.

We may be restricted under the terms of the indentures governing the Senior Notes (the "Senior Notes Indentures") from making distributions under certain circumstances, which may limit Sabine Pass Liquefaction's ability to make payments under its TUA with us.

The Senior Notes Indentures restrict payments that we can make in certain events and limits the indebtedness that we can incur. We are permitted to pay distributions only after the following payments have been made:

• an operating account has been funded with amounts sufficient to cover the succeeding 45 days of operating and maintenance expenses, maintenance capital expenditures and obligations, if any, under an assumption agreement and a state tax sharing agreement;

• one-sixth of the amount of interest due on the Senior Notes on the next interest payment date (plus any shortfall from any such month subsequent to the preceding interest payment date) has been transferred to a debt payment account;

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• outstanding principal on the Senior Notes then due and payable has been paid;

• taxes payable by us or the guarantors of the Senior Notes and permitted payments in respect of taxes have been paid; and

• the debt service reserve account has on deposit the amount required to make the next interest payment on the Senior Notes.

In addition, we will only be able to make distributions to our partners in the event that we could, among other things, incur at least $1.00 of additional indebtedness under the fixed charge coverage ratio test of 2:1 at the time of payment and after giving pro forma effect to the distribution. We are also prohibited under the Senior Notes Indentures from paying distributions upon the occurrence of any of the following events, among others:

• a default for 30 days in the payment of interest on the Senior Notes;

• a failure to pay any principal of the Senior Notes;

• a failure to comply with various covenants in the Senior Notes Indentures;

• a failure to observe any other agreement in the Senior Notes Indentures beyond any specified cure periods;

• a default under any mortgage, indenture or instrument governing any indebtedness for borrowed money by us in excess of $25.0 million if such default results from a failure to pay principal or interest on, or results in the acceleration of, such indebtedness;

• a final money judgment or decree (not covered by insurance) in excess of $25.0 million is not discharged or stayed within 60 days following entry;

• a failure of any material representation or warranty in the security documents entered into in connection with the Senior Notes Indentures to be correct;

• our LNG terminal project is abandoned; or

• certain events of bankruptcy or insolvency.

Our inability to pay distributions or to incur additional indebtedness as a result of the foregoing restrictions in the Senior Notes Indentures may inhibit Sabine Pass Liquefaction's ability to make payments under its TUA with us, which in turn could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.

The Senior Notes Indentures may prevent us from engaging in certain beneficial transactions.

In addition to restrictions on our ability to make distributions or incur additional indebtedness, the Senior Notes Indentures also contains various other covenants that may prevent us from engaging in beneficial transactions, including limitations on the ability of us or certain of our subsidiaries to:

• make certain investments;

• purchase, redeem or retire equity interests;

• issue preferred stock;

• sell or transfer assets;

• incur liens;

• enter into transactions with affiliates;

• consolidate, merge, sell or lease all or substantially all of its assets; and

• enter into sale and leaseback transactions.

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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 use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange ("NYMEX"), 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 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.

8

Risks Relating to Our Business

Operation of our LNG terminal involves significant risks.

As more fully discussed in these Risk Factors, our LNG terminal 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.

To maintain the cryogenic readiness of our LNG terminal, we may need to purchase and process LNG. Our TUA customers have the obligation to procure LNG if necessary for our LNG terminal to maintain its cryogenic state. If they fail to do so, we may need to procure such LNG.

We need to maintain the cryogenic readiness of our LNG terminal. Our customers have the obligation to maintain minimum inventory levels, and, under certain circumstances, to procure LNG to maintain the cryogenic readiness of the terminal. In the event that aggregate minimum inventory levels are not maintained, we have the right to procure a cryogenic readiness cargo to cure a minimum inventory condition, and to be reimbursed by each customer for their allocable share of the LNG acquisition costs. If we are not able to obtain financing on acceptable terms, we will need to maintain sufficient working capital for such a purchase until we receive reimbursement for the allocable costs of the LNG from our customers or sell the regasified LNG. We may also bear the commodity price and other risks of purchasing LNG, holding it in our inventory for a period of time and selling the regasified LNG.

We may be required to purchase natural gas to provide fuel at our LNG terminal, which would increase operating costs and could have a material adverse effect on our results of operations.

Our TUAs provide for an in-kind deduction of 2% of the LNG delivered to our LNG terminal, which we use primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. There is a risk that this 2% in-kind deduction will be insufficient for these needs and that we will have to purchase additional natural gas from third parties. We will bear the cost and risk of changing prices for any such fuel.

Hurricanes or other disasters could result in an interruption of our operations, 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. 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 operation of our LNG terminal could impede operations and could have a material adverse effect on us.

The operation of our LNG terminal is a highly regulated activity. The FERC's approval under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to operate an LNG facility. Although we have obtained all of the necessary authorizations to operate our LNG receiving terminal, such authorizations are subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed. Failure to maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

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We are entirely dependent on subsidiaries of 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 our LNG terminal operations. We have contracted with subsidiaries of Cheniere and Cheniere Partners to provide the personnel necessary for the operation, maintenance and management of our LNG terminal. We face competition for these highly skilled employees in the immediate vicinity of our LNG terminal 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 general partner's executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and our general partner does 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 general partner's 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.

We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, we have entered into a TUA with Sabine Pass Liquefaction, under which Sabine Pass Liquefaction will be able to derive economic benefits. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand.

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

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

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

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

Decreases in the demand for and price of LNG and natural gas could affect the performance of our TUA customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, 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;

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• 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 TUA customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

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

The economics of our LNG terminal 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:

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

• competitive liquefaction capacity in North America, which could divert natural gas from Sabine Pass Liquefaction's proposed liquefaction facilities;

• insufficient or oversupply of LNG liquefaction or receiving 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 offer LNG regasification services or 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 imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;

• adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or 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 customers, to procure supplies of LNG to be imported into North America, to procure customers for LNG or regasified LNG, or to procure natural gas to be liquefied and exported to international markets, at economical prices, or at all.

Failure of imported or 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.

Our LNG terminal operations are dependent upon the ability of our TUA customers to import LNG supplies into the United States, which is primarily dependent upon LNG being a competitive source of energy in North America. In North America, due mainly to a historically abundant supply of natural gas and recent discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. The success of the regasification services component of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to North America at a lower cost than the cost to produce some domestic supplies of natural gas, or 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 in 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 imported LNG.

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One of our TUA customers, Sabine Pass Liquefaction, will also be affected by the ability to export LNG at its proposed liquefaction facilities, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of Sabine Pass Liquefaction's 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 or export 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 or export LNG from or to the United States. Furthermore, some foreign suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-United States markets or from or to competitors' LNG 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 in the United States or 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 or to the United States on a commercial basis. Any significant impediment to the ability to deliver LNG to or from the United States generally, or to our LNG terminal or from our proposed liquefaction facilities specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Various economic and political factors could negatively affect the development of liquefaction facilities, which could adversely affect the performance of our TUA customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Commercial development of liquefaction facilities 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 an LNG facility or LNG vessel.

There may be shortages of LNG vessels worldwide, which could adversely affect the performance of our customers and 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 LNG 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;

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• 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 face competition from competitors with far greater resources.

Many competing companies have secured access to, or are pursuing development or acquisition of, LNG facilities to serve the North American natural gas market. Our LNG regasification service competitors in North America include major energy companies. In addition, competitors have developed or reopened additional LNG terminals in Europe, Asia and other markets, which also compete with our LNG terminal. Almost all of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to natural gas and LNG supplies than we and our affiliates do. The superior resources that these competitors have available for deployment could allow them to compete successfully against us, which could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

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 temporary or permanent closure of existing LNG facilities, including our 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 customers, including their ability to satisfy their obligations to us under their TUAs. 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 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 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 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 LNG terminal 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 our 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 imported to our LNG terminal through the Sabine Pass Channel, could cause additional expenditures, restrictions and delays in our business, 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 costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

13

We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain key personnel could adversely affect us.

We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to operate our LNG terminal and to provide our customers with the highest quality service. Our affiliates who hire personnel on our behalf are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. 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 for us to attract and retain personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. For example, in the aftermaths of Hurricanes Katrina and Rita, Bechtel and certain subcontractors temporarily experienced a shortage of available skilled labor necessary to meet the requirements of our construction plan. As a result, we agreed to change orders with our construction contractor concerning additional activities and expenditures to mitigate the hurricanes' effects on the construction of our LNG terminal. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.

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

All of our anticipated revenue in 2014 will be dependent upon one facility, our LNG terminal located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at our LNG terminal, 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 consolidated 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 PARTNER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Not applicable.

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ITEM 6. SELECTED FINANCIAL DATA

Selected financial data set forth below are derived from our audited consolidated 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 Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report. 

	Year Ended December 31,
	2013			2012			2011			2010			2009
	(in thousands)
Statement of Operations Data:
Revenues (including affiliates)	$	521,552		$	523,884		$	533,612		$	523,223		$	416,790
Expenses (including affiliates)	116,448			96,516			88,993			93,481			76,579
Income from operations	405,104			427,368			444,619			429,742			340,211
Other expense	(160,811		)	(214,563		)	(175,705		)	(173,297		)	(141,402		)
Net income	$	244,293		$	212,805		$	268,914		$	256,445		$	198,809
Cash Flow Data:
Cash flows provided by operating activities	$	302,224		$	263,295		$	319,291		$	268,426		$	244,722
Cash flows used in investing activities	(116		)	(4,458		)	(7,330		)	(5,076		)	(26,431		)
Cash flows used in financing activities	(292,316		)	(257,903		)	(313,619		)	(374,835		)	(295,707		)
	December 31,
	2013			2012			2011			2010			2009
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	14,994		$	5,202		$	4,268		$	5,926		$	117,411
Restricted cash and cash equivalents (current)	14,959			17,386			13,732			13,732			13,732
Non-current restricted cash and cash equivalents	76,106			76,106			82,394			82,394			82,394
Property, plant and equipment, net	1,433,822			1,476,174			1,514,137			1,550,465			1,588,557
Total assets	1,596,210			1,621,596			1,652,513			1,695,305			1,859,101
Long-term debt, net of discount	2,071,807			2,067,113			2,192,418			2,187,724			2,110,101
Long-term debt—related party, net of discount	—			—			—			—			72,928

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTSOF 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 Consolidated Financial Statements and the accompanying notes in "Financial Statements and Supplementary Data." This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis include the following subjects:

• Overview of Business 

• Liquidity and Capital Resources 

• Contractual Obligations 

• Results of Operations 

• Off-Balance Sheet Arrangements 

• Summary of Critical Accounting Estimates 

• Recent Accounting Standards

Overview of Business

In 2003, we were formed by Cheniere Energy, Inc. ("Cheniere") to own, develop and operate an LNG receiving and regasification terminal in western Cameron Parish, Louisiana, less than four miles from the Gulf Coast on the Sabine Pass deepwater ship channel (our "LNG terminal"). Our LNG terminal 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 operational regasification capacity of approximately 4.0 Bcf/d.

Unless the context requires otherwise, references to "Sabine Pass LNG", "we", "us", and "our" refer to Sabine Pass LNG, L.P. and its wholly owned subsidiaries.

Liquidity and Capital Resources

Cash and Cash Equivalents

As of December 31, 2013, we had $15.0 million of cash and cash equivalents and $91.1 million of current and non-current restricted cash and cash equivalents, which is restricted to pay interest on the 2016 Notes and 2020 Notes described below.

The foregoing funds and cash flows generated from operations are anticipated to be sufficient to fund our operating expenditures and interest requirements for at least the next twelve months.

TUA Revenues

Approximately 2.0 Bcf/d of the regasification capacity at our LNG terminal has been reserved under two long-term third-party TUAs, under which our customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Capacity reservation fee TUA payments are made by our third-party TUA customers as follows:

• Total Gas & Power North America, Inc. ("Total") has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to us aggregating approximately $125 million annually for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total's obligations under its TUA up to $2.5 billion, subject to certain exceptions; and 

• Chevron U.S.A. Inc. ("Chevron") has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to us aggregating approximately $125 million annually for 20 years that commenced July 1, 2009. Chevron Corporation has guaranteed Chevron's obligations under its TUA up to 80% of the fees payable by Chevron.

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The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"), a wholly owned subsidiary of Cheniere Energy Partners, L.P. ("Cheniere Partners"), a publicly traded partnership which indirectly owns us. Sabine Pass Liquefaction is developing liquefaction facilities at our LNG terminal adjacent to our existing regasification facilities in order to liquefy and export natural gas from the United States.  Sabine Pass Liquefaction is obligated to make monthly capacity payments to us aggregating approximately $250 million annually, continuing until at least 20 years after Sabine Pass Liquefaction delivers its first commercial cargo at Sabine Pass Liquefaction's liquefaction facilities under construction at our LNG terminal, which Cheniere Partners has reported may occur as early as late 2015. We entered into a terminal use rights assignment and agreement ("TURA") with Sabine Pass Liquefaction and Cheniere Energy Investments, LLC ("Cheniere Investments"), a wholly owned subsidiary of Cheniere Partners, pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to us. Cheniere Partners has guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA.

Under each of these TUAs, we are entitled to retain 2% of the LNG delivered to our LNG terminal by our TUA customers.

Capital Resources

As of December 31, 2013 and 2012, we had an aggregate principal amount of $1,665.5 million, before discount, of the 7.50% Senior Secured Notes due 2016 (the "2016 Notes") and $420.0 million of the 6.50% Senior Secured Notes due 2020 (the "2020 Notes" and collectively with the 2016 notes, the "Senior Notes"). Borrowings under the 2016 Notes and 2020 Notes bear interest at a fixed rate of 7.50% and 6.50%, respectively. The terms of the 2016 Notes and 2020 Notes are substantially similar. Interest on the Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the Senior Notes are secured on a pari passu first-priority basis by a security interest in all of our equity interests and substantially all of our operating assets.

We may redeem some or all of our 2016 Notes at any time, and from time to time, at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:

•1.0% of the principal amount of the 2016 Notes; or

•the excess of: a) the present value at such redemption date of (i) the redemption price of the 2016 Notes plus (ii) all

required interest payments due on the 2016 Notes (excluding accrued but unpaid interest to the redemption date), computed

using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over b) the principal

amount of the 2016 Notes, if greater.

We may redeem some or all of the 2020 Notes at any time on or after November 1, 2016 at fixed redemption prices specified in the indenture governing the 2020 Notes, plus accrued and unpaid interest, if any, to the date of redemption. We may also redeem some or all of the 2020 Notes at any time prior to November 1, 2016 at a "make-whole" price set forth in the indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, we may redeem up to 35% of the aggregate principal amount of the 2020 Notes at a redemption price of 106.5% of the principal amount of the 2020 Notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date, in an amount not to exceed the net proceeds of one or more completed equity offerings as long as we redeem the 2020 Notes within 180 days of the closing date for such equity offering and at least 65% of the aggregate principal amount of the 2020 Notes originally issued remains outstanding after the redemption.

Pursuant to the indentures governing the Senior Notes (the "Senior Notes Indentures"), except for permitted tax distributions, we may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Senior Notes Indentures.

17

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. 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,
	2013			2012			2011
Sources of cash and cash equivalents
Operating cash flow	$	302,224		$	263,295		$	319,291
Proceeds from 2020 Notes	—			420,000			—
Capital contributions from Cheniere Partners	56,820			208,354			—
Uses of restricted cash and cash equivalents	—			6,288			—
Total sources of cash and cash equivalents	359,044			897,937			319,291
Uses of cash and cash equivalents
Distributions to limited partner	(348,938		)	(333,453		)	(313,619		)
Repayment of 2013 Notes	—			(550,000		)	—
LNG terminal costs, net	(116		)	(4,458		)	(7,137		)
Debt issuance costs	(198		)	(9,092		)	—
Other	—			—			(193		)
Total uses of cash and cash equivalents	(349,252		)	(897,003		)	(320,949		)
Net increase (decrease) in cash and cash equivalents	9,792			934			(1,658		)
Cash and cash equivalents—beginning of period	5,202			4,268			5,926
Cash and cash equivalents—end of period	$	14,994		$	5,202		$	4,268

Operating Cash Flow

Operating cash flow was $302.2 million, $263.3 million and $319.3 million in 2013, 2012 and 2011, respectively.

The $38.9 million increase in operating cash flow in 2013 compared to 2012 primarily resulted from increased accounts payable and accrued liabilities due affiliates.

The $56.0 million decrease in operating cash flow in 2012 compared to 2011 primarily resulted from loss on the early extinguishment of the 7.25% Senior Secured Notes due 2013 (the "2013 Notes") primarily related to make-whole payments.

Proceeds from 2020 Notes and Debt Issuance Costs

In October 2012, we issued $420.0 million of the 2020 Notes. Debt issuance costs during the year ended December 31, 2012 relate to the issuance of the 2020 Notes.

Capital Contributions from Cheniere Partners

In the year ended December 31, 2012, Cheniere Partners contributed $208.4 million to us primarily in connection with the repurchase of our 2013 Notes. Funds used for the repurchase included proceeds received from the sale of the 2020 Notes and from $208.4 million of capital contributions from Cheniere Partners.

Use of Restricted Cash and Cash Equivalents

The $6.3 million use of restricted cash and cash equivalents during the year ended December 31, 2012 relates to the payment from a restricted interest payment account of interest on the 2013 Notes that were extinguished in October 2012.

18

Distributions to Limited Partner

We made $348.9 million, $333.5 million and $313.6 million of distributions to our limited partner in 2013, 2012 and 2011, respectively.

Repayment of 2013 Notes

During the fourth quarter of 2012, we repurchased the 2013 Notes. Funds used for the repurchase included proceeds received from the 2020 Notes and from an equity contribution from Cheniere Partners.

Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2013 (in thousands).

	Payments Due for Years Ended December 31,
	Total		2014		2015 - 2016		2017 - 2018		Thereafter
Operating lease obligations (1)	$	253,588	$	9,438	$	19,178	$	12,161	$	212,811
Long-term debt (2)	2,085,500		—		1,665,500		—		420,000
Interest payments (2)	550,879		152,213		294,016		54,600		50,050
Service contracts (3)	134,080		8,512		17,023		17,023		91,522
Cooperative endeavor agreements (3)	7,360		2,453		4,907		—		—
Total	$	3,031,407	$	172,616	$	2,000,624	$	83,784	$	774,383

(1) Operating lease obligations primarily relate to land site and tug leases for our LNG terminal. Minimum lease payments have not been reduced by a minimum sublease rental of $112.5 million due in the future under non-cancelable tug boat subleases, and have not been reduced by sublease payments of $34.3 million we will receive from Sabine Pass Liquefaction. A discussion of these obligations can be found in Note 12—"Leases" of our Notes to Consolidated Financial Statements.

(2) Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2013.  See Note 10—"Long-Term Debt" of our Notes to Consolidated Financial Statements.

(3) A discussion of these obligations can be found in Note 11—"Related Party Transactions" of our Notes to Consolidated Financial Statements.

Results of Operations

2013 vs. 2012

Our consolidated net income increased $31.5 million, from $212.8 million in 2012 to $244.3 million in 2013. This primarily resulted from decreased loss on early extinguishment of debt and decreased interest expense, which was partially offset by increased operating and maintenance expense. Loss on early extinguishment of debt decreased from $42.6 million in 2012 to zero in 2013 primarily as a result of make-whole payments associated with the early repayments in full of the 2013 Notes in 2012. Interest expense decreased $10.5 million in 2013 as a result of the reduction of our indebtedness outstanding and a lower interest rate. During the fourth quarter of 2012, we repurchased $550.0 million of our outstanding 2013 Notes. Funds used for the repurchase included proceeds received from the issuance of $420.0 million of the 2020 Notes and from an equity contribution from Cheniere Partners. Operating and maintenance expense (including affiliate expense) increased $16.5 million, from $41.4 million in 2012 to $57.9 million in 2013. This increase primarily resulted from increased LNG terminal maintenance and repair costs, increased fuel costs and increased costs to manage the operation and maintenance of our LNG terminal under our long-term operation and maintenance agreement with a wholly owned subsidiary of Cheniere.

2012 vs. 2011

Our consolidated net income decreased $56.1 million, from $268.9 million in 2011 to $212.8 million in 2012. This primarily resulted from loss on early extinguishment of debt, decreased revenues and increased operating and maintenance expense. Loss on early extinguishment of debt increased from zero in 2011 to $42.6 million in 2012 primarily as a result of make-whole payments associated with the early repayments in full of the 2013 Notes. Our revenues decreased $9.7 million, from $533.6 million in 2011 to $523.9 million in 2012. This primarily resulted from decreased LNG cargo export loading fee revenue. Operating and

19

maintenance expense (including affiliate expense) increased $7.7 million, from $33.7 million in 2011 to $41.4 million in 2012. This increase primarily resulted from increased dredging services in 2012.

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 consolidated financial position or results of operations.

Summary of Critical Accounting Estimates

The preparation of consolidated 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 consolidated 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 consolidated 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.

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.

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

Derivatives

We use derivative instruments from time to time to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminal. We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 7—"Financial Instruments" of our Notes to Consolidated Financial Statements.

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 consolidated balance sheet as assets or liabilities

20

unless they satisfy the normal purchases and normal sales exception criteria. 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 commodity prices and interest rates change.

Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are recognized currently in earnings. Gains or losses in the positions to mitigate the price risk from future purchases of natural gas to be utilized as fuel to operate our LNG terminal are classified as derivative gain (loss) on our Consolidated Statements of Operations.

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.

Recent Accounting Standards

In December 2011 and February 2013, the Financial Accounting Standards Board 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 presented is required. We adopted this guidance effective January 1, 2013. The adoption of this guidance did not have an impact on our consolidated 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 consolidated financial position, results of operations or cash flows upon adoption.

ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Cash Investments

We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation of capital. Such cash investments are stated at historical cost, which approximates fair market value on our Consolidated Balance Sheets.

Marketing and Trading Commodity Price Risk

We have entered into certain derivative instruments to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminal ("Fuel Derivatives"). We use one-day value at risk ("VaR") with a 95% confidence interval and other methodologies for market risk measurement and control purposes. The VaR is calculated using the Monte Carlo simulation method. The table below provides information about our derivative financial instruments that are sensitive to changes in natural gas prices as of December 31, 2013 (in thousands, except for volume and price range data).

Hedge Description	Hedge Instrument	Contract Volumes (MMBtu)	Price Range ($/MMBtu)	Final Hedge Maturity Date	Fair Value ($)		VaR ($)
Fuel Derivatives	Fixed price natural gas swaps	360,000	4.222 - 4.427	May 2014	$	27	$	11

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

SABINE PASS LNG, L.P.

Management's Report to the Partners of Sabine Pass LNG, L.P.	23
Report of Independent Registered Public Accounting Firm—Ernst & Young LLP	24
Consolidated Balance Sheets	25
Consolidated Statements of Operations	26
Consolidated Statements of Partners' Deficit	27
Consolidated Statements of Cash Flows	28
Notes to Consolidated Financial Statements	29
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data	43

22

MANAGEMENT'S REPORT TO THE PARTNERS OF SABINE PASS LNG, L.P.

Management's Report on Internal Control Over Financial Reporting

As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Sabine Pass LNG, L.P. and its subsidiaries ("Sabine Pass LNG").  In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO").  Sabine Pass LNG's system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.

Based on our assessment, we have concluded that Sabine Pass LNG maintained effective internal control over financial reporting as of December 31, 2013, based on criteria in Internal Control—Integrated Framework (1992) issued by the COSO.

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

Management's Certifications

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

Sabine Pass LNG, L.P.
By:	Sabine Pass LNG-GP, LLC,
	Its general partner

By:	/s/ Charif Souki	By:	/s/ Michael J. Wortley
	Charif Souki		Michael J. Wortley
	Chief Executive Officer		Chief Financial Officer
	(Principal Executive Officer)		(Principal Financial Officer)

23

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Sabine Pass LNG-GP, LLC and

Partners of Sabine Pass LNG, L.P.

We have audited the accompanying consolidated balance sheets of Sabine Pass LNG, L.P. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, partners' deficit, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Sabine Pass LNG, L.P. and subsidiaries at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/    ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

February 21, 2014

24

SABINE PASS LNG, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2013			2012
ASSETS
Current assets
Cash and cash equivalents	$	14,994		$	5,202
Restricted cash and cash equivalents	14,959			17,386
Accounts receivable—affiliate	2,615			1,349
Advances to affiliate	4,025			1,025
LNG inventory	10,430			2,625
Prepaid expenses and other	5,149			5,993
Total current assets	52,172			33,580
Non-current restricted cash and cash equivalents	76,106			76,106
Property, plant and equipment, net	1,433,822			1,476,174
Debt issuance costs, net	16,871			20,882
Other	17,239			14,854
Total assets	$	1,596,210		$	1,621,596
LIABILITIES AND PARTNERS' DEFICIT
Current liabilities
Accounts payable	$	1,420		$	—
Accrued liabilities	21,153			19,469
Due to affiliates	18,721			2,525
Deferred revenue	26,593			26,540
Deferred revenue—affiliate	21,786			21,737
Other	—			97
Total current liabilities	89,673			70,368
Long-term debt, net of discount	2,071,807			2,067,113
Deferred revenue	17,500			21,500
Deferred revenue—affiliate	17,173			14,720
Other non-current liabilities	276			289
Commitments and contingencies
Partners' deficit	(600,219		)	(552,394		)
Total liabilities and partners' deficit	$	1,596,210		$	1,621,596

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

25

SABINE PASS LNG, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2013			2012			2011
Revenues
Revenues	$	265,153		$	268,273		$	278,241
Revenues—affiliates	256,399			255,611			255,371
Total revenues	521,552			523,884			533,612
Expenses
Operating and maintenance expense	32,724			25,399			21,827
Operating and maintenance expense—affiliate	25,172			16,032			11,918
Depreciation expense	42,444			42,431			42,936
General and administrative expense	2,844			1,864			2,723
General and administrative expense—affiliate	13,264			10,790			9,589
Total expenses	116,448			96,516			88,993
Income from operations	405,104			427,368			444,619
Other income (expense)
Interest expense, net	(161,041		)	(171,495		)	(173,590		)
Loss on early extinguishment of debt	—			(42,587		)	—
Derivative gain (loss), net	182			(622		)	(2,251		)
Other	48			141			136
Total other expense	(160,811		)	(214,563		)	(175,705		)
Net income	$	244,293		$	212,805		$	268,914

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

26

SABINE PASS LNG, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' DEFICIT

(in thousands)

	General Partner Sabine Pass LNG-GP, LLC		Limited Partner Sabine Pass LNG-LP, LLC			Total Partners' Deficit
Balance at December 31, 2010	$	—	$	(598,891	)	$	(598,891	)
Distributions to limited partner	—		(313,619		)	(313,619		)
Net income	—		268,914			268,914
Balance at December 31, 2011	—		(643,596		)	(643,596		)
Distributions to limited partner	—		(333,453		)	(333,453		)
Net income	—		212,805			212,805
Capital contributions from Cheniere Partners	—		211,850			211,850
Balance at December 31, 2012	—		(552,394		)	(552,394		)
Contributions from Cheniere Partners	—		56,820			56,820
Distributions to limited partner	—		(348,938		)	(348,938		)
Net income	—		244,293			244,293
Balance at December 31, 2013	$	—	$	(600,219	)	$	(600,219	)

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

27

SABINE PASS LNG, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2013			2012			2011
Cash flows from operating activities
Net income	$	244,293		$	212,805		$	268,914
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	42,444			42,431			42,936
Amortization of debt discount	4,695			4,695			4,695
Amortization of debt issuance costs	4,209			4,362			4,382
Non-cash derivative (gain) loss	(125		)	(1,317		)	1,415
Investment in restricted cash and cash equivalents for certain operating activities	2,427			(3,654		)	—
Loss on early extinguishment of debt	—			1,470			—
Other	169			3,496			—
Changes in operating assets and liabilities:
Due to affiliates	12,512			482			(1,917		)
Deferred revenue	(3,947		)	(4,089		)	(3,964		)
Deferred revenue—affiliate	49			87			58
Advances to affiliate	(2,983		)	(487		)	2,988
Accounts receivable—affiliate	(1,266		)	(1,035		)	35
Accounts payable and accrued liabilities	(751		)	2,296			(114		)
Other	498			1,753			(137		)
Net cash provided by operating activities	302,224			263,295			319,291
Cash flows from investing activities
LNG terminal cost, net	(116		)	(4,458		)	(7,137		)
Other	—			—			(193		)
Net cash used in investing activities	(116		)	(4,458		)	(7,330		)
Cash flows from financing activities
Distributions to limited partner	(348,938		)	(333,453		)	(313,619		)
Repayment of 2013 Notes	—			(550,000		)	—
Proceeds from 2020 Notes	—			420,000			—
Capital contributions from Cheniere Partners	56,820			208,354			—
Debt issuance costs	(198		)	(9,092		)	—
Use of restricted cash and cash equivalents	—			6,288			—
Net cash used in financing activities	(292,316		)	(257,903		)	(313,619		)
Net increase (decrease) in cash and cash equivalents	9,792			934			(1,658		)
Cash and cash equivalents—beginning of period	5,202			4,268			5,926
Cash and cash equivalents—end of period	$	14,994		$	5,202		$	4,268

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

28

SABINE PASS LNG, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—NATURE OF OPERATIONS

We are a Houston-based Delaware limited partnership formed by Cheniere Energy, Inc. ("Cheniere") to own, develop and operate a liquefied natural gas ("LNG") receiving and regasification terminal in western Cameron Parish, Louisiana, less than four miles from the Gulf Coast on the Sabine Pass deepwater ship channel (our "LNG terminal"). We were formed with one general partner, Sabine Pass LNG-GP, LLC ("Sabine Pass GP"), and one limited partner, Sabine Pass LNG-LP, LLC ("Sabine Pass LP"), both indirect subsidiaries of Cheniere. Cheniere has a 49.2% ownership interest in Cheniere Energy Partners, L.P. ("Cheniere Partners"), which is the 100% parent of Cheniere Energy Investments, LLC ("Cheniere Investments"), the 100% parent of Sabine Pass GP and Sabine Pass LP and, indirectly, us. Unless the context requires otherwise, references to "Sabine Pass LNG", "we", "us" and "our" refer to Sabine Pass LNG, L.P. and its wholly owned subsidiaries.

Our LNG terminal 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 operational regasification capacity of approximately 4.0 Bcf/d.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Consolidated 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 consolidated financial position, results of operations or cash flows.

Summary of Critical Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives but involve an implementation and interpretation of existing rules, and the use of judgment, to apply the accounting rules to the specific set of circumstances existing in our business. In preparing our consolidated financial statements in conformity with GAAP, we endeavor to comply with all applicable rules on or before their adoption, and we believe that the proper implementation and consistent application of the accounting rules are critical. However, not all situations are specifically addressed in the accounting literature. In these cases, we must use our best judgment to adopt a policy for accounting for these situations. We accomplish this by analogizing to similar situations and the accounting guidance governing them.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Accounting for LNG Activities

Generally, we begin capitalizing the costs of LNG terminal projects once the individual project meets the following criteria: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project 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 our LNG terminal projects.

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.

29

SABINE PASS LNG, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

We capitalize interest and other related debt costs during the construction period of our LNG terminal. 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 significant impairments related to property, plant and equipment for 2013, 2012 or 2011. 

Revenue Recognition

LNG regasification capacity reservation fees are recognized as revenue over the term of the respective terminal use agreements ("TUAs"). Advance capacity reservation fees are initially deferred and amortized over a 10-year period as a reduction of a customer's regasification capacity reservation fees payable under its TUA.  For a discussion of revenue from related parties, please read Note 11—"Related Party Transactions".  The retained 2% of LNG delivered for each customer's account at our LNG terminal is recognized as revenue as we perform the services set forth in each customer's TUA.

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 Consolidated 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 Consolidated Financial Statements.

At December 31, 2013, the tax basis of our assets and liabilities was $445.7 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 permitted 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 November 2006, we and Cheniere entered into a state tax sharing agreement. 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 January 1, 2008.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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 Consolidated Balance Sheets and are being amortized to interest expense 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.

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

Derivatives

We use derivative instruments from time to time to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminal. We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 7—"Financial Instruments" of our Notes to Consolidated Financial Statements.

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 consolidated balance sheet as assets or liabilities unless they satisfy the normal purchases and sales exception criteria. 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 commodity prices and interest rates change.

Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are recognized currently in earnings. Gains or losses in the positions to mitigate the price risk from future purchases of natural gas to be utilized as fuel to operate our LNG terminal are classified as derivative gain (loss) on our Consolidated Statements of Operations.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with an investment grade financial institution. Collateral deposited for such contracts is recorded as an other current asset and netted within the derivative fair value. 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 certain long-term TUAs with unaffiliated third parties for regasification capacity at our LNG terminal. We are dependent on the respective counterparties' creditworthiness and their willingness to perform under their respective TUAs. We have mitigated this credit risk by securing TUAs for a significant portion of our regasification capacity with creditworthy third-party customers with a minimum Standard & Poor's rating of AA.

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated 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 consolidated 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 3—RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents consists of cash and cash equivalents that are contractually restricted as to usage or withdrawal, as follows:

Senior Notes Debt Service Reserve

We have consummated private offerings of an aggregate principal amount of $1,665.5 million, before discount, of 7.50% Senior Secured Notes due 2016 (the "2016 Notes") and $420.0 million of 6.50% Senior Secured Notes due 2020 (the "2020 Notes") (See Note 10—"Long-Term Debt"). Collectively, the 2016 Notes and the 2020 Notes are referred to as the "Senior Notes." Under the Senior Notes Indentures, except for permitted tax distributions, we may not make distributions until certain conditions are satisfied, including that there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Senior Notes Indentures.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

As of December 31, 2013 and 2012, we classified $15.0 million and $17.4 million, respectively, as current restricted cash and cash equivalents for the payment of interest due within twelve months. As of both December 31, 2013 and 2012, we classified the permanent debt service reserve fund of $76.1 million as non-current restricted cash and cash equivalents. These cash accounts are controlled by a collateral trustee, and, therefore, are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.

NOTE 4—LNG INVENTORY

LNG inventory is recorded at cost and is subject to lower of cost or market ("LCM") adjustments at the end of each period. LNG inventory cost is determined using the average cost method. Recoveries of losses resulting from interim period LCM adjustments are recorded when market price recoveries occur on the same inventory in the same fiscal year. These recoveries are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. As of December 31, 2013 and 2012, we had $10.4 million and $2.6 million, respectively, of LNG inventory on our Consolidated Balance Sheets. During the years ended December 31, 2013, 2012 and 2011, we recognized $0.2 million, $0.2 million and $0.4 million, respectively, as a result of LCM adjustments to our LNG inventory.

We require our TUA customers to maintain the cryogenic readiness of our regasification facilities at the Sabine Pass LNG Terminal by purchasing, from time to time, LNG cargoes which we retain as inventory. We remit all proceeds to our TUA customers as the inventory boils off and is sold. As of December 31, 2013 and 2012, we recorded $4.6 million and $2.3 million, respectively, as current liabilities representing the remaining amounts owed to our TUA customers. As of December 31, 2013 and 2012, we recorded $3.9 million and $1.0 million, respectively, as current liabilities—affiliate representing the remaining amounts owed to our affiliate TUA customers.

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	$	1,642,007		$	1,641,722
LNG terminal construction-in-process	9			256
LNG site and related costs, net	149			156
Accumulated depreciation	(208,729		)	(166,539		)
Total LNG terminal costs, net	1,433,436			1,475,595
Fixed assets
Computer and office equipment	424			368
Vehicles	599			550
Machinery and equipment	1,189			1,172
Other	697			759
Accumulated depreciation	(2,523		)	(2,270		)
Total fixed assets, net	386			579
Property, plant and equipment, net	$	1,433,822		$	1,476,174

Depreciation expense related to our LNG terminal totaled $42.2 million, $42.1 million and $42.6 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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

Components	Useful life (yrs)
LNG storage tanks	50
Marine berth, electrical, facility and roads	35
Regasification processing equipment (recondensers, vaporization and vents)	30
Sendout pumps	20
Others	15-30

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, we amortized $4.2 million, $4.4 million and $4.4 million, respectively, of debt issuance costs. In addition, for the years ended December 31, 2013, 2012 and 2011, we wrote off zero, $1.5 million, and zero, respectively, of debt issuance costs related to early extinguishments of debt.

As of December 31, 2013, we had recorded $16.9 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
2016 Notes	$	30,057	10.1 years	$	(21,099	)	$	8,958
2020 Notes	9,290		8.1 years	(1,377		)	7,913
Total	$	39,347		$	(22,476	)	$	16,871

NOTE 7—FINANCIAL INSTRUMENTS

Derivative Instruments

We have entered into certain instruments to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminal ("Fuel Derivatives").

The following table (in thousands) shows the fair value of our derivative assets and liabilities that are required to be measured at fair value on a recurring basis as of December 31, 2013 and 2012, which are classified as other current assets and other current liabilities in our Consolidated 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
Fuel Derivatives asset (liability)	$	—	$	27	$	—	$	27	$	—	$	(98	)	$	—	$	(98	)

The estimated fair values of our Fuel 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. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Commodity Derivatives

We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption.  For transactions in which we have elected the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Statements of Operations until the period of delivery. For certain of our Fuel Derivative instruments. 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 Fuel Derivatives are in an asset position. Except for the fuel hedges with our affiliate described below, 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 $0.7 million and $0.8 million 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.

During the second quarter of 2013, we began to enter into forward contracts under an International Swaps and Derivatives Association master agreement with Cheniere Marketing, LLC ("Cheniere Marketing"), a wholly owned subsidiary of Cheniere, to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our terminal. We elected to account for these physical hedges of future fuel purchases as normal purchase normal sale transactions, exempt from fair value accounting. We had not posted collateral with Cheniere Marketing for such forward contracts as of December 31, 2013.

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

		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2013		December 31, 2012
Fuel Derivatives asset (liability)	Prepaid expenses and other	$	27	$	(98	)

The following table (in thousands) shows the changes in the fair value and settlements of our Fuel Derivatives recorded in derivative gain (loss) on our Consolidated Statements of Operations during the years ended December 31, 2013, 2012, and 2011:

	Year Ended December 31,
	2013		2012			2011
Fuel Derivatives gain (loss) (1)	$	182	$	(622	)	$	(2,251	)

(1)Excludes settlements of hedges of the exposure to price risk attributable to future purchases of natural gas to be utilized

as fuel to operate our terminal for which we have elected the normal purchase normal sale exemption from derivative accounting.

Balance Sheet Presentation

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

	Gross Amounts Recognized			Gross Amounts Offset in Our Consolidated Balance Sheets			Net Amounts Presented in Our Consolidated Balance Sheets		Gross Amounts not Offset in Our Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)									Derivative Instrument		Cash Collateral Received (Paid)		Net Amount
As of December 31, 2013:
Fuel Derivatives	$	27		$	—		$	27	$	—	$	—	$	27
As of December 31, 2012:
Fuel Derivatives	(98		)	(98		)	—		—		—		—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Other Financial Instruments

The estimated fair value of our other financial instruments, including those financial instruments for which the fair value option was not elected, are set forth in the table below.  The carrying amounts reported on our Consolidated Balance Sheets for cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, interest receivable and accounts payable approximate fair value due to their short-term nature.

Other Financial Instruments (in thousands):

	December 31, 2013				December 31, 2012
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
2016 Notes, net of discount	$	1,651,807	$	1,868,607	$	1,647,113	$	1,824,177
2020 Notes	420,000		432,600		420,000		437,850

(1) The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on December 31, 2013 and 2012, as applicable.

NOTE 8—ACCRUED LIABILITIES

As of December 31, 2013 and 2012, accrued liabilities (including amounts due to affiliates) consisted of the following (in thousands): 

	December 31,
	2013		2012
Interest and related debt fees	$	14,959	$	16,173
LNG terminal costs	1,612		977
Due to affiliate	17,756		2,525
Other	4,582		2,319
Total accrued liabilities (including affiliates)	$	38,909	$	21,994

NOTE 9—DEFERRED REVENUE

Advance Capacity Reservation Fee

In November 2004, Total Gas & Power North America, Inc. ("Total") paid us a nonrefundable advance capacity reservation fee of $10.0 million in connection with the reservation of approximately 1.0 Bcf/d of LNG regasification capacity at our LNG terminal. An additional advance capacity reservation fee payment of $10.0 million was paid by Total to us in April 2005. The advance capacity reservation fee payments are being amortized as a reduction of Total's regasification capacity reservation fee under its TUA over a 10-year period beginning with the commencement of its TUA on April 1, 2009. As a result, we recorded the advance capacity reservation fee payments that we received, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

In November 2004, we also entered into a TUA to provide Chevron U.S.A. Inc. ("Chevron") with approximately 0.7 Bcf/d of LNG regasification capacity at our LNG terminal. In December 2005, Chevron exercised its option to increase its reserved capacity by approximately 0.3 Bcf/d to approximately 1.0 Bcf/d, making advance capacity reservation fee payments to us totaling $20.0 million. The advance capacity reservation fee payments are being amortized as a reduction of Chevron's regasification capacity reservation fee under its TUA over a 10-year period beginning with the commencement of its TUA on July 1, 2009. As a result, we recorded the advance capacity reservation fee payments that we received, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

As of December 31, 2013, we had recorded $4.0 million and $17.5 million as current and non-current deferred revenue on our Consolidated Balance Sheets, respectively, related to the Total and Chevron advance capacity reservation fees. As of December 31, 2012, we had recorded $4.0 million and $21.5 million as current and non-current deferred revenue on our Consolidated Balance Sheets, respectively, related to the Total and Chevron advance capacity reservation fees.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

TUA Payments

Following the achievement of commercial operability of our LNG terminal in September 2008, we began receiving capacity reservation fee payments from Cheniere Marketing under its TUA. Effective July 1, 2010, Cheniere Marketing assigned its existing TUA with us to Cheniere Investments, including all of its rights, titles, interests, obligations and liabilities in and under the TUA. Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction") obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, we, Sabine Pass Liquefaction and Cheniere Investments entered into a terminal use rights assignment and agreement ("TURA") pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to us. Cheniere Partners has guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA. As of December 31, 2013 and 2012, we had recorded $21.1 million and $21.0 million, respectively, as current deferred revenue—affiliate related to Cheniere Investments monthly advance capacity reservation fee payment.

Total and Chevron are obligated to make monthly TUA payments to us in advance of the month of service. These monthly payments are recorded to current deferred revenue in the period cash is received and are then recorded as revenue in the next month when the TUA service is performed. As of December 31, 2013 and 2012, we had recorded $21.2 million and $21.1 million, respectively, as current deferred revenue on our Consolidated Balance Sheets related to Total's and Chevron's monthly TUA payments.

Cooperative Endeavor Agreements

In July 2007, we executed Cooperative Endeavor Agreements ("CEAs") with various Cameron Parish, Louisiana taxing authorities that allow them to accelerate certain of our property tax payments scheduled to begin in 2019. This ten-year initiative represents an aggregate commitment of up to $25.0 million, and we will make resources available to the Cameron Parish taxing authorities on an accelerated basis in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for our advance payments of annual ad valorem taxes, Cameron Parish will grant us a dollar for dollar credit against future ad valorem taxes to be levied against our LNG terminal starting in 2019. In September 2007, we entered into an agreement with Cheniere Marketing, pursuant to which Cheniere Marketing would pay us additional TUA revenues equal to any and all amounts payable under the CEAs in exchange for a similar amount of credits against future TUA payments it would owe us under its TUA starting in 2019. In June 2010, Cheniere Marketing assigned its TUA to Cheniere Investments and concurrently entered into a variable capacity rights agreement ("VCRA"), allowing Cheniere Marketing to utilize Cheniere Investments' capacity under the TUA after the assignment. In July 2012, Cheniere Investments entered into an amended and restated VCRA with Cheniere Marketing in order for Cheniere Investments to utilize during construction of the Liquefaction Project the capacity rights granted under the TURA. Cheniere Marketing will continue to fund the CEAs during the term of the amended and restated VCRA and, in exchange, Cheniere Marketing will receive any future credits.

These advance tax payments were recorded to other assets, and payments from Cheniere Marketing that we utilized to make

the ad valorem tax payments were recorded as deferred revenue—affiliate. As of December 31, 2013 and 2012, we had $17.2 million and $14.7 million, respectively, of other non-current assets and non-current deferred revenue—affiliate resulting from accelerated ad valorem tax payments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 10—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
2016 Notes	$	1,665,500		$	1,665,500
2020 Notes	420,000			420,000
Total long-term debt	2,085,500			2,085,500
Long-term debt discount
2016 Notes	(13,693		)	(18,387		)
Total long-term debt, net of discount	$	2,071,807		$	2,067,113

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 (including related parties):
2016 Notes	$	1,665,500	$	—	$	1,665,500	$	—	$	—
2020 Notes	420,000		—		—		—		420,000
Debt (including related parties)	$	2,085,500	$	—	$	1,665,500	$	—	$	420,000

Senior Notes

As of December 31, 2013 and 2012, we had an aggregate principal amount of $1,665.5 million, before discount, of the 2016 Notes and $420.0 million of the 2020 Notes outstanding. Borrowings under the 2016 Notes and 2020 Notes bear interest at a fixed rate of 7.50% and 6.50%, respectively. The terms of the 2016 Notes and 2020 Notes are substantially similar. Interest on the 2016 Notes and 2020 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 our equity interests and substantially all of our operating assets.

We may redeem some or all of our 2016 Notes at any time, and from time to time, at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:

•1.0% of the principal amount of the 2016 Notes; or

• the excess of: a) the present value at such redemption date of (i) the redemption price of the 2016 Notes plus (ii) all required interest payments due on the 2016 Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over b) the principal amount of the 2016 Notes, if greater.

We may redeem all or part of the 2020 Notes at any time on or after November 1, 2016, at fixed redemption prices specified in the indenture governing the 2020 Notes, plus accrued and unpaid interest, if any, to the date of redemption. We may also, at our option, redeem all or part of the 2020 Notes at any time prior to November 1, 2016, at a "make-whole" price set forth in the indenture governing the 2020 Notes, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, we may redeem up to 35% of the aggregate principal amount of the 2020 Notes at a redemption price of 106.5% of the principal amount of the 2020 Notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date, in an amount not to exceed the net proceeds of one or more completed equity offerings as long as we redeem the 2020 Notes within 180 days of the closing date for such equity offering and at least 65% of the aggregate principal amount of the 2020 Notes originally issued remains outstanding after the redemption.

Under the Senior Notes Indentures, except for permitted tax distributions, we may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

in the Senior Notes Indentures. During the years ended December 31, 2013, 2012 and 2011, we made distributions of $348.9 million, $333.5 million and $313.6 million, respectively, after satisfying all the applicable conditions in the Senior Notes Indentures.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 11—RELATED PARTY TRANSACTIONS

As of December 31, 2013 and 2012, we had $4.0 million and $1.0 million of advances to affiliates, respectively. In addition, we have entered into the following related party transactions:

Terminal Use Agreement

Sabine Pass Liquefaction obtained approximately 2.0 Bcf/d of regasification capacity under a TUA with us as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with us. Sabine Pass Liquefaction is obligated to make monthly capacity payments to us aggregating approximately $250 million per year, continuing until at least 20 years after Sabine Pass Liquefaction delivers its first commercial cargo at Sabine Pass Liquefaction's facilities under construction, which Cheniere Partners has reported may occur as early as late 2015. We entered into a TURA with Sabine Pass Liquefaction and Cheniere Investments pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to us. Cheniere Investments' right to use capacity at the Sabine Pass LNG terminal will be reduced as each of Trains 1 through 4 reaches commercial operations. 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 Sabine Pass Liquefaction's obligations under the TUA and the obligations of Cheniere Investments under the TURA.

Service Agreements

We have entered into a long-term operation and maintenance agreement (the "O&M Agreement") with Cheniere Investments pursuant to which we receive all necessary services required to operate and maintain our LNG receiving terminal. We are required to pay a fixed monthly fee of $130,000 (indexed for inflation) under the O&M Agreement, and the counterparty is entitled to a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between us and the counterparty at the beginning of each operating year. In addition, we are required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses.

We have entered into a long-term management services agreement (the "MSA Agreement") with Cheniere LNG Terminals, Inc. ("Cheniere Terminals"), a wholly owned subsidiary of Cheniere, pursuant to which Cheniere Terminals manages the operation of our LNG receiving terminal, excluding those matters provided for under the O&M Agreement. We are required to pay Cheniere Terminals a monthly fixed fee of $520,000 (indexed for inflation).

During the years ended December 31, 2013, 2012, and 2011, we recorded general and administrative expense—affiliate of $8.5 million, $8.4 million, and $8.1 million, respectively, under the foregoing service agreements.

Agreement to Fund Our Cooperative Endeavor Agreements

In July 2007, we executed CEAs as discussed in Note 9—"Deferred Revenues". These advance tax payments were recorded to other assets, and payments from Cheniere Marketing that we utilized to make the ad valorem tax payments were recorded as deferred revenue—affiliate. As of December 31, 2013 and 2012, we had $17.2 million and $14.7 million of other non-current assets and non-current deferred revenue—affiliate resulting from our ad valorem tax payments and the advance tax payments received from Cheniere Marketing, respectively.

Contracts for Sale and Purchase of Natural Gas and LNG

We are able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these agreements, we purchase natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase cost paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing in respect of the receipt, purchase, and delivery of the natural gas or LNG to our LNG terminal.

We recorded $3.3 million, $2.8 million and $4.2 million of natural gas and LNG purchased from Cheniere Marketing under this agreement in the years ended December 31, 2013, 2012 and 2011, respectively. We recorded $14.7 million, $2.8 million and

40

SABINE PASS LNG, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

zero for natural gas sold to Cheniere Marketing under this agreement in the years ended December 31, 2013, 2012 and 2011, respectively.

LNG Terminal Export Agreement

In January 2010, we and Cheniere Marketing entered into an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from our LNG terminal.  We recorded revenues—affiliate of zero, $0.3 million and $0.3 million pursuant to this agreement in the years ended December 31, 2013, 2012 and 2011, respectively.

Pipeline Compressor Agreement

In August 2010, we entered into an agreement with Cheniere Investments, under which Cheniere Investments reimburses us for a portion of the costs of installing, operating and maintaining pipeline compression equipment at our LNG terminal. During the years ended December 31, 2013, 2012 and 2011, we recorded revenues—affiliate from Cheniere Investments of $0.6 million, $0.1 million and $0.4 million, respectively, pursuant to this agreement.

Tug Boat Lease Sharing Agreement

In connection with our tug boat lease, as discussed in Note 12—"Leases", Sabine Pass Tug Services, LLC, our wholly owned subsidiary ("Tug Services"), entered into a tug sharing agreement with Cheniere Marketing to provide its LNG cargo vessels with tug boat and marine services at our LNG terminal. Tug Services recorded revenues—affiliate from Cheniere Marketing of $2.8 million, $2.8 million, and $2.7 million pursuant to this agreement in the years ended December 31, 2013, 2012 and 2011, respectively.

LNG Site Sublease Agreement

In June 2012, we entered into an agreement with Sabine Pass Liquefaction to sublease a portion of our terminal site for its liquefaction project. The annual sublease payment is $0.5 million. The initial term of the sublease expires on December 31, 2034, with options to renew for five 10-year extensions with similar terms as the initial term. The annual sublease payment will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreement. We recognized $0.5 million and $0.3 million of sublease revenue from Sabine Pass Liquefaction as a credit to operating and maintenance expense—affiliate on our Consolidated Statements of Operations in the years ended December 31, 2013 and 2012, respectively.

NOTE 12—LEASES

During the years ended December 31, 2013, 2012 and 2011, we recognized rental expense for all operating leases of $8.8 million, $9.4 million, and $9.2 million, respectively.

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

Year ending December 31,	Lease Payments(2) (3)
2014	$	9,438
2015	9,533
2016	9,645
2017	9,764
2018	2,397
Later years (1)	212,811
Total minimum payments required	$	253,588

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

(2) Lease payments for our land leases represent our land lease payment obligations and do not take into account the $34.3 million sublease payments we will receive from Sabine Pass Liquefaction, as discussed in Note 11—"Related Party Transactions".

41

SABINE PASS LNG, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(3) Lease payments for our tug boat lease represent our lease payment obligation and do not take into account the $112.5 million sublease payments we will receive from our customers that effectively offset these lease payment obligations, as discussed below.

Land Leases

In January 2005, we exercised our options and entered into three land leases for the site of our LNG terminal. The leases have an initial term of 30 years, with options to renew for six10-year extensions with similar terms as the initial term. In February 2005, two of the three leases were amended, thereby increasing the total acreage under lease to 853 acres and increasing the annual lease payments to $1.5 million.  In July 2012, we entered into an additional land lease, thereby increasing the total acreage under lease to 883 acres. The annual lease payment will be adjusted for inflation every five years based on a consumer price index, as defined in the lease agreements. We recognized $1.8 million, $1.5 million and $1.8 million of site lease expense on our Consolidated Statements of Operations in 2013, 2012 and 2011, respectively,

Tug Boat Lease

In the second quarter of 2009, we acquired a lease (the "Tug Agreement") for the use of tug boats and marine services at our LNG terminal as a result of our purchase of Sabine Pass Tug Services, LLC.  The term of the Tug Agreement commenced in January 2008 for a period of 10 years, with an option to renew two additional, consecutive terms of five years each.  We have determined that the Tug Agreement contains a lease for the tugs specified in the Tug Agreement.  In addition, we have concluded that the tug lease contained in the Tug Agreement is an operating lease, and as such, the equipment component of the Tug Agreement will be charged to expense over the term of the Tug Agreement as it becomes payable.

In connection with this lease acquisition, Sabine Pass Tug Services, LLC entered into a tug sharing agreement (the "Tug Sharing Agreement") with Chevron, Total and Cheniere Marketing to provide their LNG cargo vessels with tug boat and marine services at our LNG terminal and effectively offset the cost of the Tug Agreement. The Tug Sharing Agreement provides for each of our customers to pay Sabine Pass Tug Services, LLC an annual service fee.

NOTE 13—COMMITMENTS AND CONTINGENCIES

LNG Commitments

We have entered into TUAs with Total, Chevron and Sabine Pass Liquefaction to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at our LNG terminal. See Note 11—"Related Party Transactions" for information regarding such agreements.

Services Agreements

We have entered into certain services agreements with affiliates. See Note 11—"Related Party Transactions" for information regarding such agreements.

Other Commitments

State Tax Sharing Agreement

In November 2006, we and Cheniere entered into a state tax sharing agreement. 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 January 1, 2008.

Cooperative Endeavor Agreements

In July 2007, we executed CEAs with various Cameron Parish, Louisiana taxing authorities. See Note 11—"Related Party Transactions" for information regarding such agreements.

Legal Proceedings

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2013, there were no threatened or pending legal matters that would have a material impact on our consolidated results of operations, financial position or cash flows.

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS

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

	Year Ended December 31,
	2013		2012		2011
Cash paid during the year for interest, net of amounts capitalized	$	153,350	$	159,998	$	164,513

42

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

SUMMARIZED QUARTERLY FINANCIAL DATA

(unaudited)

Quarterly Financial Data—(in thousands)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year ended December 31, 2013:
Revenues	$	129,880	$	130,413	$	130,919	$	130,340
Income from operations	101,576		99,210		102,203		102,115
Net income	61,854		58,556		61,812		62,071
Year ended December 31, 2012:
Revenues	$	130,731	$	129,928	$	129,751	$	133,474
Income from operations	108,328		106,493		102,693		109,854
Net income	64,074		63,335		59,525		25,871

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Based on their evaluation as of the end of the fiscal year ended December 31, 2013, our general partner's principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (i) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (ii) recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms.

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

Management Report on Internal Control Over Financial Reporting

Our Management's Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements on page 23 and is incorporated herein by reference.

ITEM 9B. OTHER INFORMATION

Compliance Disclosure

Pursuant to Section 13(r) of the Exchange Act, if during the fiscal year ended December 31, 2013, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our Annual Report on Form 10-K as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 ("ITRA"). During the fiscal year ended December 31, 2013, we did not engage in any transactions with Iran or with persons or entities related to Iran.

Blackstone CQP Holdco LP, an affiliate of The Blackstone Group L.P. ("Blackstone"), is a holder of approximately 29% of the outstanding equity interests of Cheniere Partners and has three representatives on the Board of Directors of Cheniere Partners' general partner. Accordingly, Blackstone may be deemed an "affiliate" of Cheniere Partners, as that term is defined in Exchange Act Rule 12b-2. We have received notice from Blackstone that it may include in its Annual Report on Form 10-K for the fiscal year ended December 31, 2013 disclosures pursuant to ITRA regarding one of its portfolio companies that may be deemed to be an affiliate of Blackstone. Because of the broad definition of "affiliate" in Exchange Act Rule 12b-2, this portfolio company of Blackstone, through Blackstone's ownership of Cheniere Partners, may also be deemed to be an affiliate of ours.

We have received notice from Blackstone that Travelport Limited ("Travelport") has engaged in the following activities: as part of its global business in the travel industry, Travelport provides certain passenger travel-related GDS and airline IT services to Iran Air and airline IT services to Iran Air Tours. The gross revenues and net profits attributable to such activities during the quarter ended December 31, 2013 have not been reported by Travelport. Blackstone has informed us that Travelport intends to continue these business activities with Iran Air and Iran Air Tours as such activities are either exempt from applicable sanctions prohibitions or specifically licensed by OFAC.

In our Form 10-Q reports for the quarterly periods ended on March 31, 2013, June 30, 2013 and September 30, 2013, we disclosed, under "Item 5. Other Information--Compliance Disclosure" in each such report, as amended, activities as required by

44

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

SUMMARIZED QUARTERLY FINANCIAL DATA

(unaudited)

Section 13(r) of the Exchange Act as transactions or dealings with the government of Iran that have not been specifically authorized by a U.S. federal department or agency. Such disclosures are incorporated herein by reference.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF OUR GENERAL PARTNER AND CORPORATE GOVERNANCE

Omitted pursuant to Instruction I of Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

Omitted pursuant to Instruction I of Form 10-K.

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

Omitted pursuant to Instruction I of Form 10-K.

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

Omitted pursuant to Instruction I of Form 10-K.

45

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Ernst & Young LLP served as our independent auditor for the fiscal years ended December 31, 2013 and 2012. The following table sets forth the fees paid to Ernst & Young LLP for professional services rendered for 2013 and 2012:

	Ernst & Young LLP
	Fiscal 2013		Fiscal 2012
Audit Fees	$	979,255	$	652,620
Audit-Related Fees	—		96,400
Total	$	979,255	$	749,020

Audit Fees—Audit fees for 2013 and 2012 include attestation services and review of documents filed with the SEC in addition to audit, review and all other services performed to comply with generally accepted auditing standards.

Audit-Related Fees—Audit-related fees for 2012 include services rendered in connection with the offering of the 2020 Notes.

There were no tax or other fees in 2013 and 2012.

Auditor Pre-Approval Policy

Our general partner is not a public company and it is not listed on any stock exchange. As a result, it is not required to, and does not, have an independent audit committee, a financial expert or a majority of independent directors. The board of directors of our general partner has approved all audit and non-audit services to be provided by the independent accountants and the fees for such services during the fiscal years ended December 31, 2013 and 2012.

PART IV

ITEM 15.     EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements and Exhibits

(1) Financial Statements—Sabine Pass LNG, L.P.: 

Management's Report to the Partners of Sabine Pass LNG, L.P.	23
Report of Independent Registered Public Accounting Firm—Ernst & Young LLP	24
Consolidated Balance Sheets	25
Consolidated Statements of Operations	26
Consolidated Statements of Partners' Deficit	27
Consolidated Statements of Cash Flows	28
Notes to Consolidated Financial Statements	29
Supplemental Information to Consolidated Financial Statements	43

(2) Financial Statement Schedules:

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

46

(3) Exhibits:

Exhibit No.	Description
3.1*	Certificate of Limited Partnership of Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 3.1 to Sabine Pass LNG L.P.'s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on November 22, 2006)
3.2*	Sixth Amended and Restated Agreement of Limited Partnership of Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 3.1 to Sabine Pass LNG L.P.'s Quarterly Report on Form 10-Q (SEC File No. 333-138916), filed on August 6, 2010)
4.1*	Form of general partner interest certificate (Incorporated by reference to Exhibit 4.5 to Sabine Pass LNG L.P.'s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on November 22, 2006)
4.2*	Form of limited partner interest certificate (Incorporated by reference to Exhibit 4.6 to Sabine Pass LNG L.P.'s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on November 22, 2006)
4.3*	Indenture, dated as of November 9, 2006, between Sabine Pass LNG, L.P., as issuer, and The Bank of New York, as trustee (Incorporated by reference to Exhibit 4.1 to Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
4.5*	Form of 7.50% Senior Secured Note due 2016 (Included as Exhibit A1 to Exhibit 4.3 above)
4.6*	Form of 7 1/2% Senior Secured Note due 2016 (Incorporated by reference to Exhibit 4.1 to the Sabine Pass LNG, L.P.'s Current Report on Form 8-K (SEC File No. 333-138916), filed on September 15, 2008)
4.7*	Indenture, dated as of October 16, 2012, by and among Sabine Pass LNG, L.P., the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to Sabine Pass LNG, L.P.'s Current Report on Form 8-K (SEC File No. 333-138916), filed on October 19, 2012)
4.8*	Form of 6.5% Senior Secured Note due 2020 (Included as Exhibit A1 to Exhibit 4.7 above)
10.1*	LNG Terminal Use Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.2*	Amendment of LNG Terminal Use Agreement, dated January 24, 2005, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.40 to Cheniere Energy, Inc.'s Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 10, 2005)
10.3*	Amendment of LNG Terminal Use Agreement, dated June 15, 2010, by and between Total Gas & Power North America, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 6, 2010)
10.4*	Letter Agreement, dated September 11, 2012, between Total Gas & Power North America, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.'s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.5*	Second Amended and Restated Terminal Use Agreement, dated as of July 31, 2012, between Sabine Pass LNG, L.P. and Sabine Pass Liquefaction, LLC (Incorporated by reference to Exhibit 10.1 to Sabine Pass LNG, L.P.'s Current Report on Form 8-K (SEC File No. 333-138916), filed on August 6, 2012)
10.6*	Letter Agreement, dated May 28, 2013, by and between Sabine Pass Liquefaction, LLC and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to Sabine Pass LNG, L.P.'s Quarterly Report on Form 10-Q (SEC File No. 333-138916), filed on August 2, 2013)
10.7*	Guarantee Agreement, dated as of July 31, 2012, by Cheniere Energy Partners, L.P. in favor of Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to Sabine Pass LNG, L.P.'s Current Report on Form 8-K (SEC File No. 333-138916), filed on August 6, 2012)
10.8*	Omnibus Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)

47

10.9*	Guaranty, dated as of November 9, 2004, by Total S.A. in favor of Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.3 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.10*	LNG Terminal Use Agreement, dated November 8, 2004, between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.4 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.11*	Amendment to LNG Terminal Use Agreement, dated December 1, 2005, by and between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.28 to Sabine Pass LNG, L.P.'s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on November 22, 2006)
10.12*	Amendment of LNG Terminal Use Agreement, dated June 16, 2010, by and between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.3 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 6, 2010)
10.13*	Omnibus Agreement, dated November 8, 2004, between Chevron U.S.A., Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.14*	Guaranty Agreement, dated as of December 15, 2004, from ChevronTexaco Corporation to Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.12 to Sabine Pass LNG, L.P.'s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on November 22, 2006)
10.15*	Cooperative Endeavor Agreement & Payment in Lieu of Tax Agreement, dated October 23, 2007 (amending the Amended and Restated Terminal Use Agreement, dated November 9, 2006, by and between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P.) (Incorporated by reference to Exhibit 10.7 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2007)
10.16*	LNG Lease Agreement, dated June 24, 2008, between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.7 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 11, 2008)
10.17*	Collateral Trust Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New York, as collateral trustee, Sabine Pass LNG-GP, Inc. and Sabine Pass LNG-LP, LLC (Incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.18*	Additional Secured Debt Designation, dated September 15, 2008, executed by Sabine Pass LNG, L.P. and acknowledged by The Bank of New York Mellon, as collateral trustee (Incorporated by reference to Exhibit 10.1 to the Sabine Pass LNG, L.P.'s Current Report on Form 8-K (SEC File No. 333-138916), filed on September 15, 2008)
10.19*	Amended and Restated Parity Lien Security Agreement, dated November 9, 2006, by and between Sabine Pass LNG, L.P. and The Bank of New York, as collateral trustee (Incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.20*	Third Amended and Restated Multiple Indebtedness Mortgage, Assignment of Rents and Leases and Security Agreement, dated November 9, 2006, between Sabine Pass LNG, L.P. and The Bank of New York, as collateral trustee (Incorporated by reference to Exhibit 10.3 to Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.21*	Amended and Restated Parity Lien Pledge Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., Sabine Pass LNG-GP, Inc., Sabine Pass LNG-LP, LLC and The Bank of New York, as collateral trustee (Incorporated by reference to Exhibit 10.4 to Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.22*	Security Deposit Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New York, as collateral trustee, and The Bank of New York, as depositary agent (Incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.23*	Amended and Restated Operation and Maintenance Agreement (Sabine Pass LNG Facilities), dated as of August 9, 2012, by and among Cheniere LNG O&M Services, LLC, Cheniere Energy Partners GP, LLC and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.5 to Cheniere Energy Partners, L.P.'s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)

48

10.24*	Assignment and Assumption Agreement (Sabine Pass LNG O&M Agreement), dated as of November 20, 2013, by and between Cheniere Energy Partners GP, LLC and Cheniere Energy Investments, LLC (Incorporated by reference to Exhibit 10.75 to Cheniere Energy Partners LP Holdings, LLC's Registration Statement on Form S-1 (SEC File No. 333-191298), filed on December 2, 2013)
10.25*	Amended and Restated Management Services Agreement, dated as of August 9, 2012, by and between Cheniere LNG Terminals, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.6 to Cheniere Energy Partners, L.P.'s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

* Incorporated by reference

49

SIGNATURES

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

SABINE PASS LNG, L.P.
By:	Sabine Pass LNG-GP, LLC,
	Its general partner
By:	/s/    Charif Souki
	Charif Souki Chief Executive Officer
Date:	February 21, 2014

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

Signature	Title	Date
/s/    Charif Souki	Chief Executive Officer and Manager  (Principal Executive Officer)	February 21, 2014
Charif Souki
/s/    R. Keith Teague	President (Principal Operating Officer)	February 21, 2014
R. Keith Teague
/s/    Michael J. Wortley	Chief Financial Officer (Principal Financial Officer)	February 21, 2014
Michael J. Wortley
/s/    Leonard Travis	Chief Accounting Officer (Principal Accounting Officer)	February 21, 2014
Leonard Travis
/s/    Victor A. Duva	Manager	February 21, 2014
Victor A. Duva

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