10-K 1 cei2013form10k.htm 10-K CEI 2013 Form 10K


 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
  For the fiscal year ended December 31, 2013
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
  For the transition period from              to             
Commission File No. 001-16383
CHENIERE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware
95-4352386
(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: 
Common Stock, $ 0.003 par value
NYSE MKT
(Title of Class)
(Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act: None 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  x  No  o 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes  o  No  x 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x  No  o 
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  x
Accelerated filer  o
Non-accelerated filer  o
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 registrant's Common Stock held by non-affiliates of the registrant was approximately $6.2 billion as of June 28, 2013. 
238,106,267 shares of the registrant's Common Stock were outstanding as of January 31, 2014
Documents incorporated by reference: The definitive proxy statement for the registrant's Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant's fiscal year) is incorporated by reference into Part III.


 



CHENIERE ENERGY, INC.
TABLE OF CONTENTS


 
 
 
 





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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 that we expect to commence or complete construction of our proposed liquefied natural gas ("LNG") terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions thereof, by certain dates, or at all;
statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
statements regarding any financing transactions or arrangements, or ability to enter into such transactions;
statements relating to the construction of our natural gas liquefaction trains ("Trains"), including statements concerning the engagement of any engineering, procurement and construction ("EPC") contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;
statements regarding any 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 commercial contracts, construction contracts and other contracts;
statements regarding our planned construction of additional Trains, including the financing of such Trains;
statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections or objectives, including anticipated revenues and capital expenditures, any or all of which are subject to change;
statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
statements regarding our anticipated LNG and natural gas marketing activities; and 
any other statements that relate to non-historical or future information.
All of these types of statements, other than statements of historical fact, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expect," "plan," "project," "intend," "anticipate," "believe," "estimate," "predict," "potential," "pursue," "target," "continue," the negative of such terms or other comparable terminology. The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this annual report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors described in this annual report and in the other reports and other information that we file with the Securities and Exchange Commission ("SEC"). These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.





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DEFINITIONS
 
As commonly used in the liquefied natural gas industry, to the extent applicable, and as used in this annual report, the following terms have the following meanings: 
Bcf/d means billion cubic feet per day;
Bcf/yr means billion cubic feet per year;
Bcfe means billion cubic feet equivalent;
Dthd means dekatherms per day;
EPC means engineering, procurement and construction;
Henry Hub means the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange's Henry Hub natural gas futures contract for the month in which a relevant cargo's delivery window is scheduled to begin;
LNG means liquefied natural gas, a product of natural gas consisting primarily of methane (CH4) that is in liquid form at near atmospheric pressure;
MMBtu means million British thermal units, an energy unit;
MMBtu/d means million British thermal units per day;
MMBtu/yr means million British thermal units per year;
mtpa means million metric tonnes per annum;
SPA means an LNG sale and purchase agreement;
Tcf means trillion cubic feet;
Tcf/yr means trillion cubic feet per year;
Train means a compressor train used in the industrial process to convert natural gas into LNG; and
TUA means terminal use agreement.
 
PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General
 
Cheniere Energy, Inc. (NYSE MKT: LNG), a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Energy Partners, L.P. ("Cheniere Partners") (NYSE MKT: CQP), which is a publicly traded partnership that we created in 2007. We own 100% of the general partner interest in Cheniere Partners and 84.5% of Cheniere Energy Partners LP Holdings, LLC ("Cheniere Holdings") (NYSE MKT: CQH), which owns a 55.9% limited partner interest in Cheniere Partners.

In 2013, we formed Cheniere Holdings, a publicly traded limited liability company, to hold our limited partner interests in Cheniere Partners. In December 2013, Cheniere Holdings completed an initial public offering of 36.0 million common shares at $20.00 per common share (the "Cheniere Holdings Offering").
  
The Sabine Pass LNG terminal is located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal has regasification facilities owned by Cheniere Partners' wholly owned subsidiary, Sabine Pass LNG, L.P. ("Sabine Pass LNG"), 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 regasification capacity of approximately 4.0 Bcf/d. Cheniere Partners is developing and constructing natural gas liquefaction facilities (the "Sabine Pass Liquefaction Project") at the Sabine Pass LNG terminal adjacent to the existing regasification facilities


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through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"). Cheniere Partners plans to construct up to six Trains, which are in various stages of development. Each Train is expected to have nominal production capacity of approximately 4.5 mtpa of LNG. Cheniere Partners also owns the 94-mile Creole Trail Pipeline through a wholly owned subsidiary, Cheniere Creole Trail Pipeline, L.P. ("CTPL"), which interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines. One of our subsidiaries, Cheniere Marketing, LLC ("Cheniere Marketing"), is marketing LNG and natural gas on its own behalf and on behalf of Cheniere Partners, in an effort to utilize half of the LNG regasification capacity at the Sabine Pass LNG terminal during construction of the Sabine Pass Liquefaction Project. Cheniere Marketing has also entered into an SPA with Sabine Pass Liquefaction to purchase, at Cheniere Marketing's option, up to 104,000,000 MMBtu/yr of LNG.

We are developing a second natural gas liquefaction and export facility near Corpus Christi, Texas (the "Corpus Christi Liquefaction Project"). As currently contemplated, the proposed Corpus Christi Liquefaction LNG terminal would be designed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, have three LNG storage tanks with capacity of 10.1 Bcfe and two docks that can accommodate vessels with capacity of up to 267,000 cubic meters.

We are also in various stages of developing other projects, which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision.

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

Unless the context requires otherwise, references to the "Company", "Cheniere", "we", "us" and "our" refer to Cheniere Energy, Inc. and its subsidiaries, including Cheniere Holdings and our publicly traded subsidiary partnership, Cheniere Partners.

Although results are consolidated for financial reporting, we, Cheniere Holdings and Cheniere Partners operate with independent capital structures. The following diagram depicts our abbreviated capital structure, including our ownership of Cheniere Holdings, Cheniere Partners, Sabine Pass LNG, Sabine Pass Liquefaction and CTPL as of January 31, 2014:


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Our Business Strategy

Our primary business strategy is to identify markets where growth is constrained by lack of infrastructure and in those markets develop, construct, and operate assets supported by long-term, fixed fee contracts. We plan to implement our strategy by:
completing construction and commencing operation of Sabine Pass Liquefaction's Trains;
developing and operating Sabine Pass Liquefaction's Trains safely, efficiently and reliably;
making LNG available to our long-term SPA customers to generate steady and reliable revenues and operating cash flows;
safely maintaining and operating the Sabine Pass LNG terminal and the Creole Trail Pipeline;
utilizing capacity at the Sabine Pass LNG terminal for short-term and spot LNG purchases and sales until such capacity is used in connection with the Sabine Pass Liquefaction Project;
developing business relationships for the marketing of additional long-term and short-term agreements for the Corpus Christi Liquefaction Project and additional LNG volumes at the Sabine Pass LNG terminal, and for long-term and short-term contracts for potential future projects at other sites;
obtaining the requisite regulatory permits, long-term commercial contracts and financing to reach a final investment decision regarding the Corpus Christi Liquefaction Project; and
optimizing our capital structure to finance the construction and operation of the facilities needed to serve our customers.

Business Segments
 
Our business activities are conducted by two operating segments for which we provide information in our consolidated financial statements for the years ended December 31, 2013, 2012 and 2011. These two segments are our: 
LNG terminal business; and
LNG and natural gas marketing business. 
For information about our segments' revenues, profits and losses and total assets, see Note 17—"Business Segment Information" of our Notes to Consolidated Financial Statements.

LNG Terminal Business
 
We began developing our LNG terminal business in 1999 and were among the first companies to secure sites and commence development of new LNG terminals in North America. We focused our development efforts on three LNG terminal projects: the Sabine Pass LNG terminal in western Cameron Parish, Louisiana, less than four miles from the Gulf Coast on the deepwater ship channel; the Corpus Christi LNG terminal near Corpus Christi, Texas; and the Creole Trail LNG terminal at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. We have constructed and are operating regasification facilities at the Sabine Pass LNG terminal and are developing and constructing the Sabine Pass Liquefaction Project, which is owned through Cheniere Partners. We own 100% of the general partner interest in Cheniere Partners and 84.5% of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners. We currently own 100% interests in both the Corpus Christi and Creole Trail LNG terminal projects.
 
Sabine Pass LNG Terminal

Regasification Facilities
 
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which Sabine Pass LNG's customers are required to pay fixed monthly fees, whether or not they use the LNG terminal.  Each of Total Gas & Power North America, Inc. ("Total") 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 Sabine Pass LNG aggregating approximately $125 million annually for 20 years that commenced in 2009.


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Total S.A. has guaranteed Total's obligations under its TUA up to $2.5 billion, subject to certain exceptions, and 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 Sabine Pass LNG aggregating approximately $250 million annually, continuing until at least 20 years after Sabine Pass Liquefaction delivers its first commercial cargo at the Sabine Pass Liquefaction Project, which may occur as early as late 2015. In September 2012, Sabine Pass Liquefaction entered into a partial TUA assignment agreement with Total, whereby Sabine Pass Liquefaction will progressively gain access to Total's capacity and other services provided under Total's TUA with Sabine Pass LNG.  This agreement will provide Sabine Pass Liquefaction with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Trains 5 and 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of Train 3, and permit Sabine Pass Liquefaction to more flexibly manage its LNG storage capacity with the commencement of Train 1. Notwithstanding any arrangements between Total and Sabine Pass Liquefaction, payments required to be made by Total to Sabine Pass LNG will continue to be made by Total to Sabine Pass LNG in accordance with its TUA.

Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.

Liquefaction Facilities

The Sabine Pass Liquefaction Project is being developed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. We are developing Trains 5 and 6 and commenced the regulatory approval process for these Trains in February 2013.

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

As of December 31, 2013, the overall project completion for Trains 1 and 2 and Trains 3 and 4 of the Sabine Pass Liquefaction Project were approximately 54% and 20%, respectively, which are ahead of the contractual schedule. Based on our current construction schedule, we anticipate that Train 1 will produce LNG as early as late 2015, and Trains 2, 3 and 4 are expected to commence operations on a staggered basis thereafter.

Customers

Sabine Pass Liquefaction has entered into four fixed price, 20-year SPAs with third parties that in the aggregate equate to 16 mtpa of LNG that commence with the date of first commercial delivery for Trains 1 through 4, which are fully permitted. In addition, Sabine Pass Liquefaction has entered into two fixed price, 20-year SPAs with third parties for another 3.75 mtpa of LNG that commence with the date of first commercial delivery for Train 5, which has not yet received regulatory approval for construction. Under the SPAs, the customers will purchase LNG from Sabine Pass Liquefaction for a price consisting of a fixed fee plus 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to cargoes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA commences upon the start of operations of the specified Train. As of December 31, 2013, Sabine Pass Liquefaction had the following third-party SPAs:
 
BG Gulf Coast LNG, LLC ("BG") has entered into an SPA that commences upon the date of first commercial delivery for Train 1 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $2.25 per MMBtu and includes additional annual contract quantities of 36,500,000 MMBtu, 34,000,000 MMBtu, and 33,500,000 MMBtu upon the date of first commercial delivery for Trains 2, 3 and 4, respectively, with a fixed fee of $3.00 per MMBtu. The total expected annual contracted cash flow from BG from fixed fees is approximately $723 million. In addition, Sabine Pass Liquefaction has agreed to make up to 500,000 MMBtu/d of LNG available to BG to the extent that Train 1 becomes commercially operable prior to the beginning of the first delivery window with a fixed fee of $2.25 per MMBtu, if


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produced. The obligations of BG are guaranteed by BG Energy Holdings Limited, a company organized under the laws of England and Wales.
Gas Natural Aprovisionamientos SDG S.A. ("Gas Natural Fenosa") has entered into an SPA that commences upon the date of first commercial delivery for Train 2 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $2.49 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $454 million. In addition, Sabine Pass Liquefaction has agreed to make up to 285,000 MMBtu/d of LNG available to Gas Natural Fenosa to the extent that Train 2 becomes commercially operable prior to the beginning of the first delivery window with a fixed fee of $2.49 per MMBtu, if produced. The obligations of Gas Natural Fenosa are guaranteed by Gas Natural SDG S.A., a company organized under the laws of Spain.
Korea Gas Corporation ("KOGAS") has entered into an SPA that commences upon the date of first commercial delivery for Train 3 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $548 million. KOGAS is organized under the laws of the Republic of Korea.
GAIL (India) Limited ("GAIL") has entered into an SPA that commences upon the date of first commercial delivery for Train 4 and includes an annual contract quantity of 182,500,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $548 million. GAIL is organized under the laws of India.
Total has entered into an SPA that commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 104,750,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $314 million. The obligations of Total are guaranteed by Total S.A., a company organized under the laws of France.
Centrica has entered into an SPA that commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 91,250,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $274 million. Centrica is organized under the laws of England and Wales.
In aggregate, the fixed fee portion to be paid by these customers is approximately $2.3 billion annually for Trains 1 through 4, and $2.9 billion annually if we make a positive final investment decision with respect to Train 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of Trains 1 through 5, respectively.

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

Natural Gas Transportation and Supply

For Sabine Pass Liquefaction's feed gas transportation requirements, Sabine Pass Liquefaction has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CTPL and other third party pipeline companies. Sabine Pass Liquefaction has entered into enabling agreements with third parties, and will continue to enter into such agreements in order to secure feed gas for the Sabine Pass Liquefaction Project.

Construction

Trains 1 through 4 are being designed, constructed and commissioned by Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") using the ConocoPhillips Optimized Cascade® technology, a proven technology deployed in numerous LNG projects around the world. Sabine Pass Liquefaction entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Train 1 and Train 2 (the "EPC Contract (Trains 1 and 2)") and Train 3 and Train 4 (the "EPC Contract (Trains 3 and 4)" and together with EPC Contract (Trains 1 and 2), the "EPC Contracts") under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause Sabine


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Pass Liquefaction to enter into a change order, or Sabine Pass Liquefaction agrees with Bechtel to a change order.
The total contract price of the EPC Contract (Trains 1 and 2) and the total contract price of the EPC Contract (Trains 3 and 4) is approximately $4.1 billion and $3.8 billion, respectively, reflecting amounts incurred under change orders through December 31, 2013. Total expected capital costs for Trains 1 through 4 are estimated to be between $9.0 billion and $10.0 billion before financing costs, including estimated owner's costs and contingencies.

Pipeline Facilities

CTPL owns the Creole Trail Pipeline, a 94-mile pipeline interconnecting the Sabine Pass LNG terminal with a number of large interstate pipelines. In December 2013, CTPL began construction of certain modifications to allow the Creole Trail Pipeline to be able to transport natural gas to the Sabine Pass LNG terminal. We estimate that the capital costs to modify the Creole Trail Pipeline will be approximately $100 million. The modifications are expected to be in service in time for the commissioning and testing of Trains 1 and 2.

Corpus Christi LNG Terminal

Liquefaction Facilities

In September 2011, we formed Corpus Christi Liquefaction, LLC ("Corpus Christi Liquefaction") to develop a natural gas liquefaction facility near Corpus Christi, Texas on over 1,000 acres of land that we own or control. In August 2012, Corpus Christi Liquefaction filed an application with the FERC for authorization to site, construct and operate the Corpus Christi Liquefaction Project. Simultaneously, Cheniere Marketing filed an application with the DOE to export up to 15 mtpa of domestically produced LNG to FTA and non-FTA countries from the proposed Corpus Christi Liquefaction Project. In October 2012, the DOE granted Cheniere Marketing authority to export 15 mtpa of domestically produced LNG to FTA countries from the proposed Corpus Christi Liquefaction Project.

Customer

Corpus Christi Liquefaction has entered into a fixed price, 20-year SPA with PT Pertamina (Persero) ("Pertamina") with an annual contract quantity of 39,680,000 MMBtu of LNG, which equates to approximately 0.8 mtpa of LNG. Under the SPA, Pertamina will purchase LNG from Corpus Christi Liquefaction for a price consisting of a fixed fee of $3.50 plus 115% of Henry Hub per MMBtu of LNG, equating to expected annual contracted cash flow from fixed fees of approximately $139 million. In certain circumstances, Pertamina may elect to cancel or suspend deliveries of LNG cargoes, in which case Pertamina would still be required to pay the fixed fee with respect to cargoes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for inflation. The SPA and contracted volumes to be made available under the SPA are not tied to a specific Train; however, the term of the SPA commences upon the start of operations of the first Train at the Corpus Christi Liquefaction Project.

Construction

In December 2013, Corpus Christi Liquefaction entered into contracts with Bechtel for the engineering, procurement and construction of Trains and related facilities for the Corpus Christi Liquefaction Project under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause Corpus Christi Liquefaction to enter into a change order, or Corpus Christi Liquefaction agrees with Bechtel to a change order. The Corpus Christi Liquefaction stage 1 EPC contract (the "Stage 1 EPC Contract") with Bechtel includes two Trains, two LNG storage tanks, one complete berth and a second partial berth. The Corpus Christi Liquefaction stage 2 EPC contract (the Stage 2 EPC Contract") with Bechtel includes one Train, one additional LNG storage tank and completion of the second berth. The contract price for the Stage 1 EPC contract is approximately $7.1 billion, and the contract price for the Stage 2 EPC contract is approximately $2.4 billion. Total expected costs for the three Trains and the related facilities, excluding pipeline facilities, are estimated to be between $10.5 billion and $11.0 billion before financing costs, including an estimate for owner's costs and contingencies.

We will contemplate making a final investment decision to commence construction of the Corpus Christi Liquefaction Project based upon, among other things, entering into acceptable commercial arrangements, receiving regulatory authorization from the FERC to construct and operate the liquefaction assets, securing pipeline transportation of natural gas to the Corpus Christi Liquefaction Project and obtaining adequate financing to construct the facility.



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Pipeline Facilities

In conjunction with the Corpus Christi Liquefaction Project, we filed an application with the FERC in August 2012 for authorization to site, construct and operate 23 miles of 48" pipeline that would interconnect the Corpus Christi Liquefaction Project with five inter- and intrastate natural gas pipelines (the "Corpus Christi Pipeline"). The pipeline is designed to transport 2.25 Bcf/d of feed and fuel gas required by the Corpus Christi Liquefaction Project from the existing natural gas pipeline grid.

We will contemplate making a final investment decision to commence construction of the Corpus Christi Pipeline based upon, among other things, a positive final investment decision of the Corpus Christi Liquefaction Project, receiving regulatory authorization from the FERC to construct and operate the pipeline and obtaining adequate financing.

Other LNG Terminals and Facilities
 
We continue to evaluate, and may develop, additional sites that we believe may be commercially desirable locations for LNG terminals and other facilities.
 
Competition

Sabine Pass LNG currently does not experience competition for its terminal capacity because the entire approximately 4.0 Bcf/d of regasification capacity that is available at the Sabine Pass LNG terminal has been fully contracted. If and when Sabine Pass LNG has to replace any TUAs, it will compete with other then-existing LNG terminals for customers.

The Sabine Pass Liquefaction Project currently does not experience competition with respect to Trains 1 through 5. Sabine Pass Liquefaction has entered into six fixed price, 20-year LNG SPAs with third parties that will utilize substantially all of the liquefaction capacity available from these Trains. Each customer will be required to pay an escalating fixed fee for its annual contract quantity even if it elects not to purchase any LNG from us.

If and when Sabine Pass Liquefaction or Corpus Christi Liquefaction needs to replace any existing SPA or enter into new SPAs, they will compete on the basis of price per contracted volume of LNG with other natural gas liquefaction projects throughout the world. Revenues associated with any incremental volumes, including those under the Cheniere Marketing SPA discussed above, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to markets than us.

CTPL currently does not experience competition for its pipeline capacity because it is fully contracted with Sabine Pass Liquefaction. Corpus Christi Liquefaction is expected to commit for all capacity on the Corpus Christi Pipeline. If and when we have to replace any of our contracted pipeline capacity, we will compete with other interstate and/or intrastate pipelines that may connect with our LNG terminals.

Governmental Regulation
 
Our LNG terminals are 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 our cost of operations and construction, and failure to comply with such laws could result in substantial penalties.

The design, construction and operation of our proposed liquefaction facilities, the export of LNG and the transportation of natural gas through the Creole Trail Pipeline and the Corpus Christi Pipeline are highly regulated activities. In order to site and construct our LNG terminals, we need to obtain and maintain authorizations from the FERC under Section 3 of the Natural Gas Act of 1938, as amended ("NGA"). 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 site, construct and operate our liquefaction facilities.

The Energy Policy Act of 2005 (the "EPAct") amended Section 3 of the NGA to establish or clarify the FERC's exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, although except as specifically provided in the EPAct, nothing in the EPAct is intended to affect otherwise applicable law related to any other federal agency's authorities or responsibilities related to LNG terminals. The FERC issued final orders in April and July 2012 approving our application for an order under Section 3 of the NGA authorizing the siting, construction and operation of the Sabine


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Pass Liquefaction Project, including the siting, construction and operation of Trains 1 through 4. Subsequently, the FERC issued written approval to commence site preparation work for Trains 1 through 4. The FERC approval requires us to obtain certain additional FERC approvals as construction progresses. To date, we have been able to obtain these approvals as needed. On October 9, 2012, we applied to amend the FERC approval to reflect certain modifications to the Sabine Pass Liquefaction Project, and on August 2, 2013, the FERC issued an order approving the modifications. On October 25, 2013, we applied to further amend the FERC approval, requesting authorization to increase the total LNG production capacity of Trains 1 through 4 from the currently authorized 803 Bcf/yr to 1,006 Bcf/yr so as to more accurately reflect the estimated maximum LNG production capacity. The need for these approvals has not materially affected our construction progress. The FERC's approval to site, construct and operate Trains 5 and 6 also will be required. In this regard, on September 30, 2013, we filed an application with the FERC for authorization to add Trains 5 and 6 to the Sabine Pass Liquefaction Project. Throughout the life of our proposed liquefaction facilities 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.

In order to construct, own, operate and maintain the Creole Trail Pipeline, CTPL received a certificate of public convenience and necessity from the FERC under Section 7 of the NGA. The FERC's approval under Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, may be required prior to making any modifications to the Creole Trail Pipeline as it is a regulated, interstate natural gas pipeline. An application for authorization to construct, own, operate and maintain certain new facilities in order to enable bi-directional natural gas flow on the Creole Trail Pipeline system to allow for the delivery of up to 1,530,000 Dthd of feed gas to the Sabine Pass Liquefaction Project was submitted to the FERC by CTPL in April 2012. In February 2013, the FERC approved the proposed project, and in October 2013, the FERC issued an order denying a petitioner's request for rehearing and stay of the approval. In November 2013, CTPL received approval from the Louisiana Department of Environmental Quality ("LDEQ") for the proposed modifications and, with subsequent final FERC clearance, construction began in December 2013.

Corpus Christi Liquefaction filed an application with the FERC in August 2012 for an order under Section 3 of the NGA authorizing the siting, construction and operation of the Corpus Christi Liquefaction Project. The FERC's approval under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, will be required prior to construction and operation of the Corpus Christi Liquefaction facilities.

In August 2012, we filed an application with the FERC for an order under Section 7 of the NGA authorizing the siting, construction and operation of the Corpus Christi Pipeline. The FERC's approval under Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, will be required prior to construction and operation of the Corpus Christi Pipeline.

Under the NGA, the FERC is granted authority to approve, and if necessary, set "just and reasonable rates" for the transportation or sale of natural gas in interstate commerce. In addition, under the NGA, CTPL is not permitted to unduly discriminate or grant undue preference as to its rates or the terms and conditions of service. The FERC has the authority to grant certificates allowing construction and operation of facilities used in interstate gas transportation and authorizing the provision of services. Under the NGA, the FERC's jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate consumption for domestic, commercial, industrial, or any other use, and to natural gas companies engaged in such transportation or sale. However, the FERC's jurisdiction does not extend to the production, gathering, or local distribution of natural gas.

 In general, the FERC's authority to regulate interstate natural gas pipelines and the services that they provide includes:
rates and charges for natural gas transportation and related services;
the certification and construction of new facilities;
the extension and abandonment of services and facilities;
the maintenance of accounts and records;
the acquisition and disposition of facilities;
the initiation and discontinuation of services; and
various other matters.


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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.

For a number of years the FERC has implemented certain rules referred to as Standards of Conduct aimed at ensuring that an interstate natural gas pipeline not provide certain affiliated entities with preferential access to transportation service or non-public information about such service. These rules have been subject to revision by the FERC from time to time, most recently in 2008 when the FERC issued a final rule, Order No. 717, on Standards of Conduct for Transmission Providers. Order No. 717 eliminated the concept of energy affiliates and adopted a "functional approach" that applies Standards of Conduct to individual officers and employees based on their job functions, not on the company or division in which the individual works. The general principles of the Standards of Conduct are non-discrimination, independent functioning, no conduit and transparency. These general principles govern the relationship between marketing function employees conducting transactions with affiliated pipeline companies and transportation function employees. CTPL has established the required policies and procedures to comply with the Standards of Conduct and is subject to audit by the FERC to review compliance, policies and its training programs.

DOE Export License

The DOE has authorized the export of up to the equivalent of 16 mtpa (approximately 803 Bcf/yr) of domestically produced LNG by vessel from the Sabine Pass LNG terminal to countries with which the United States has a FTA providing for national treatment for trade in natural gas ("FTA countries") for a 30-year term, beginning on the earlier of the date of first export or September 7, 2020; and to non-FTA countries for a 20-year term, beginning on the earlier of the date of first export or August 7, 2017.

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

The DOE has authorized the export of up to the equivalent of 15 mtpa (approximately 767 Bcf/yr) of domestically produced LNG by vessel from the Corpus Christi Liquefaction Project to countries with which the United States has an FTA providing for national treatment for trade in natural gas for a 25-year term, beginning on the earlier of the date of first export or October 16, 2022. An application to export LNG to non-FTA countries was filed on August 31, 2012 by Cheniere Marketing and is still pending DOE authorization.

Exports of natural gas to countries with which the United States has an FTA are "deemed to be consistent with the public interest" and authorization to export LNG to FTA countries shall be granted by the DOE without "modification or delay". FTA countries which import LNG now or will do so by 2016 include Chile, Mexico, Singapore, South Korea and the Dominican Republic. Exports of natural gas to countries with which the United States does not have an FTA are considered by the DOE in the context of a comment period whereby interveners are provided the opportunity to assert that such authorization would not be consistent with the public interest.

Pipelines

The Creole Trail Pipeline and the Corpus Christi Pipeline are subject to regulation by the U.S. Department of Transportation ("DOT"), under the Pipeline and Hazardous Material Safety Act ("PHMSA"), pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities.

The Pipeline Safety Improvement Act of 2002, as amended ("PSIA"), which is administered by the DOT Office of Pipeline Safety, governs the areas of testing, education, training and communication. The PSIA requires pipeline companies to perform extensive integrity tests on natural gas transportation pipelines that exist in high population density areas designated as "high consequence areas." Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as


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the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs for gas transportation pipelines, which requires pipeline operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline, as necessary; and implement preventive and mitigation actions.

In 2010, the DOT issued a final rule (known as "Control Room Management Rule") requiring pipeline operators to write and institute certain control room procedures that address human factors and fatigue management.

Natural Gas Pipeline Safety Act of 1968 ("NGPSA")

Louisiana and Texas administer federal pipeline safety standards under the NGPSA, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal remedies.

Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011

The Creole Trail Pipeline and Corpus Christi Pipeline are also subject to the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. Under the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has civil penalty authority up to $200,000 per day (from the prior $100,000), with a maximum of $2 million for any related series of violations (from the prior $1 million).

Other Governmental Permits, Approvals and Authorizations

The construction and operation of the Sabine Pass LNG terminal and the Corpus Christi Liquefaction Project are subject to additional federal permits, orders, approvals and consultations required by other federal agencies, including the DOE, Advisory Council on Historic Preservation, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, Environmental Protection Agency ("EPA") and U.S. Department of Homeland Security.

Three significant permits are the U.S. Army Corps of Engineers ("USACE") Section 404 of the Clean Water Act/Section 10 of the Rivers and Harbors Act Permit (the "Section 10/404 Permit"), the Clean Air Act Title V ("Title V") Operating Permit and the Prevention of Significant Deterioration ("PSD") Permit, the latter two permits being issued by the LDEQ for the Sabine Pass LNG terminal and by the Texas Commission on Environmental Quality ("TCEQ") and the EPA for the Corpus Christi Liquefaction Project.

The application for revision of the Sabine Pass LNG terminal's Section 10/404 Permit to authorize construction of Train 1 through Train 4 was submitted in January 2011. The process included a public comment period which commenced in March 2011 and closed in April 2011. The revised Section 10/404 Permit was received from the USACE in March 2012. The USACE acted in the capacity as a cooperating agency in the FERC's NEPA review process. The application to amend the Sabine Pass LNG terminal's existing Title V and PSD permits to authorize construction of Train 1 through Train 4 was initially submitted in December 2010 and revised in March 2011. The process included a public comment period from June 2011 to August 2011 and a public hearing in August 2011. The final revised Title V and PSD permits were issued by the LDEQ in December 2011. Although these permits are final, a petition with the EPA has been filed pursuant to the Clean Air Act requesting that the EPA object to the Title V permit. The EPA has not ruled on this petition. In June 2012, Cheniere Partners applied to the LDEQ for a further amendment to the Title V and PSD permits to reflect proposed modifications to the Sabine Pass Liquefaction Project that were filed with the FERC in October 2012. The LDEQ issued the amended PSD and Title V permits in March 2013. These permits are final. In September 2013, Cheniere Partners applied to the LDEQ for another amendment to its PSD and Title V permits seeking approval to, among other things, construct and operate Train 5 and Train 6. Cheniere Partners anticipates, but cannot guarantee, that the revised Title V and PSD permits authorizing, among other things, construction and operation of Train 5 and Train 6 will be issued by September 2014.

An application for an amendment to Corpus Christi Liquefaction's Section 10/404 Permit to authorize construction of the Corpus Christi Liquefaction Project was submitted in August 2012. The process included a public comment period which


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commenced in May 2013 and closed in June 2013. Corpus Christi Liquefaction applied for new PSD and Title V permits with the TCEQ and EPA in August 2012; these permits are pending.

In April 2012, CTPL applied for new Title V and PSD permits for the proposed modifications to the Creole Trail Pipeline system, which were issued by the LDEQ in November 2013.

In August 2012, Corpus Christi Pipeline applied to the TCEQ and EPA for new PSD and Title V permits for the proposed compressor station at Sinton, Texas (the "Sinton Compressor Station"). The PSD permit for criteria pollutants at the Sinton Compressor Station was issued by the TCEQ on December 20, 2013; the EPA permit for greenhouse gases is pending.

Cheniere Partners will also need to obtain a modification to the Sabine Pass LNG terminal's existing wastewater discharge permit to authorize discharges from the liquefaction facilities prior to the commencement of operation of the Sabine Pass Liquefaction Project. Corpus Christi Liquefaction applied for a waste water discharge permit in February 2013 to authorize discharges from the liquefaction facilities. The permit public comment period commenced in November 2013 and closed in December 2013; no comments were received.

The Sabine Pass LNG terminal and the Corpus Christi LNG terminal are subject to DOT safety regulations and standards for the transportation and storage of LNG and regulations of the U.S. Coast Guard relating to maritime safety and facility security.

Commodity Futures Trading Commission

Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), is designed primarily to (1) regulate certain participants in the swaps markets, including entities falling within the newly established categories of "Swap Dealer" and "Major Swap Participant," (2) require clearing and exchange-trading of certain swaps that the Commodity Futures Trading Commission (the "CFTC") determines, by rulemaking, must be cleared, (3) increase swap market transparency through robust reporting and recordkeeping requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared and, in certain cases, uncleared swaps, and (5) enhance the CFTC's rulemaking and enforcement authority, including the authority to establish position limits on certain swaps and futures products. This legislation requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the swaps regulatory provisions of the Dodd-Frank Act. The CFTC had adopted rules imposing new position limits on certain core futures and equivalent swaps contracts for or linked to certain physical commodities, including Henry Hub natural gas, that market participants could hold with exceptions for certain bona fide hedging transactions.

The final rules that the CFTC adopted on November 18, 2011 imposing position limits on certain core futures and equivalent swaps contracts for physical commodities, including Henry Hub natural gas, were vacated by federal district court on September 28, 2012. On November 5, 2013, the CFTC proposed new position limits rules that would modify and expand the applicability of position limits on certain core futures and equivalent swaps contracts for or linked to certain physical commodities, including Henry Hub natural gas, that market participants could hold with exceptions for certain bona fide hedging transactions. The CFTC has determined, by rule, that certain interest rate swaps and certain credit default swaps must be mandatorily cleared, but the CFTC has not yet proposed rules determining any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the "end-user exception" from the mandatory clearing and exchange-trading requirements for our swaps entered to hedge our commercial risks, these mandatory clearing and exchange-trading requirements may apply to other market participants, such as our counterparties (who may be registered as Swap Dealers), and the application of such rules may change the cost and availability of the swaps that we use for hedging. For uncleared swaps, the CFTC or federal banking regulators may adopt rules that would require our Swap Dealer counterparties to enter into credit support documentation with us and/or require us to post initial and variation margin; however, the CFTC's and other regulators' margin rules are not yet final and therefore the application of those provisions to us is uncertain at this time. Provisions from other titles of the Dodd-Frank Act may also cause our derivatives counterparties to spin off some or all of their derivatives activities to a separate entity, and such separate entity, who could be our counterparty in future swaps, may not be as creditworthy as the current counterparty. The Dodd-Frank Act's swaps regulatory provisions and the related rules may also adversely affect our existing derivative contracts and restrict our ability to monetize such contracts, cause us to restructure certain contracts, reduce the availability of derivatives to protect against risks or to optimize assets, and impact the liquidity of certain swaps products, all of which could increase our business costs.



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Environmental Regulation
  
Our LNG terminals are 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 terminals are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the construction and operations of our proposed liquefaction facilities, will be materially and adversely affected by any such requirements.
 
In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule for multiple sections of the economy. This rule requires mandatory reporting of greenhouse gas ("GHG") emissions from stationary fuel combustion sources as well as all fugitive emissions throughout LNG terminals. From time to time, Congress has considered proposed legislation directed at reducing GHG emissions, and the EPA has defined GHG emissions thresholds for requiring certain permits for new and existing industrial sources. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, financial position, results of operations and cash flows.

Coastal Zone Management Act ("CZMA")
 
Our LNG terminals are 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 terminals are subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained to discharge pollutants into state and federal waters. The CWA is administered by the EPA, the USACE, and by the states (in Louisiana, by the LDEQ, and in Texas, by the TCEQ).
 
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 facilities, we will be subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes
 
Endangered Species Act
 
Our LNG terminals 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.



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LNG and Natural Gas Marketing Business 

Our wholly owned subsidiary, Cheniere Marketing, is engaged in the LNG and natural gas marketing business and is seeking to develop a portfolio of long-term, short-term and spot LNG purchase and sale agreements. Cheniere Marketing has purchased, transported and unloaded commercial LNG cargoes into the Sabine Pass LNG terminal and has used trading strategies intended to maximize margins on these cargoes. Cheniere Marketing has secured the following rights and obligations to support its business:
the right to deliver cargoes to the Sabine Pass LNG terminal during the construction of the Sabine Pass Liquefaction Project in exchange for payment of 80% of the expected gross margin from each cargo to Cheniere Energy Investments, LLC ("Cheniere Investments"), a wholly owned subsidiary of Cheniere Partners;
the Cheniere Marketing SPA, with the right to purchase, at Cheniere Marketing's option, up to 104,000,000 MMBtu/yr of LNG from Sabine Pass Liquefaction, to the extent Sabine Pass Liquefaction is able to produce LNG in excess of that required for other customers: Cheniere Marketing may purchase LNG at a price of 115% of Henry Hub plus up to $3.00 per MMBtu for the most profitable 36,000,000 MMBtu of cargoes sold each year by Cheniere Marketing; and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing; and
three LNG vessel time charters with subsidiaries of two ship owners, Dynagas, Ltd. and Teekay LNG Operating LLC. The annual payments for the vessel charters are approximately $92 million. The charters have an initial term of 5 years with the option to renew with Dynagas, Ltd. for a 2-year extension with similar terms as the initial term. Cheniere Marketing expects to receive delivery of the vessel from Dynagas, Ltd. in June 2015 and the vessels from Teekay LNG Operating LLC in January 2016 and June 2016.

LNG and Natural Gas Marketing Competition 

In purchasing LNG, we compete for supplies of LNG with: 
large, multinational and national companies with longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources; 
oil and gas producers who sell or control LNG derived from their international oil and gas properties; and 
purchasers located in other countries where prevailing market prices can be substantially different from those in the United States.
In marketing LNG and natural gas, we compete for sales of LNG and natural gas with a variety of competitors, including:
major integrated marketers who have large amounts of capital to support their marketing operations and offer a full-range of services and market numerous products other than natural gas; 
producer marketers who sell their own natural gas production or the production of their affiliated natural gas production company; 
small geographically focused marketers who focus on marketing natural gas for the geographic area in which their affiliated distributor operates; and 
aggregators who gather small volumes of natural gas from various sources, combine them and sell the larger volumes for more favorable prices and terms than would be possible selling the smaller volumes separately.
LNG and Natural Gas Marketing Governmental Regulation

In 1992 and 1993, the FERC concluded that sellers of short-term or long-term natural gas supplies would not have market power over the sale for resale of natural gas. The FERC established light-handed regulation over sales for resale of natural gas and adopted regulations granting blanket certificates to allow entities selling natural gas to make interstate sales for resale at negotiated rates. In 2003, the FERC amended the blanket marketing certificates to require that all sellers adhere to a code of conduct with respect to natural gas sales. The code of conduct addresses such matters as natural gas withholding, manipulation of market prices, communication of accurate information and record retention.
 
The EPAct contains provisions intended to prohibit the manipulation of the natural gas markets and is applicable to our LNG and natural gas marketing businesses.
 


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The prices at which we sell natural gas are not regulated, insofar as the interstate market is concerned and, for the most part, are not subject to state regulation. We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate automatically granted by the FERC. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. 

Market Factors

Our ability to sell any seasonal quantities of LNG available from Trains 1 through 4, develop additional Trains, or develop other new projects is subject to a broader array of market factors, including changes in worldwide supply and demand for natural gas, LNG and substitute products; the relative prices for natural gas, crude oil and substitute products in North America and international markets; economic growth in developing countries; investment in energy infrastructure; the rate of fuel switching for power generation from coal, nuclear or oil to natural gas; and access to capital markets.

We expect, based on our experience in the energy industry, that global demand for natural gas and LNG will increase significantly as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Global demand for natural gas is projected by the International Energy Agency ("IEA") to grow by more than 22.5 Tcf between 2010 and 2020, fueled by the growth of emerging economies. Wood Mackenzie forecasts that global demand for LNG will increase by 45%, or 5.14 Tcf, by 2020, from approximately 237 mtpa, or 11.5 Tcf/yr, in 2012, and reach a total of 532 mtpa, or 26 Tcf/yr, by 2030. As a result, the share of LNG in the global natural gas market is expected to increase as markets seek to improve security of supply by accessing a wide portfolio of producers that can readjust deliveries to meet the needs of changing markets.

While global natural gas consumption has been rising internationally, natural gas production in the United States has undergone a technological transformation that has resulted in a substantial increase in annual production capacity, decrease in the cost of production, and expansion of technically recoverable reserves.

Our ability to continue to develop new facilities in the United States will be driven in part by the continued success of the North American upstream natural gas sector in developing new reservoirs, continuing to drive down costs and producing higher valued condensates and natural gas liquids in conjunction with natural gas production. Any such facilities will compete with other international LNG export projects principally on a price basis. These projects generally require capital not only to build the marine, storage and liquefaction facilities, but also to drill wells and build processing and pipeline transportation infrastructure. Because we rely on the natural gas market and transportation infrastructure already existing in the United States, we generally require less capital expenditures than competing projects. Furthermore, because natural gas is purchased from the United States market at a Henry Hub related price, we can offer LNG for sale at an alternative price to crude oil prices, thereby providing customers with an opportunity to diversify their supply portfolios by geography and price index.

Subsidiaries
 
Our assets are generally held by or under our subsidiaries. We conduct most of our business through these subsidiaries, including the development, construction and operation of our LNG terminal business and the development and operation of our LNG and natural gas marketing business.
 
Employees and Labor Relations
 
We had 423 full-time employees at January 31, 2014.  We consider our current employee relations to be favorable.



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Available Information

Our common stock has been publicly traded since March 24, 2003, and is traded on the NYSE MKT under the symbol "LNG".
Our principal executive offices are located at 700 Milam Street, Suite 800, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is http://www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

We will also make available to any stockholder, without charge, copies of our Annual Report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Cheniere Energy, Inc., Investor Relations Department, 700 Milam Street, Suite 800, Houston, Texas 77002 or call (713) 375-5000. In addition, 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, proxy and information statements and other information regarding issuers, like us, that file electronically with the SEC.

ITEM 1A. RISK FACTORS
 
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
 
The risk factors in this report are grouped into the following categories: 
Risks Relating to Our Financial Matters; 
Risks Relating to Our LNG Terminal Business; 
Risks Relating to Our LNG and Natural Gas Marketing Business; 
Risks Relating to Our LNG Businesses in General; and 
Risks Relating to Our Business in General.
Risks Relating to Our Financial Matters
 
Our significant debt could materially and adversely affect our business, financial condition and prospects.
 
As of December 31, 2013, we had $6.6 billion of total debt outstanding on a consolidated basis (before debt discounts and debt premiums). We incur significant interest expense relating to the assets at the Sabine Pass LNG terminal, and we anticipate needing to incur substantial additional debt and issue equity to finance the construction of the Corpus Christi Liquefaction Project and to finance the construction of Trains 5 and 6 of the Sabine Pass Liquefaction Project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access the capital markets. Furthermore, our costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs.

We have not been profitable historically, and we have not had positive operating cash flow. We may not achieve profitability or generate positive operating cash flow in the future.
 
We had net losses of $507.9 million, $332.8 million and $198.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. In addition, our net cash flow used in operating activities was $52.4 million, $107.8 million and $42.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. We will continue to incur significant capital and operating expenditures while we develop and construct the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project. We currently expect that we will not begin to receive cash flows from operations under any SPA until late 2015, at the earliest. Any delays beyond the expected development period for Train 1 of the Sabine Pass Liquefaction Project would prolong, and could
increase the level of operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully and timely complete the applicable Train.

We may sell equity or equity-related securities or assets, including equity interests in Cheniere Holdings and Cheniere Partners. Such sales could dilute our stockholders' proportionate indirect interests in our assets, business operations and proposed liquefaction and other projects of Cheniere Partners or other subsidiaries, and could adversely affect the market price of our common stock.
 
We have pursued and are pursuing a number of alternatives in order to finance the construction of Trains 5 and 6 of the Sabine Pass Liquefaction Project and to finance the construction of the Corpus Christi Liquefaction Project, including potential issuances and sales of additional equity or equity-related securities by us, Cheniere Partners, or both, and potential sales of assets, including our equity interests in Cheniere Holdings. Such sales, in one or more transactions, could dilute our stockholders' proportionate indirect interests in our assets, business operations and proposed projects of Cheniere Partners, including the Sabine Pass Liquefaction Project, or in other subsidiaries or projects, including the Corpus Christi Liquefaction Project. In addition, such sales, or the anticipation of such sales, could adversely affect the market price of our common stock.

Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason.

Our future results and liquidity are substantially dependent upon performance by Chevron and Total, each of which has entered into a TUA with Sabine Pass LNG and agreed to pay us approximately $125 million annually, and, upon satisfaction of the conditions precedent to payment thereunder, by BG, Gas Natural Fenosa, KOGAS, GAIL, Total, Centrica and Pertamina, each of which has entered into an SPA and agreed to pay us approximately $723 million, $454 million, $548 million, $548 million, $314 million, $274 million and $139 million annually, respectively. We are dependent on each customer's continued willingness and ability to perform its obligations under its SPA. We are also exposed to the credit risk of any guarantor of these customers' obligations under their respective TUA or SPA in the event that we must seek recourse under a guaranty. If any customer fails to perform its obligations under its TUA or SPA, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the TUA or SPA.

Each of our customer contracts is subject to termination under certain circumstances.
  
Each of Sabine Pass LNG's long-term TUAs contains various termination rights. For example, each customer may terminate its TUA if the Sabine Pass 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. Sabine Pass LNG may not be able to replace these TUAs on desirable terms, or at all, if they are terminated.

Each of the SPAs contain various termination rights allowing our customers to terminate their SPAs, including, without limitation: (i) upon the occurrence of certain events of force majeure; (ii) if we fail to make available specified scheduled cargo quantities; (iii) delays in the commencement of commercial operations; and (iv) if the conditions precedent contained in the Total, Centrica and Pertamina SPAs are not met or waived by specified dates. Sabine Pass Liquefaction or Corpus Christi Liquefaction, as applicable, may not be able to replace these SPAs on desirable terms, or at all, if they are terminated.

Our subsidiaries may be restricted under the terms of their indebtedness from making distributions under certain circumstances, which may limit Cheniere Partners' ability to pay or increase distributions to us and could materially and adversely affect us.
 
The agreements governing our indebtedness restricts payments that our subsidiaries can make to Cheniere Partners in certain events and limits the indebtedness that our subsidiaries can incur. For example, Sabine Pass LNG may not make distributions until, among other requirements, a deposit has been made in an interest payment account for one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, a deposit has been made to a permanent debt service reserve fund for one semi-annual interest payment and a fixed charge coverage ratio test of 2:1 is satisfied.


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Sabine Pass LNG is not permitted to make cash distributions if its consolidated cash flow is not at least twice its fixed charges, calculated as required in the indentures governing the Sabine Pass LNG Notes (the "Sabine Pass Indentures"). In order to satisfy this fixed charge coverage ratio test, we estimate that Sabine Pass LNG's consolidated cash flow, as defined in such indentures, must be greater than approximately $340 million. Thus, TUA payments from Sabine Pass Liquefaction and either Chevron or Total are needed to satisfy the test. If the fixed charge coverage ratio test is not satisfied, Sabine Pass LNG will not be permitted by the Sabine Pass Indentures to make distributions to Cheniere Partners, which may prevent Cheniere Partners from making distributions to us and its other unitholders, which could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

Sabine Pass Liquefaction is likewise restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, substantial completion of Trains 1 through 4 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio of 1.25:1.00 is satisfied.

Our subsidiaries' inability to pay distributions to Cheniere Partners or to incur additional indebtedness as a result of the foregoing restrictions in the agreements governing their indebtedness may inhibit Cheniere Partners' ability to pay or increase distributions to us and its other unitholders.

Restrictions in agreements governing our subsidiaries' indebtedness may prevent our subsidiaries from engaging in certain beneficial transactions.
 
In addition to restrictions on the ability of Sabine Pass LNG and Sabine Pass Liquefaction to make distributions or incur additional indebtedness, the agreements governing their indebtedness also contain various other covenants that may prevent them from engaging in beneficial transactions, including limitations on their ability 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.
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 its 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


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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 commodity price risks that we encounter in our operations, our results of operations and cash flows may become more volatile and could be otherwise adversely affected.

Risks Relating to Our LNG Terminal Business
 
Operation of the Sabine Pass LNG terminal, the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project and other facilities that we may construct involves significant risks.
 
As more fully discussed in these Risk Factors, the Sabine Pass LNG terminal, the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project and our other existing and proposed LNG facilities face operational risks, including the following:
the facilities' performing below expected levels of efficiency;
breakdown or failures of equipment;
operational errors by vessel or tug operators;
operational errors by us or any contracted facility operator;
labor disputes; and
weather-related interruptions of operations.
We may not be successful in implementing our proposed business strategy to provide liquefaction capabilities at the Sabine Pass LNG terminal adjacent to the existing regasification facilities or the Corpus Christi Liquefaction Project.
 
The Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project will require very significant financial resources, which may not be available on terms reasonably acceptable to us or at all. The SPAs with Total, Centrica and Pertamina contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision to construct the applicable Train. If these conditions are not met by June


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30, 2015 with respect to the Total and Centrica SPAs, and December 31, 2014 with respect to the Pertamina SPA, each of Total, Centrica and Pertamina may terminate its respective SPA.

It will take several years to construct our proposed liquefaction facilities, and we do not expect Train 1 of the Sabine Pass Liquefaction Project to produce LNG until late 2015, at the earliest. Even if successfully constructed, our proposed liquefaction facilities would be subject to the operating risks described herein. Accordingly, there are many risks associated with the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, and if we are not successful in implementing our business strategy, we may not be able to generate cash flows, which could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Cost overruns and delays in the completion of one or more Trains, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
 
The actual construction costs of the Trains may be significantly higher than our current estimates as a result of many factors, including change orders under existing or future engineering, procurement and construction contracts resulting from the occurrence of certain specified events that may give Bechtel the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. We do not have any prior experience in constructing liquefaction facilities, and no liquefaction facilities have been constructed and placed in service in the United States in over 40 years. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both.

Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to the EPC Contracts with Bechtel or any future engineering, procurement and construction contract related to additional Trains, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is constructed (which could cause further delays). Our ability to obtain financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factors beyond our control. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Delays in the completion of one or more Trains could lead to reduced revenues or termination of one or more of the SPAs by our counterparties.
 
Any delay in completion of a Train could cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our ability to complete development of additional Trains will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to complete our business plan and our business may ultimately be unsuccessful.
 
We will require significant additional funding to be able to commence construction of the Corpus Christi Liquefaction Project and Trains 5 and 6 of the Sabine Pass Liquefaction Project, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in the development of additional Trains, and we may not be able to complete our business plan. Even if we are able to obtain funding, the funding may be inadequate to cover any increases in costs or delays in completion of the applicable Train, which may cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
  
To maintain the cryogenic readiness of the Sabine Pass LNG terminal, Sabine Pass LNG may need to purchase and process LNG. Sabine Pass LNG's TUA customers, including Sabine Pass Liquefaction, have the obligation to procure LNG if necessary for the Sabine Pass LNG terminal to maintain its cryogenic state. If they fail to do so, Sabine Pass LNG may need to procure such LNG.
 
Sabine Pass LNG needs to maintain the cryogenic readiness of the Sabine Pass LNG terminal. Together with Sabine Pass Liquefaction, the two third-party TUA customers have the obligation to maintain minimum inventory levels, and, under certain


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circumstances, to procure LNG to maintain the cryogenic readiness of the terminal. In the event that aggregate minimum inventory levels are not maintained, Sabine Pass LNG has the right to procure a cryogenic readiness cargo to cure a minimum inventory condition, and to be reimbursed by each TUA customer for their allocable share of the LNG acquisition costs. If Sabine Pass LNG is not able to obtain financing on acceptable terms, it will need to maintain sufficient working capital for such a purchase until it receives reimbursement for the allocable costs of the LNG from its TUA customers or sells the regasified LNG.
 
Sabine Pass LNG may be required to purchase natural gas to provide fuel at the Sabine Pass LNG terminal, which would increase operating costs and could have a material adverse effect on our results of operations.
 
Sabine Pass LNG's TUAs provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG terminal, which it uses 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 Sabine Pass LNG will have to purchase additional natural gas from third parties. Sabine Pass LNG 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, a delay in the completion of our liquefaction projects, higher construction costs, and the deferral of the dates on which payments are due under the SPAs, all of which could adversely affect us.
 
In August and September of 2005, Hurricanes Katrina and Rita damaged coastal and inland areas located in Texas, Louisiana, Mississippi and Alabama, resulting in the temporary suspension of construction of the Sabine Pass LNG terminal. In September 2008, Hurricane Ike struck the Texas and Louisiana coast, and the Sabine Pass LNG terminal experienced minor damage.

Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Sabine Pass Liquefaction Project, the Corpus Christi Liquefaction Project or our other facilities. If there are changes in the global climate, storm frequency and intensity may increase; should it result in rising seas, our coastal operations may be impacted.
 
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities could impede operations and construction and could have a material adverse effect on us.

The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, and other facilities, and the import and export of LNG and the transportation of natural gas, are highly regulated activities. Approval of the FERC under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline. Although the FERC has issued an order under Section 3 of the NGA authorizing the siting, construction and operation of four Trains at the Sabine Pass Liquefaction Project, the FERC order requires us to obtain certain additional approvals in conjunction with ongoing construction and operations of our proposed liquefaction facilities. In addition, our applications to the FERC under Section 3 of the NGA for authorization to site, construct and operate two additional Trains at the Sabine Pass Liquefaction Project and to site, construct and operate trains at the Corpus Christi Liquefaction Project are currently pending and will be subject to an environmental assessment by the FERC and comment from the public and intervenors. Authorizations obtained from other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We cannot control the outcome of the review and approval process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any existing or potential interventions or other actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in our projects. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

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

Timely and cost-effective completion of the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of Bechtel


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

We are relying on third-party engineers to estimate the future capacity ratings and performance capabilities of our proposed liquefaction facilities, and these estimates may prove to be inaccurate.
    
We are relying on third parties, principally Bechtel, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of our proposed liquefaction facilities. If any Train, when actually constructed, fails to have the capacity ratings and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our Trains to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

If third-party pipelines and other facilities interconnected to our pipelines and facilities are or become unavailable to transport natural gas, this could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
 
We will depend upon third-party pipelines and other facilities that will provide gas delivery options to our proposed liquefaction facilities and pipelines. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to meet our SPA obligations and continue shipping natural gas from producing regions or to end markets could be restricted, thereby reducing our revenues which could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

Under the SPAs with our liquefaction customers, we are required to deliver to them a specified amount of LNG at specified times. However, we may not be able to purchase or receive physical delivery of sufficient quantities of natural gas to satisfy those delivery obligations, which may provide affected SPA customers with the right to terminate their SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
 


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Our interstate natural gas pipelines and their FERC gas tariffs are subject to FERC regulation.
 
Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and under the Natural Gas Policy Act of 1978. The FERC regulates the transportation of natural gas in interstate commerce, including the construction and operation of our pipelines, the rates and terms of conditions of service and abandonment of facilities. Under the NGA, the rates charged by our interstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our interstate pipelines could be subject to substantial penalties and fines.

Our FERC gas tariffs, including our pro forma transportation agreements, must be filed and approved by the FERC. Before we enter into a transportation agreement with a shipper that contains a term that materially deviates from our tariff, we must seek FERC approval. The FERC may approve the material deviation in the transportation agreement; however, in that case, the materially deviating terms must be made available to our other similarly-situated customers. If we fail to seek FERC approval of a transportation agreement that materially deviates from our tariff, or if the FERC audits our contracts and finds deviations that appear to be unduly discriminatory, the FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.
 
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation.
 
Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.
 
The Federal Office of Pipeline Safety requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in "high consequence areas" where a leak or rupture could potentially do the most harm. As an operator, we are required to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventative and mitigating actions.
We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with the Office of Pipeline Safety's rules and related regulations and orders, we could be subject to significant penalties and fines.
 
Any reduction in the capacity of, or the allocations to, interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines, which would adversely affect our revenues and cash flow.
 
We will be dependent upon third-party pipelines and other facilities to provide delivery options to and from our pipelines. If any pipeline connection were to become unavailable for volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any permanent interruption at any key pipeline interconnect which caused a material reduction in volumes transported on our pipelines could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development and operation of our interstate natural gas pipelines would have a detrimental effect on us and our pipeline projects.
 
The design, construction and operation of interstate natural gas pipelines and the transportation of natural gas are all highly regulated activities. The FERC's approval under Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA from the United States Army Corps of Engineers


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and state environmental agencies, are required in order to construct and operate an interstate natural gas pipeline. We have no control over the outcome of the review and approval process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any existing or potential interventions or other actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in our pipeline projects. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.
 
Our business could be materially and adversely affected if we lose the right to situate our pipelines on property owned by third parties.
 
We do not own the land on which our pipelines are situated, and we are subject to the possibility of increased costs to retain necessary land use rights. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.

Risks Relating to Our LNG and Natural Gas Marketing Business
 
The limited capital resources and credit available to our LNG and natural gas marketing business may limit our ability to develop that business.
 
We have limited capital available to our LNG and natural gas marketing business. The business also currently has limited access to third-party sources of financing. Other investment-grade marketing companies have greater financial resources than we do. Our LNG and natural gas marketing business continues to develop and implement its business strategy and may not generate sufficient revenues and cash flows to cover the significant fixed costs of the business.
 
Our exposure to the performance and credit risks of counterparties under agreements may adversely affect our results of operations, liquidity and access to financing.
 
Our LNG and natural gas marketing business involves our entering into various purchase and sale, hedging and other transactions with numerous third parties (commonly referred to as "counterparties"). In such arrangements, we are exposed to the performance and credit risks of our counterparties, including the risk that one or more counterparties fails to perform its obligation to make deliveries of commodities and/or to make payments. These risks may increase during periods of commodity price volatility. Defaults by suppliers and other counterparties may adversely affect our results of operations, liquidity and access to financing.

Cheniere Marketing may not be able to contract with customers to facilitate the export of LNG on its chartered LNG vessels.
 
Cheniere Marketing has entered into an SPA with Sabine Pass Liquefaction pursuant to which Cheniere Marketing has the option to purchase LNG at the Sabine Pass Liquefaction Project.  Cheniere Marketing has also entered into LNG vessel charters in order to secure shipping capacity for the export of LNG to purchasers.  Under the charters, each having an initial term of 5 years, Cheniere Marketing is obligated to make payments for these vessels regardless of use in the aggregate amount of approximately $92.0 million per year with a portion of such payments beginning in 2015.  However, Cheniere Marketing may not be able to enter into contracts with purchasers of LNG in quantities equivalent to the vessel capacities for which Cheniere Marketing is required to make payments.  Failure to secure buyers for a sufficient amount of LNG could materially and adversely affect Cheniere Marketing's business, results of operations, cash flows and liquidity.

Risks Relating to Our LNG Businesses in General
 
We may not construct or operate any additional LNG facilities or Trains beyond those currently planned, which could limit our growth prospects.

We may not construct some of our proposed LNG facilities, including the proposed Corpus Christi Liquefaction Project or natural gas pipelines, whether due to lack of commercial interest or inability to obtain financing or otherwise. Our ability to develop additional liquefaction facilities will also depend on the availability and pricing of LNG and natural gas in North America and other places around the world. Competitors may have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to sources of natural


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gas and LNG than we do. If we are unable or unwilling to construct and operate additional LNG facilities, our prospects for growth will be limited.

Our cost estimates for Trains are subject to change as a result of cost overruns, change orders under existing or future construction contracts, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules. In the event we experience cost overruns, delays or both, the amount of funding needed to complete a Train could exceed our available funds and result in our failure to complete such Train and thereby negatively impact our business and limit our growth prospects.

Decreases in the demand for and price of LNG and natural gas could affect the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
 
The development of domestic LNG facilities and projects generally is based on assumptions about the future availability of natural gas, price of natural gas and LNG, and the prospects for international natural gas and LNG markets. Natural gas prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
relatively minor changes in the supply of, and demand for, natural gas in relevant markets;
political conditions in natural gas producing regions;
the extent of domestic production and importation of natural gas in relevant markets;
the level of demand for LNG and natural gas in relevant markets, including the effects of economic downturns or upturns;
weather conditions;
the competitive position of natural gas as a source of energy compared with other energy sources; and
the effect of government regulation on the production, transportation and sale of natural gas.
Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and natural gas, which could adversely affect the performance of our 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 our LNG businesses and the performance of our customers and could reduce our operating revenues and may cause us operating losses.

The economics of our LNG businesses 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 the Sabine Pass LNG terminal;
competitive liquefaction capacity in North America, which could divert natural gas from our proposed liquefaction facilities;
insufficient or oversupply of natural gas 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;


23




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 current and prospective 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.

Current operations at the Sabine Pass LNG terminal 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.

Operations at our proposed liquefaction facilities will be dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas have recently been and may continue to be discovered outside North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than LNG exported to these markets.

Political instability in foreign countries that import 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 the Sabine Pass 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 LNG facilities, including the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Commercial development of an LNG facility takes a number of years, requires a substantial capital investment and may be delayed by factors such as:
increased construction costs;
economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;
decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects;
the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;


24




political unrest or local community resistance to the siting of LNG 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 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;
weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and
shortages of or delays in the receipt of necessary construction materials.
We may not be able to secure firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas transportation requirements, which could have a material adverse effect on us.

We believe that there is sufficient capacity on the Creole Trail Pipeline to accommodate all of our natural gas supply requirements for Trains 1 and 2 of the Sabine Pass Liquefaction Project but not for additional Trains. We have entered into transportation precedent agreements to secure firm pipeline transportation capacity with CTPL and other third party pipeline companies and plan to secure additional capacity, but we may not be able to do so on commercially reasonable terms or at all, which would impair our ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We face competition based upon the international market price for LNG.
    
Our liquefaction projects are subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our liquefaction projects are diverse and include, among others:
increases in worldwide LNG production capacity and availability of LNG for market supply;
increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
increases in the cost to supply natural gas feedstock to our liquefaction projects;
decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;
increases in capacity and utilization of nuclear power and related facilities; and
displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.
Terrorist attacks or military campaigns may adversely impact our business.

A terrorist or military incident involving an LNG facility or LNG vessel may result in delays in, or cancellation of, construction of new LNG facilities, including one or more of the Trains, which would increase our costs and decrease our cash


25




flows. A terrorist incident may also result in temporary or permanent closure of existing LNG facilities, including the Sabine Pass LNG terminal or the Creole Trail Pipeline, which could increase our costs and decrease our cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Risks Relating to Our Business in General
 
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 facilities, including the Sabine Pass Liquefaction Project, and pipelines are 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. 
 
Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
    
Our business is and will be subject to extensive federal, state and local laws and regulations that regulate and restrict, among other things, discharges to air, land and water, with particular respect to the protection of the environment; the handling, storage and disposal of hazardous materials, hazardous waste, and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. Violation of these laws and regulations could lead to substantial liabilities, fines and penalties or to capital expenditures related to pollution control equipment that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.
    
There are numerous regulatory approaches currently in effect or being considered to address greenhouse gases, including possible future United States treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, and regulation by the EPA. In addition, as we consume natural gas at the Sabine Pass LNG terminal, a future carbon tax or other regulation may be imposed on us directly.
    
Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from the Sabine Pass LNG terminal through the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast, could cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.


26




 
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 construct and operate our facilities and pipelines 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. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.
 
We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could seriously harm us.
 
Our lack of diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.
 
Substantially all of our anticipated revenue in 2014 will be dependent upon one facility, the Sabine Pass LNG receiving terminal and related pipeline located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass LNG terminal or pipeline, or in the LNG industry, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.
 
We may engage in operations or make substantial commitments and investments located, or enter into agreements with counterparties located, outside the United States, which would expose us to political, governmental and economic instability and foreign currency exchange rate fluctuations.
 
Conducting operations or making commitments and investments located, or entering into agreements with counterparties located, outside of the United States will cause us to be affected by economic, political and governmental conditions in the countries where we engage in business. Any disruption caused by these factors could harm our business. Risks associated with operations, commitments and investments outside of the United States include the risks of:
currency fluctuations;
war;
expropriation or nationalization of assets;
renegotiation or nullification of existing contracts;
changing political conditions;
changing laws and policies affecting trade, taxation and investment;
multiple taxation due to different tax structures; and
the general hazards associated with the assertion of sovereignty over certain areas in which operations are conducted.
Because our reporting currency is the United States dollar, any of our operations conducted outside the United States or denominated in foreign currencies would face additional risks of fluctuating currency values and exchange rates, hard currency shortages and controls on currency exchange. We would be subject to the impact of foreign currency fluctuations and exchange rate changes on our reporting for results from those operations in our consolidated financial statements.

We may incur impairments to goodwill or long-lived assets.
 
We review our long-lived assets, including goodwill and other intangible assets, for impairment annually in the fourth quarter or whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, including a significant decline in the market price of our common stock, reduced


27




estimates of future cash flows for our business segments or disruptions to our business could lead to an impairment charge of our long-lived assets, including goodwill 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 to our goodwill, 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.

The market price of our common stock may fluctuate significantly, and our stockholders could lose all or part of their investment.

The market price of our common stock may fluctuate significantly as a result of a variety factors, some of which are beyond our control, including:
fluctuations in our quarterly or annual financial results or those of other companies in our industry;
issuance of additional equity securities which causes further dilution to stockholders;
operating and stock price performance of companies that investors deem comparable to us;
changes in government regulation or proposals applicable to us;
actual or potential non-performance by any customer or a counterparty under any agreement;
announcements made by us or our competitors of significant contracts;
changes in accounting standards, policies, guidance, interpretations or principles;
general economic conditions;
the failure of securities analysts to cover our common stock or changes in financial or other estimates by analysts; and
other factors described in these "Risk Factors"
In addition, the United States securities markets have experienced significant price and volume fluctuations. These fluctuations have often been unrelated to the operating performance of companies in these markets. Market fluctuations and broad market, economic and industry factors may negatively affect the price of our common stock, regardless of our operating performance. If we were to be the object of securities class litigation as a result of volatility in our common stock price or for other reasons, it could result in substantial diversion of our management's attention and resources, which could negatively affect our financial results.

If there is a determination that any of the restructuring transactions entered into prior to and in connection with Cheniere Holdings' initial public offering are taxable for U.S. federal income tax purposes and Cheniere Holdings ceases to be a member of our consolidated group for U.S. federal income tax purposes, then we could incur significant income tax liabilities.

Prior to and in connection with Cheniere Holdings' initial public offering, we, Cheniere Holdings and other members of our consolidated group for U.S. federal income tax purposes participated in a series of restructuring transactions intended to qualify as tax-free for U.S. federal income tax purposes. No ruling from the U.S. Internal Revenue Service has been requested in connection with the restructuring transactions. Under the Internal Revenue Code, Cheniere Holdings will cease to be a member of our consolidated group for U.S. federal income tax purposes (a deconsolidation) if at any time we own less than 80% of the vote or 80% of the value of Cheniere Holdings' outstanding shares, whether by issuance of additional shares by Cheniere Holdings or by our sale or other disposition of Cheniere Holdings' shares. If any of the restructuring transactions is determined to be taxable for U.S. federal income tax purposes for any reason, following a deconsolidation, we could incur significant income tax liabilities.

ITEM 1B. UNRESOLVED STAFF COMMENTS
 
None.



28




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.



29




PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER

Purchases of Equity Securities
 
Our common stock has traded on the NYSE MKT under the symbol "LNG" since March 24, 2003. The table below presents the high and low daily closing sales prices of our common stock, as reported by the NYSE MKT, for each quarter during 2012 and 2013
 
 
High
 
Low
Three Months Ended
 
 
 
 
March 31, 2012
 
$
16.67

 
$
8.70

June 30, 2012
 
18.74

 
11.75

September 30, 2012
 
16.80

 
12.81

December 31, 2012
 
18.78

 
14.11

Three Months Ended
 
 

 
 

March 31, 2013
 
$
28.00

 
$
19.50

June 30, 2013
 
30.60

 
25.33

September 30, 2013
 
34.14

 
27.07

December 31, 2013
 
44.90

 
34.31

 
As of January 31, 2014, we had 238.1 million shares of common stock outstanding held by approximately 518 record owners.
 
We have never paid a cash dividend on our common stock. We currently intend to retain earnings to finance the growth and development of our business and do not anticipate paying any cash dividends on the common stock in the foreseeable future. Any future change in our dividend policy will be made at the discretion of our board of directors in light of our financial condition, capital requirements, earnings, prospects and any restrictions under any financing agreements, as well as other factors the board of directors deems relevant.
 
Issuer Purchases of Equity Securities
 
During the year ended December 31, 2013, we purchased 4.2 million shares of restricted stock at a weighted average cash price of $33.81 per share related to restricted stock that vested during 2013 and that was returned to the Company by employees to cover taxes.

Total Stockholder Return
 
The following graph compares the cumulative total stockholder return on our common stock against the S&P Oil & Gas Exploration & Production Index, and the Russell 2000 Index for the five years ended December 31, 2013. The graph was constructed on the assumption that $100 was invested in our common stock, the S&P Oil & Gas Exploration & Production Index and the Russell 2000 Index on December 31, 2008 and that any dividends were fully reinvested.

Company / Index
 
2009
 
2010
 
2011
 
2012
 
2013
Cheniere Energy, Inc.
85

 
194

 
305

 
659

 
1,513

Russell 2000 Index
127

 
161

 
155

 
180

 
250

S&P Oil & Gas Exploration & Production Index
142

 
155

 
145

 
151

 
192



30








31




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,
 
 
(in thousands, except per share data)
 
 
2013
 
2012
 
2011
 
2010
 
2009
Revenues
 
$
267,213

 
$
266,220

 
$
290,444

 
$
291,513

 
$
181,126

General and administrative expense (1)
 
384,512

 
152,081

 
88,427

 
68,626

 
65,830

Income (loss) from operations
 
(328,986
)
 
(75,832
)
 
58,146

 
104,623

 
23,496

Interest expense, net
 
(178,400
)
 
(200,811
)
 
(259,393
)
 
(262,046
)
 
(243,295
)
Net loss attributable to common stockholders
 
(507,922
)
 
(332,780
)
 
(198,756
)
 
(76,203
)
 
(161,490
)
Net loss per share attributable to common stockholders - basic and diluted
 
$
(2.32
)
 
$
(1.83
)
 
$
(2.60
)
 
$
(1.37
)
 
$
(3.13
)
Weighted average number of common shares outstanding - basic and diluted
 
218,869

 
181,768

 
76,483

 
55,765

 
51,598


 
 
December 31,
 
 
2013
 
2012
 
2011
 
2010
 
2009
Cash and cash equivalents
 
$
960,842

 
$
201,711

 
$
459,160

 
$
74,161

 
$
88,372

Restricted cash and cash equivalents (current)
 
598,064

 
520,263

 
102,165

 
73,062

 
138,309

Non-current restricted cash and cash equivalents
 
1,031,399

 
272,924

 
82,892

 
82,892

 
82,892

Property, plant and equipment, net
 
6,454,399

 
3,282,305

 
2,107,129

 
2,157,597

 
2,216,855

Total assets
 
9,673,237

 
4,639,085

 
2,915,325

 
2,553,507

 
2,732,622

Current debt, net of discount
 

 

 
492,724

 

 

Long-term debt, net of discount
 
6,576,273

 
2,167,113

 
2,465,113

 
2,918,579

 
2,692,740

Long-term debt-related parties, net of discount
 

 

 
9,598

 
8,930

 
349,135

Total stockholders' equity (deficit)
 
$
2,840,057

 
$
2,261,605

 
$
(172,992
)
 
$
(472,610
)
 
$
(649,732
)
 
(1)
General and administrative expense includes $252.1 million, $53.2 million, $24.4 million, $16.1 million, and $19.2 million share-based compensation expense recognized in the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively.


32




ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
 
Introduction
 
The following discussion and analysis presents management's view of our business, financial condition and overall performance and should be read in conjunction with our 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 
Overview of Significant Events 
Liquidity and Capital Resources 
Contractual Obligations 
Results of Operations 
Off-Balance Sheet Arrangements 
Summary of Critical Accounting Estimates 
Recent Accounting Standards
Overview of Business
 
Cheniere Energy, Inc. (NYSE MKT: LNG), a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Energy Partners, L.P. ("Cheniere Partners") (NYSE MKT: CQP), which is a publicly traded limited partnership that we created in 2007. We own 100% of the general partner interest in Cheniere Partners and 84.5% of Cheniere Energy Partners LP Holdings, LLC ("Cheniere Holdings") (NYSE MKT: CQH), which owns a 55.9% limited partner interest in Cheniere Partners.

In 2013, we formed Cheniere Holdings, a publicly traded limited liability company, to hold our limited partner interests in Cheniere Partners. In December 2013, Cheniere Holdings completed an initial public offering of 36.0 million common shares at $20.00 per common share (the "Cheniere Holdings Offering").

The Sabine Pass LNG terminal is located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners' wholly owned subsidiary, Sabine Pass LNG, L.P. ("Sabine Pass LNG"), 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 regasification capacity of approximately 4.0 Bcf/d. Cheniere Partners is developing and constructing natural gas liquefaction facilities (the "Sabine Pass Liquefaction Project") at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"). Cheniere Partners plans to construct up to six Trains, which are in various stages of development. Each Train is expected to have nominal production capacity of approximately 4.5 mtpa. Cheniere Partners also owns the 94-mile Creole Trail Pipeline through a wholly owned subsidiary, Cheniere Creole Trail Pipeline, L.P. ("CTPL"), which interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines. One of our subsidiaries, Cheniere Marketing, LLC ("Cheniere Marketing"), is marketing LNG and natural gas on its own behalf and on behalf of Cheniere Partners, in an effort to utilize half of the LNG regasification capacity at the Sabine Pass LNG terminal during construction of the Sabine Pass Liquefaction Project. Cheniere Marketing has also entered into an LNG Sale and Purchase Agreement ("SPA") with Sabine Pass Liquefaction to purchase, at Cheniere Marketing's option, up to 104,000,000 MMBtu/yr of LNG.

We are developing a second natural gas liquefaction and export facility near Corpus Christi, Texas (the "Corpus Christi Liquefaction Project"). As currently contemplated, the proposed Corpus Christi Liquefaction LNG terminal would be designed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, have three LNG storage tanks with capacity of 10.1 Bcfe and two docks that can accommodate vessels with capacity of up to 267,000 cubic meters.



33




We are also in various stages of developing other projects, which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision.
Overview of Significant Events

Our significant accomplishments since January 1, 2013 and through the filing date of this Form 10-K, include the following:  

Cheniere
Our wholly owned subsidiary, Corpus Christi Liquefaction, LLC ("Corpus Christi Liquefaction"), entered into an SPA with PT Pertamina (Persero) ("Pertamina") under which Pertamina has agreed to purchase 39.7 million MMBtu of LNG per year (approximately 0.8 mtpa) upon the commencement of operations from the LNG export facility being developed near Corpus Christi, Texas (the "Corpus Christi Liquefaction Project");
Corpus Christi Liquefaction entered into two lump sum turnkey contracts for the engineering, procurement and construction ("EPC") of Trains and related facilities for the Corpus Christi Liquefaction Project; and
Cheniere Holdings completed its initial public offering of 36.0 million common shares at $20.00 per common share. Cheniere Holdings was formed by us to hold our Cheniere Partners limited partner interests. We ultimately received all of the $665.0 million of net proceeds from the Cheniere Holdings Offering from the repayment of Cheniere Holdings' intercompany indebtedness and payables owed to us and through a distribution by Cheniere Holdings to us. We intend to use the $665.0 million for the development of our existing assets, future projects and general corporate purposes.
Cheniere Partners
Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 2021 (the "2021 Sabine Pass Liquefaction Senior Notes"), $1.0 billion of 6.25% Senior Secured Notes due 2022 (the "2022 Sabine Pass Liquefaction Senior Notes") and $1.0 billion of 5.625% Senior Secured Notes due 2023 (the "2023 Sabine Pass Liquefaction Senior Notes" and collectively with the 2021 Sabine Pass Liquefaction Senior Notes and the 2022 Sabine Pass Liquefaction Senior Notes, the "Sabine Pass Liquefaction Senior Notes"). Net proceeds from these offerings are intended to be used to pay a portion of the capital costs incurred in connection with the construction of Trains 1 through 4 of the Sabine Pass Liquefaction Project;
Cheniere Partners sold 17.6 million common units to institutional investors for net proceeds, after deducting expenses, of $372.4 million, which includes the general partner's proportionate capital contribution of $7.4 million. Cheniere Partners used the proceeds from that offering to purchase the Creole Trail Pipeline Business, as described below;
Sabine Pass Liquefaction entered into four credit facilities (the "2013 Liquefaction Credit Facilities") totaling $5.9 billion (which were subsequently reduced to $5.0 billion in connection with the issuance of the 2022 Sabine Pass Liquefaction Senior Notes) to be used for costs associated with the construction of Trains 1 through 4 of the Sabine Pass Liquefaction Project;
Sabine Pass Liquefaction issued a notice to proceed to Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") under the lump sum turnkey contract for the engineering, procurement and construction of Trains 3 and 4 of the Sabine Pass Liquefaction Project (the "EPC Contract (Trains 3 and 4)");
Sabine Pass Liquefaction entered into an SPA with Centrica plc ("Centrica") that commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 91.25 million MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $274 million;
Cheniere Partners completed the acquisition of 100% of the equity interests in Cheniere Pipeline GP Interests, LLC held by Cheniere Pipeline Company, and the limited partner interest in CTPL held by Grand Cheniere Pipeline, LLC (the "Creole Trail Pipeline Business") for $480.0 million and reimbursed us $13.9 million for certain expenditures incurred prior to the closing date. Concurrent with the Creole Trail Pipeline Business acquisition closing, Cheniere Partners issued 12.0 million Class B units to us for aggregate consideration of $180.0 million. As a result of the two transactions, Cheniere Partners paid us net cash of $313.9 million;
CTPL entered into a $400.0 million term loan credit facility (the "CTPL Credit Facility") to fund capital expenditures on the Creole Trail Pipeline and for general business purposes; and
Cheniere Partners entered into an equity distribution agreement with Mizuho Securities USA Inc., under which Cheniere Partners may sell up to $500.0 million of common units through an at-the-market program.


34




Liquidity and Capital Resources

Although results are consolidated for financial reporting, Cheniere, Cheniere Holdings, Cheniere Partners, Sabine Pass Liquefaction and Sabine Pass LNG operate with independent capital structures. We expect the cash needs for at least the next twelve months will be met for each of these independent capital structures as follows:
Sabine Pass LNG through operating cash flows and existing unrestricted cash;
Sabine Pass Liquefaction through project debt and equity financings;
Cheniere Partners through operating cash flows from Sabine Pass LNG and existing unrestricted cash;
Cheniere Holdings through distributions from Cheniere Partners; and
Cheniere through existing unrestricted cash, services fees from Cheniere Holdings, Cheniere Partners and its other
subsidiaries, distributions from our investments in Cheniere Holdings and Cheniere Partners and operating
cash flows from our LNG and natural gas marketing businesses.

As of December 31, 2013, we had cash and cash equivalents of $960.8 million available to Cheniere. In addition, we had current and non-current restricted cash and cash equivalents of $1,629.5 million (which included current and non-current restricted cash and cash equivalents available to Cheniere Partners, Sabine Pass Liquefaction and Sabine Pass LNG) designated for the following purposes: $1,059.7 million for the Sabine Pass Liquefaction Project, $101.9 million for CTPL, $91.1 million for interest payments related to the Sabine Pass LNG Senior Secured Notes described below; and $376.8 million for other restricted purposes.

Cheniere Holdings

Cheniere Holdings was formed by us to hold our Cheniere Partners limited partner interests, thereby allowing us to segregate our lower risk, stable, cash flow generating assets from our higher risk, early stage development projects and marketing activities. As of December 31, 2013, we had an 84.5% direct ownership of Cheniere Holdings. We will receive dividends on our Cheniere Holdings shares from the distributions that Cheniere Holdings receives from Cheniere Partners, and we will receive management fees for managing Cheniere Holdings.

Cheniere Partners
 
Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. Through our interest in Cheniere Holdings, we indirectly own a 47.2% limited partner interest in Cheniere Partners in the form of 11,963,488 common units, 45,333,334 Class B units and 135,383,831 subordinated units. We also indirectly own a 2% general partner interest and the incentive distribution rights in Cheniere Partners. Cheniere Partners owns a 100% interest in Sabine Pass LNG, which is operating the regasification facilities at the Sabine Pass LNG terminal, and a 100% interest in Sabine Pass Liquefaction, which is constructing the Sabine Pass Liquefaction Project.
 
Prior to the Cheniere Holdings Offering, we received quarterly equity distributions from Cheniere Partners related to our limited partner and 2% general partner interests. We will continue to receive quarterly equity distributions from Cheniere Partners related to our 2% general partner interest, and we receive fees for providing services to Cheniere Partners, Cheniere Holdings, Sabine Pass LNG, Sabine Pass Liquefaction and CTPL. For the year ended December 31, 2013, we received $20.3 million in distributions on our common units, no cash distributions on our subordinated units or Class B units and $1.8 million in distributions on our general partner interest. During the year ended December 31, 2013, we received $102.9 million of service fees, in the aggregate, from Cheniere Partners, Sabine Pass LNG, Sabine Pass Liquefaction and CTPL.

Cheniere Partners' common unit and general partner distributions are being funded from accumulated operating surplus. We have not received distributions on our subordinated units with respect to the quarters ended on or after June 30, 2010. Cheniere Partners will not make distributions on our subordinated units until it generates additional cash flow from Sabine Pass LNG's excess capacity, the Sabine Pass Liquefaction Project or other new business, which would be used to make quarterly distributions on our subordinated units before any increase in distributions to the common unitholders.

Cheniere Partners' Class B units are subject to conversion, mandatorily or at the option of the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. The Cheniere Partners Class B units are not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale of substantially all of Cheniere Partners' assets). On a quarterly basis beginning on the initial purchase of the Class B units and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The accreted conversion


35




ratio of the Class B units owned by Cheniere and Blackstone CQP Holdco LP ("Blackstone") was 1.23 and 1.21, respectively, as of December 31, 2013. The Class B units will mandatorily convert into common units on the first business day following the record date with respect to Cheniere Partners' first distribution (the "Mandatory Conversion Date") after the earlier of the substantial completion date of Train 3 of the Sabine Pass Liquefaction Project or August 9, 2017, although if a notice to proceed is given to Bechtel for Train 3 prior to August 9, 2017, the Mandatory Conversion Date will be the substantial completion date of Train 3. The notice to proceed was given to Bechtel on May 28, 2013. Cheniere Partners currently expects the substantial completion date of Train 3 to occur before March 31, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.

LNG Terminal Business

Sabine Pass LNG Terminal

Regasification Facilities
 
The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which Sabine Pass LNG's customers are required to pay fixed monthly fees, whether or not they use the LNG terminal.  Each of Total Gas & Power North America, Inc. ("Total") 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 Sabine Pass LNG aggregating approximately $125 million annually for 20 years that commenced in 2009.  Total S.A. has guaranteed Total's obligations under its TUA up to $2.5 billion, subject to certain exceptions, and 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 Sabine Pass LNG aggregating approximately $250 million annually, continuing until at least 20 years after Sabine Pass Liquefaction delivers its first commercial cargo at the Sabine Pass Liquefaction Project, which may occur as early as late 2015.

Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.

Liquefaction Facilities

The Sabine Pass Liquefaction Project is being developed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. We are developing Trains 5 and 6 and commenced the regulatory approval process for these Trains in February 2013.

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

As of December 31, 2013, the overall project completion for Trains 1 and 2 and Trains 3 and 4 of the Sabine Pass Liquefaction Project were approximately 54% and 20%, respectively, which are ahead of the contractual schedule. Based on our current construction schedule, we anticipate that Train 1 will produce LNG as early as late 2015, and Trains 2, 3 and 4 are expected to commence operations on a staggered basis thereafter.
    
Customers

Sabine Pass Liquefaction has entered into four fixed price, 20-year SPAs with third parties that in the aggregate equate to 16 mtpa of LNG that commence with the date of first commercial delivery for Trains 1 through 4, which are fully permitted. In addition, Sabine Pass Liquefaction has entered into two fixed price, 20-year SPAs with third parties for another 3.75 mtpa of LNG that commence with the date of first commercial delivery for Train 5, which has not yet received regulatory approval for construction. Under the SPAs, the customers will purchase LNG from Sabine Pass Liquefaction for a price consisting of a fixed fee plus 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers may elect to cancel or suspend


36




deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to cargoes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA commences upon the start of operations of the specified Train. In aggregate, the fixed fee portion to be paid by these customers is approximately $2.3 billion annually for Trains 1 through 4, and $2.9 billion annually if we make a positive final investment decision with respect to Train 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of Trains 1 through 5, respectively.

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

Natural Gas Transportation and Supply

For Sabine Pass Liquefaction's feed gas transportation requirements, Sabine Pass Liquefaction has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CTPL and other third party pipeline companies. Sabine Pass Liquefaction has entered into enabling agreements with third parties, and will continue to enter into such agreements in order to secure feed gas for the Sabine Pass Liquefaction Project.

Construction

Trains 1 through 4 are being designed, constructed and commissioned by Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel"). Sabine Pass Liquefaction entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Train 1 and Train 2 (the "EPC Contract (Trains 1 and 2)") and the EPC Contract (Trains 3 and 4) under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause Sabine Pass Liquefaction to enter into a change order, or Sabine Pass Liquefaction agrees with Bechtel to a change order.

The total contract price of the EPC Contract (Trains 1 and 2) and the total contract price of the EPC Contract (Trains 3 and 4) are approximately $4.1 billion and $3.8 billion, respectively, reflecting amounts incurred under change orders through December 31, 2013. Total expected capital costs for Trains 1 through 4 are estimated to be between $9.0 billion and $10.0 billion before financing costs and between $12.0 billion and $13.0 billion after financing costs, including, in each case, estimated owner's costs and contingencies.

Pipeline Facilities

CTPL owns the Creole Trail Pipeline, a 94-mile pipeline interconnecting the Sabine Pass LNG terminal with a number of large interstate pipelines. In December 2013, CTPL began construction of certain modifications to allow the Creole Trail Pipeline to be able to transport natural gas to the Sabine Pass LNG terminal. Cheniere Partners estimates that the capital costs to modify the Creole Trail Pipeline will be approximately $100 million. The modifications are expected to be in service in time for the commissioning and testing of Trains 1 and 2.

Capital Resources

We currently expect that Sabine Pass Liquefaction's capital resources requirements with respect to Trains 1 through 4 of the Sabine Pass Liquefaction Project will be financed through one or more of the following: borrowings, equity contributions from Cheniere Partners and cash flows under the SPAs. We believe that with the net proceeds of borrowings, unfunded commitments under the 2013 Liquefaction Credit Facilities (as defined below) and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 4 of the Sabine Pass Liquefaction Project and to meet our currently anticipated capital, operating and debt service requirements. We currently project that we will generate cash flow by late 2015, when Train 1 of the Sabine Pass Liquefaction Project is anticipated to achieve initial LNG production.
    


37




Senior Secured Notes

As of December 31, 2013, subsidiaries of Cheniere Partners had five series of senior secured notes outstanding (collectively, the "Senior Notes"):
$1,665.5 million of 7.50% Senior Secured Notes due 2016 issued by Sabine Pass LNG (the "2016 Notes");
$420.0 million of 6.50% Senior Secured Notes due 2020 issued by Sabine Pass LNG (the "2020 Notes" and collectively with the 2016 Notes, the "Sabine Pass LNG Senior Notes");
$2,000.0 million of the 2021 Sabine Pass Liquefaction Senior Notes;
$1,000.0 million of the 2022 Sabine Pass Liquefaction Senior Notes; and
$1,000.0 million of the 2023 Sabine Pass Liquefaction Senior Notes.
Interest on the Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the Sabine Pass LNG Senior Notes are secured on a pari passu first-priority basis by a security interest in all of Sabine Pass LNG's equity interests and substantially all of Sabine Pass LNG's operating assets, and the Sabine Pass Liquefaction Senior Notes are secured on a first-priority basis by a security interest in all of the membership interests in Sabine Pass Liquefaction and substantially all of Sabine Pass Liquefaction's assets.

Sabine Pass LNG may redeem some or all of its 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.
Sabine Pass LNG 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. Sabine Pass LNG 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, Sabine Pass LNG 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 Sabine Pass LNG redeems 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.

At any time prior to November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes, or December 15, 2021, with respect to the 2022 Sabine Pass Liquefaction Senior Notes, or January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction may redeem all or a part of the Sabine Pass Liquefaction Senior Notes at a redemption price equal to the "make-whole" price set forth in the common indenture governing the Sabine Pass Liquefaction Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass Liquefaction also may at any time on or after November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes, or December 15, 2021, with respect to the 2022 Sabine Pass Liquefaction Senior Notes, or January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes, redeem the Sabine Pass Liquefaction Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the Sabine Pass Liquefaction Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

Under the indentures governing the Sabine Pass LNG Senior Notes, except for permitted tax distributions, Sabine Pass LNG may not make distributions until, among other requirements, deposits are made into debt service reserve accounts and a fixed charge coverage ratio test of 2:1 is satisfied. Under the indentures governing the Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction may not make any distributions until, among other requirements, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25:1.00 is satisfied.

The Sabine Pass Liquefaction Senior Notes are governed by a common indenture with restrictive covenants. Sabine Pass Liquefaction may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could


38




be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of Sabine Pass Liquefaction, including the Sabine Pass Liquefaction Senior Notes and the 2013 Liquefaction Credit Facilities described below.
    
2013 Liquefaction Credit Facilities

Sabine Pass Liquefaction has four credit facilities aggregating $5.0 billion, which will be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Sabine Pass Liquefaction Project. The principal of the loans made under the 2013 Liquefaction Credit Facilities must be repaid in quarterly installments, commencing with the earlier of the last day of the first full calendar quarter after the Train 4 completion date, as defined in the 2013 Liquefaction Credit Facilities, and September 30, 2018. Loans under the 2013 Liquefaction Credit Facilities bear interest at a variable rate per annum equal to, at Sabine Pass Liquefaction's election, the London Interbank Offered Rate ("LIBOR") plus the applicable margin. The applicable margins for LIBOR loans range from 2.3% to 3.0% prior to the completion of Train 4 and from 2.3% to 3.25% after such completion, depending on the applicable 2013 Liquefaction Credit Facility. The 2013 Liquefaction Credit Facilities also require Sabine Pass Liquefaction to pay a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of undrawn commitments. Interest on LIBOR loans and the commitment fees are due and payable at the end of each LIBOR period and quarterly, respectively.

2012 Liquefaction Credit Facility

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

CTPL has the CTPL Credit Facility, which will be used to fund modifications to the Creole Trail Pipeline and for general business purposes. Loans under the CTPL Credit Facility bear interest at a variable rate per annum equal to, at CTPL's election, LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans under the CTPL Credit Facility is 3.25%. The CTPL Credit Facility matures in 2017 when the full amount of the outstanding principal obligations must be repaid.

Corpus Christi LNG Terminal
 
Liquefaction Facilities

In September 2011, we formed Corpus Christi Liquefaction, LLC ("Corpus Christi Liquefaction") to develop a natural gas liquefaction facility near Corpus Christi, Texas on over 1,000 acres of land that we own or control. As currently contemplated, the proposed Corpus Christi Liquefaction LNG terminal would be designed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, have three LNG storage tanks with capacity of 10.1 Bcfe and two docks that can accommodate vessels with capacity of up to 267,000 cubic meters. In August 2012, Corpus Christi Liquefaction filed an application with the FERC for authorization to site, construct and operate the Corpus Christi Liquefaction Project. Simultaneously, Cheniere Marketing filed an application with the DOE to export up to 15 mtpa of domestically produced LNG to FTA and non-FTA countries from the proposed Corpus Christi Liquefaction Project. In October 2012, the DOE granted Cheniere Marketing authority to export 15 mtpa of domestically produced LNG to FTA countries from the proposed Corpus Christi Liquefaction Project.

Customer

Corpus Christi Liquefaction has entered into a fixed price, 20-year SPA with Pertamina with an annual contract quantity of 39,680,000 MMBtu of LNG, which equates to approximately 0.8 mtpa of LNG. Under the SPA, Pertamina will purchase LNG from Corpus Christi Liquefaction for a price consisting of a fixed fee of $3.50 plus 115% of Henry Hub per MMBtu of LNG, equating to expected annual contracted cash flow from fixed fees of approximately $139 million. In certain circumstances, Pertamina may elect to cancel or suspend deliveries of LNG cargoes, in which case Pertamina would still be required to pay the fixed fee with respect to cargoes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for inflation.


39




The SPA and contracted volumes to be made available under the SPA are not tied to a specific Train; however, the term of the SPA commences upon the start of operations of the first Train at the Corpus Christi Liquefaction Project.

Construction

In December 2013, Corpus Christi Liquefaction entered into contracts with Bechtel for the engineering, procurement and construction of Trains and related facilities for the Corpus Christi Liquefaction Project under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause Corpus Christi Liquefaction to enter into a change order, or Corpus Christi Liquefaction agrees with Bechtel to a change order. Total expected costs for the three Trains and the related facilities, excluding pipeline facilities, are estimated to be between $10.5 billion and $11.0 billion before financing costs, including an estimate for owner's costs and contingencies.

We will contemplate making a final investment decision to commence construction of the Corpus Christi Liquefaction Project based upon, among other things, entering into acceptable commercial arrangements, receiving regulatory authorization from the FERC to construct and operate the liquefaction assets, securing pipeline transportation of natural gas to the Corpus Christi Liquefaction Project and obtaining adequate financing to construct the facility.

Pipeline Facilities

In conjunction with the Corpus Christi Liquefaction Project, we filed an application with the FERC in August 2012 for authorization to site, construct and operate 23 miles of 48" pipeline that would interconnect the Corpus Christi Liquefaction Project with five inter- and intrastate natural gas pipelines (the "Corpus Christi Pipeline"). The pipeline is designed to transport 2.25 Bcf/d of feed and fuel gas required by the Corpus Christi Liquefaction Project from the existing natural gas pipeline grid.

Capital Resources

We expect to finance the construction costs of the Corpus Christi Liquefaction Project from one or more of the following: project financing, debt and equity offerings and operating cash flow.

LNG and Natural Gas Marketing Business
 
Our wholly owned subsidiary, Cheniere Marketing, is engaged in the LNG and natural gas marketing business and is seeking to develop a portfolio of long-term, short-term and spot LNG purchase and sale agreements. Cheniere Marketing has purchased, transported and unloaded commercial LNG cargoes into the Sabine Pass LNG terminal and has used trading strategies intended to maximize margins on these cargoes. Cheniere Marketing has secured the following rights and obligations to support its business:
the right to deliver cargoes to the Sabine Pass LNG terminal during the construction of the Sabine Pass Liquefaction Project in exchange for payment of 80% of the expected gross margin from each cargo to Cheniere Energy Investments, LLC ("Cheniere Investments"), a wholly owned subsidiary of Cheniere Partners;
the Cheniere Marketing SPA, with the right to purchase, at Cheniere Marketing's option, up to 104,000,000 MMBtu/yr of LNG from Sabine Pass Liquefaction, to the extent Sabine Pass Liquefaction is able to produce LNG in excess of that required for other customers: Cheniere Marketing may purchase LNG at a price of 115% of Henry Hub plus up to $3.00 per MMBtu for the most profitable 36,000,000 MMBtu of cargoes sold each year by Cheniere Marketing; and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing; and
three LNG vessel time charters with subsidiaries of two ship owners, Dynagas, Ltd. and Teekay LNG Operating LLC. The annual payments for the vessel charters are approximately $92 million. The charters have an initial term of 5 years with the option to renew with Dynagas, Ltd. for a 2-year extension with similar terms as the initial term. Cheniere Marketing expects to receive delivery of the vessel from Dynagas, Ltd. in June 2015 and the vessels from Teekay LNG Operating LLC in January 2016 and June 2016.

Corporate and Other Activities
 
We are required to maintain corporate general and administrative functions to serve our business activities described above. 



40




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
 
 
 
 
 
Proceeds from issuances of long-term debt, net of debt issuance costs
$
4,504,478

 
$
520,000

 
$

Sale of common shares by Cheniere Holdings
665,001

 

 

Sale of common units by Cheniere Partners
364,775

 
204,878

 
52,351

Sale of common stock, net
3,698

 
1,200,705

 
468,598

Sale of Class B units by Cheniere Partners

 
1,387,342

 

Excess tax benefit from stock-based compensation

3,385

 

 

Total sources of cash and cash equivalents
5,541,337

 
3,312,925

 
520,949

 
 
 
 
 
 
Uses of cash and cash equivalents
 

 
 
 
 

LNG terminal costs, net
(3,114,343
)
 
(1,117,956
)
 
(8,934
)
Investment in restricted cash and cash equivalents, net of uses of restricted cash and cash equivalents
(953,998
)
 
(184,171
)
 
(15,914
)
Debt issuance and deferred financing costs
(311,050
)
 
(223,079
)
 
(4,341
)
Payments related to tax withholdings for stock-based compensation

(136,367
)
 
(20,414
)
 
(14,363
)
Repayments and prepayments of debt

(100,000
)
 
(1,326,514
)
 

Investment in Cheniere Partners
(11,122
)
 
(545,144
)
 
(17,806
)
Distributions to non-controlling interest
(69,220
)
 
(36,327
)
 
(28,215
)
Operating cash flow
(52,436
)
 
(107,840
)
 
(42,764
)
Other
(33,670
)
 
(8,929
)
 
(3,613
)
Total uses of cash and cash equivalents
(4,782,206
)
 
(3,570,374
)
 
(135,950
)
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
759,131

 
(257,449
)
 
384,999

Cash and cash equivalents—beginning of period
201,711

 
459,160

 
74,161

Cash and cash equivalents—end of period
$
960,842

 
$
201,711

 
$
459,160


Proceeds from Debt Issuances and Credit Facilities and Debt Issuance and Deferred Financing Costs
 
In February 2013 and April 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion, before premium, of the 2021 Sabine Pass Liquefaction Senior Notes. In April 2013,  Sabine Pass Liquefaction also issued $1.0 billion of the 2023 Sabine Pass Liquefaction Senior Notes. In November 2013, Sabine Pass Liquefaction also issued $1.0 billion of the 2022 Sabine Pass Liquefaction Senior Notes. Net proceeds from those offerings are intended to be used to pay a portion of the capital costs incurred in connection with the construction of the Sabine Pass Liquefaction Project. In May 2013, Sabine Pass Liquefaction closed the 2013 Liquefaction Credit Facilities aggregating $5.9 billion (which were subsequently reduced to $5.0 billion in connection with the issuance of the 2022 Sabine Pass Liquefaction Senior Notes). Sabine Pass Liquefaction borrowed $100.0 million under the 2013 Liquefaction Credit Facilities in June 2013 after meeting the required conditions precedent. Also in May 2013, CTPL entered into the CTPL Credit Facility, which will be used to fund modifications to the Creole Trail Pipeline and for general business purposes. Debt issuance costs primarily relate to up-front fees paid by Sabine Pass Liquefaction upon the closing of the 2013 Liquefaction Credit Facilities and the Sabine Pass Liquefaction Senior Notes.

In October 2012, Sabine Pass LNG issued the 2020 Notes. In July 2012, Sabine Pass Liquefaction entered into the 2012 Liquefaction Credit Facility with a syndicate of lenders. Sabine Pass Liquefaction borrowed $100.0 million under the 2012 Liquefaction Credit Facility in August 2012 after meeting the required conditions precedent to the initial advance. Debt issuance costs primarily relate to $212.8 million paid by Sabine Pass Liquefaction upon the closing of the 2012 Liquefaction Credit Facility.



41




Sale of Common Shares by Cheniere Holdings

In December 2013, Cheniere Holdings completed its initial public offering of 36.0 million common shares at $20.00 per common share. Cheniere Holdings was formed by us to hold our Cheniere Partners limited partner interests. We ultimately received all of the $665.0 million of net proceeds from the Cheniere Holdings Offering from the repayment of Cheniere Holdings' intercompany indebtedness and payables owed to us and through a distribution by Cheniere Holdings to us. We intend to use the $665.0 million for the development of our existing assets, future projects and general corporate purposes.

Sale of Common Units by Cheniere Partners

In February 2013, Cheniere Partners sold 17.6 million common units to institutional investors for net proceeds, after deducting expenses, of $365.0 million. Cheniere Partners used the proceeds from this offering to purchase the Creole Trail Pipeline Business.

In September 2012, Cheniere Partners sold 8.0 million common units in an underwritten public offering at a price of $25.07 per common unit for net cash proceeds of $194.0 million. In addition, during the year ended December 31, 2012, Cheniere Partners sold 0.5 million common units for net cash proceeds of $11.1 million under its at-the-market program initiated in January 2011.

In January 2011, Cheniere Partners initiated an at-the-market program to sell up to 1.0 million common units, the proceeds from which have primarily been used to fund development costs associated with the Sabine Pass Liquefaction Project. As of December 31, 2011, Cheniere Partners had received $9.0 million in net proceeds from its sale of common units related to this at-the-market program.

In September 2011, Cheniere Partners sold 3.0 million common units in an underwritten public offering and 1.1 million common units to our subsidiary, Cheniere Common Units Holding, LLC, at a price of $15.25 per common unit. Cheniere Partners used the net proceeds from the offering for general business purposes, including development costs for the Sabine Pass Liquefaction Project.

Sale of Common Stock, Net

In March 2012, we sold 24.2 million shares of Cheniere common stock in an underwritten public offering for net cash proceeds of approximately $351.9 million. In June 2012, we used a portion of the net proceeds from this offering to repay in full the loans outstanding under a $250.0 million credit agreement entered into in August 2008 (the "2008 Loans"). In May 2012, we sold 31.0 million shares of Cheniere common stock pursuant to a stock purchase agreement for net proceeds of $468.1 million, which was used, along with cash on hand, to purchase $500 million of Class B units from Cheniere Partners. In July 2012, we sold 28.0 million shares of Cheniere common stock in an underwritten public offering for net cash proceeds of $380.3 million. We used a portion of the net proceeds from the offering to repay our $325.0 million convertible senior unsecured notes due August 2012, and will use the remaining amount for capital expenditures on the Creole Trail Pipeline and general corporate purposes.

In June 2011, we sold 12.7 million shares of Cheniere common stock in an underwritten public offering at a price of $10.35 per share. In December 2011, we sold 41.7 million shares of Cheniere common stock in an underwritten public offering at a price of $8.35 per share. The Company used the net proceeds from the offerings for general corporate purposes, including repayment of indebtedness.

Sale of Class B Units by Cheniere Partners

During the year ended December 31, 2012, Cheniere Partners issued and sold an aggregate of 100 million Class B units to Blackstone at a price of $15.00 per Class B unit, resulting in total net proceeds of $1,387.3 million.

LNG Terminal Costs, net

Capital expenditures of $3,114.3 million in the year ended December 31, 2013 primarily related to the construction of Trains 1 through 4. In June 2012, we began capitalizing costs associated with construction of Trains 1 and 2 of the Sabine Pass Liquefaction Project, and in May 2013, we began capitalizing costs associated with Trains 3 and 4 of the Sabine Pass Liquefaction Project. Capital expenditures for our LNG terminals were $1,118.0 million and $8.9 million in the years ended December 31, 2012 and 2011, respectively.  



42




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

In the year ended December 31, 2013, we invested $1.0 billion in restricted cash and cash equivalents. This investment in restricted cash and cash equivalents is primarily a result of the $4,083.7 million investment in restricted cash and cash equivalents primarily related to the net proceeds from the Sabine Pass Liquefaction Senior Notes, the CTPL Credit Facility and the 2013 Liquefaction Credit Facilities. This investment in restricted cash and cash equivalents was partially offset by the use of $3,129.7 million of restricted cash and cash equivalents primarily related to the construction of the Sabine Pass Liquefaction Project.

In the year ended December 31, 2012, the $184.2 million investment in restricted cash and cash equivalents primarily resulted from the $1,771.7 million investment in restricted cash related to the net proceeds from Blackstone's purchase of $1.5 billion of Class B units and the June 2012 sale of Cheniere common stock, the proceeds of which were restricted to our purchase of Class B units from Cheniere Partners. This investment in restricted cash and cash equivalents in the year ended December 31, 2012 was partially offset by the use of $1,587.5 million of restricted cash and cash equivalents for the construction of Trains 1 and 2 and our purchase of Class B units from Cheniere Partners, the proceeds of which are being used for the construction of Trains 1 and 2.

In the year ended December 31, 2011, the $15.9 million investment in restricted cash and cash equivalents primarily resulted from Cheniere Partners' public offering in September 2011 in which Cheniere Partners sold 3.0 million common units in an underwritten public offering and 1.1 million common units to Cheniere Common Units Holding, LLC at a price of $15.25 per common unit. Cheniere Partners used the net proceeds from the offering for general business purposes, including development costs for the Sabine Pass Liquefaction Project.
 
Payments Related to Tax Withholdings for Stock-based Compensation
 
During 2013, 2012 and 2011, we used $136.4 million, $20.4 million and $14.4 million, respectively, of cash and cash equivalents to purchase restricted stock that was returned to us by employees to cover taxes related to their restricted stock that vested during such periods. The increase in 2013 as compared to 2012 primarily resulted from the vesting of awards under the long-term commercial bonus pools related to Trains 1 through 4. The increase in 2012 as compared to 2011 primarily resulted from the vesting of awards under the long-term commercial bonus pool related to Trains 1 and 2.

Repayments and Prepayments of Debt
 
In the year ended December 31, 2013, the 2012 Liquefaction Credit Facility was amended and restated with the 2013 Liquefaction Credit Facilities described above and $100.0 million of outstanding borrowings under the 2012 Liquefaction Credit Facility were repaid in full.

In the year ended December 31, 2012, we repurchased $1,326.5 million of debt. In January 2012, we used a portion of the net proceeds from the public offering of Cheniere common stock in December 2011 to repay in full the loans outstanding under a $400.0 million credit agreement entered into in 2007 (the "2007 Term Loan"). In June 2012, we used a portion of the net proceeds from the public offering of Cheniere common stock in March 2012 to repay in full the 2008 Loans. In August 2012, we used a portion of the net proceeds from the public offering of Cheniere common stock in July 2012 to repay in full our $325.0 million convertible senior unsecured notes due August 2012. During the fourth quarter of 2012, Sabine Pass LNG repurchased its $550.0 million 7.25% Senior Secured Notes due 2013 (the "2013 Notes"). Funds used for the repurchase included proceeds received from the newly issued 2020 Notes and from an equity contribution from Cheniere Partners.

Investment in Cheniere Partners

In the year ended December 31, 2012, we invested $534.9 million in Cheniere Partners related to the purchase of Class B units and general partner units.

Distributions to Non-controlling Interest
 
During 2013, 2012 and 2011, Cheniere Partners distributed $69.2 million, $36.3 million and $28.2 million, respectively, to its non-affiliated common unitholders.

Operating Cash Flow
 
Net cash used in operations was $52.4 million, $107.8 million and $42.8 million in 2013, 2012 and 2011, respectively. Net cash used in operations related primarily to the general administrative overhead costs, pipeline operations costs and LNG


43




and natural gas marketing overhead, offset by earnings from our LNG and natural gas marketing business. The decrease in cash used in operations in the year ended December 31, 2013 compared to 2012 primarily resulted from decreased interest expense in the year ended December 31, 2013 as a result of the capitalization of interest on Sabine Pass Liquefaction's debt, the reduction of our indebtedness outstanding in 2012 and the purchase of a royalty from Crest Energy in March 2012 (the "Crest Royalty").

The increase in cash used in operations in the year ended December 31, 2012 compared to 2011 primarily resulted from increased general administrative overhead costs primarily resulting from the August 2012 vesting of awards under the long-term commercial bonus pool and the purchase of the Crest Royalty as described in Note 16—"Commitments and Contingencies" of our Notes to Consolidated Financial Statements.

Issuances of Common Stock
 
During 2013, 2012 and 2011, 0.2 million, 0.1 million and zero shares, respectively, of our common stock were issued pursuant to the exercise of stock options.  

During 2013, 2012 and 2011, 18.9 million, 10.3 million and 7.8 million shares, respectively, of restricted stock were issued to new and existing employees.  

During 2013, 2012 and 2011, we raised $3.7 million, $0.8 million and zero proceeds, respectively, from the exercise of stock options or the exchange or exercise of warrants.

Contractual Obligations
 
We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2013 (in thousands).
 
 
Payments Due for Years Ended December 31,
 
 
Total
 
2014
 
2015-2016
 
2017-2018
 
Thereafter
Construction and purchase obligations (1)
 
$
4,334,551

 
$
2,283,852

 
$
1,840,670

 
$
210,029

 
$

Long-term debt (2)
 
6,585,500

 

 
1,665,500

 
400,000

 
4,520,000

Interest payments (2)
 
2,817,267

 
457,495

 
904,984

 
643,436

 
811,352

Operating lease obligations (3)
 
995,433

 
15,281

 
132,762

 
219,343

 
628,047

Other obligations (4)
 
10,834

 
4,456

 
5,937

 
441

 

Total
 
$
14,743,585

 
$
2,761,084

 
$
4,549,853

 
$
1,473,249

 
$
5,959,399

 
(1)
Construction and purchase obligations primarily relate to EPC Contract (Trains 1 and 2) and EPC Contract (Trains 3 and 4).  A discussion of these obligations can be found at Note 16—"Commitments and Contingencies" 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.  A discussion of these obligations can be found at Note 9—"Long-Term Debt" of our Notes to Consolidated Financial Statements.
(3)
Operating lease obligations primarily relate to LNG vessel time charters, land site and tug leases related to the Sabine Pass LNG terminal and corporate office leases. Minimum lease payments have not been reduced by a minimum sublease rental of $75.0 million due in the future under non-cancelable subleases. A discussion of these obligations and sublease rental payments can be found at Note 15—"Leases" of our Notes to Consolidated Financial Statements.
(4)
Includes obligations primarily related to cooperative endeavor agreements, telecommunication services and software licensing.
 
In addition, in the ordinary course of business, we maintain letters of credit and have certain cash and cash equivalents restricted in support of certain performance obligations of our subsidiaries. Restricted cash and cash equivalents totaled $1,629.5 million at December 31, 2013. For more information, see Note 3—"Restricted Cash and Cash Equivalents" of our Notes to Consolidated Financial Statements.



44




Results of Operations
 
2013 vs. 2012
 
Our consolidated net loss was $507.9 million, or $2.32 per share (basic and diluted), in 2013 compared to a net loss of $332.8 million, or $1.83 per share (basic and diluted), in 2012. This $175.1 million increase in net loss was primarily a result of increased general and administrative expense ("G&A Expense"), loss on early extinguishment of debt and increased LNG terminal operating expense, which was partially offset by increased derivative gain and decreased interest expense, net. G&A Expense increased $232.4 million in 2013 as compared to 2012 primarily as a result of the timing of awards under bonus plans relating to Trains 1 through 4 of the Sabine Pass Liquefaction Project. Loss on early extinguishment of debt increased $73.9 million in 2013 as compared to 2012 primarily as a result of issuances of the Sabine Pass Liquefaction Senior Notes that resulted in the termination of a portion of the commitments under the 2012 Liquefaction Credit Facility and the 2013 Liquefaction Credit Facilities. LNG terminal operating expense increased $32.1 million in 2013 as compared to 2012 primarily as a result of the loss incurred to purchase LNG to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, increased LNG terminal maintenance and repair costs and increased fuel costs at the Sabine Pass LNG terminal. We anticipate continuing to incur a similar amount of terminal use agreement maintenance expense until minimum inventory quantities are maintained, which we expect to occur in 2015. Derivative gain increased $83.4 million in 2013 as compared to 2012 primarily as a result of the change in fair value of Sabine Pass Liquefaction's interest rate derivatives to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities. Interest expense, net decreased $22.4 million in 2013 as compared to 2012 primarily as a result of reduction of our indebtedness outstanding in 2012 and the capitalization of interest on Sabine Pass Liquefaction's debt. Development expense in 2013 primarily related to the development of Trains 5 and 6 of the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, while development expense in 2012 primarily related to Trains 1 through 6 of the Sabine Pass Liquefaction Project.

2012 vs. 2011
 
Our consolidated net loss was $332.8 million, or $1.83 per share (basic and diluted), in 2012 compared to a net loss of $198.8 million, or $2.60 per share (basic and diluted), in 2011. This increase in net loss was primarily a result of increased G&A Expense, loss on early extinguishment of debt, increased LNG development expense and increased LNG terminal operating expense, which was partially offset by decreased interest expense, net. G&A Expense increased $63.7 million in 2012 as compared to 2011 primarily as a result of the August 2012 vesting of the awards under bonus plans relating to Trains 1 and 2 of the Sabine Pass Liquefaction Project. Loss on early extinguishment of debt increased $57.7 million in 2012 as compared to 2011 as a result of the early repayments in full of the 2007 Term Loan and the 2008 Loans and the make-whole payments associated with the early repayments in full of the 2013 Notes. LNG terminal development expense increased $25.3 million in 2012 as compared to 2011 primarily as a result the development of Trains 1 through 6 of the Sabine Pass Liquefaction Project in 2013 as compare to the development of Trains 1 through 4 of the Sabine Pass Liquefaction Project in 2012. LNG terminal operating expense increased $18.0 million in 2012 as compared to 2011 primarily as a result of the loss incurred to purchase LNG to maintain the cryogenic readiness of the Sabine Pass LNG terminal and increased dredging services in 2012. Interest expense, net decreased $58.6 million in 2012 as compared to 2011 primarily as a result of the reduction of our indebtedness outstanding 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, including goodwill, 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


45




price environment.  Significant negative industry or economic trends, including a significant decline in the market price of our common stock, reduced estimates of future cash flows for our business segments or disruptions to our business could lead to an impairment charge of our long-lived assets, including goodwill 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, including goodwill, 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, valuation allowances for net deferred tax assets, valuations of derivative instruments, valuations of noncash compensation and collectability of accounts receivable and other assets.

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

We use derivative instruments from time to time to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory, to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal, and to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities. We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 11—"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. 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 and losses in positions to hedge the cash flows attributable to the future sale of LNG inventory are classified as marketing and trading revenues on our Consolidated Statements of Operations. Gains or losses in the positions to mitigate the price risk from future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal are classified as derivative gain (loss) on our Consolidated Statements of Operations.

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



46




Fair Value of Financial Instruments
 
The carrying amounts of cash and cash equivalents, restricted cash and cash equivalents, restricted certificates of deposit, 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.

Income Taxes
 
Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the tax basis of assets and liabilities and their reported amounts in the consolidated financial statements. Deferred tax assets and liabilities are included in the consolidated financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period's provision for income taxes. A valuation allowance equal to our federal and state net deferred tax asset balance has been established due to the uncertainty of realizing the tax benefits related to our federal and state net deferred tax assets.
  
Goodwill
 
Goodwill represents the excess of cost over fair value of the assets of businesses acquired. The goodwill on our Consolidated Balance Sheets as of December 31, 2013 and 2012 is associated with our LNG terminal reporting unit. We determine our reporting units by identifying each unit that engaged in business activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the entities' chief operating decision makers for purposes of resource allocation and performance assessment, and had discrete financial information.

Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. During the fourth quarters of 2013 and 2012, we performed a qualitative assessment of goodwill in accordance with Financial Accounting Standards Board ("FASB") guidance which permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If we fail the qualitative test, then we must compare our management's estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.

The annual reviews of goodwill in 2013 and 2012 did not result in impairment charges. The fair value of the reporting unit substantially exceeds its carrying value for both periods and it was not "more likely than not" that the fair value of our LNG terminal segment was less than its carrying value. As discussed above regarding our use of estimates, our judgments and assumptions are inherent in our management's estimate of future cash flows used to determine the estimate of the reporting unit's fair value. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.

Share-Based Compensation Expense
 
We recognize compensation expense for all share-based payments using the Black-Scholes-Merton option valuation model. We recognize share-based compensation net of an estimated forfeiture rate and only recognize compensation cost for those shares expected to vest on a straight-line or accelerated basis over the requisite service period of the award.  
 
Determining the appropriate fair value model and calculating the fair value of share-based payment awards requires the use of highly subjective assumptions, including the expected life of the share-based payment awards and stock price volatility. We believe that implied volatility, calculated based on traded options of our common stock, combined with historical volatility is an appropriate indicator of expected volatility and future stock price trends. Therefore, the expected volatility for the years ended December 31, 2013 and 2012 used in our fair value model was based on a combination of implied and historical volatilities. The assumptions used in calculating the fair value of share-based payment awards represent our best estimates, but these estimates involve inherent uncertainties and the application of management's judgment. As a result, if factors change and we use different assumptions, our share-based compensation expense could be materially different in the future. In addition, we are required to estimate the expected forfeiture rate and only recognize expense for those shares expected to vest. If our actual forfeiture rate is materially different from our estimate, future share-based compensation expense could be significantly different from what we


47




have recorded in the current period (See Note 14—"Share-Based Compensation" of our Notes to Consolidated Financial Statements).
  
Asset Retirement Obligations
 
We recognize asset retirement obligations ("AROs") for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our recognition of AROs is described below.

Currently, the Sabine Pass LNG terminal is our only constructed and operating LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is zero. Therefore, we have not recorded an ARO associated with the Sabine Pass LNG terminal.

Currently, the Creole Trail Pipeline is our only constructed and operating natural gas pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. Therefore, we have concluded that due to advanced technology associated with current natural gas pipelines and our intent to operate the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States, we have not recorded an ARO associated with the Creole Trail Pipeline.
 
Recent Accounting Standards
 
In February 2013, the Financial Accounting Standards Board ("FASB") issued guidance that requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, entities are required to cross-reference to other disclosures required under GAAP that provide additional detail on these amounts. This standard is effective prospectively for reporting periods beginning after December 15, 2012. We adopted this standard effective January 1, 2013. The adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows, as it only expanded disclosures.

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



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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 variability in expected future cash flows attributable to the future sale of our LNG inventory ("LNG Inventory Derivatives") and to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass 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 of our LNG Inventory Derivatives and Fuel Derivatives. The VaR is calculated using the Monte Carlo simulation method. The table below provides information about our LNG Inventory Derivatives and Fuel Derivatives that are sensitive to changes in natural gas prices and interest rates as of December 31, 2013 (in thousands, except for volume and price range data):
Hedge Description
 
Hedge Instrument
 
Contract Volumes (MMBtu)
 
Price Range ($/MMBtu)
 
Final Hedge Maturity Date
 
Fair Value (in thousands)
 
VaR (in thousands)
LNG Inventory Derivatives
 
Fixed price natural gas swaps
 
1,029,890
 
$3.732 - $4.475
 
April 2014
 
$
(171
)
 
$
(54
)
Fuel Derivatives
 
Fixed price natural gas swaps
 
987,500
 
$4.222 - $4.427
 
January 2015
 
$
126

 
$
11


Interest Rate Risk

We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities ("Interest Rate Derivatives"). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the full 7-year term of the Interest Rate Derivatives. This 10% change in interest rates resulted in a change in the fair value of the Interest Rate Derivatives of $31.2 million. The table below provides information about our Interest Rate Derivatives that are sensitive to changes in the forward 1-month LIBOR curve as of December 31, 2013:
Hedge Description
 
Hedge Instrument
 
Initial Notional Amount
 
Maximum Notional Amount
 
Fixed Interest Rate Range (%)
 
Final Hedge Maturity Date
 
Fair Value (in thousands)
 
10% Change in LIBOR (in thousands)
Interest Rate Derivatives
 
Interest rate swaps
 
$20.0 million
 
$3.6 billion
 
1.99
 
May 2020
 
$
84,639

 
$
31,161





49




ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
CHENIERE ENERGY, INC. AND SUBSIDIARIES
 



50




MANAGEMENT'S REPORTS TO THE STOCKHOLDERS OF CHENIERE ENERGY, INC.
 
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 Cheniere Energy, Inc. and its subsidiaries ("Cheniere"). 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"). Cheniere'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 Cheniere 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.

Cheniere's independent registered public accounting firm, Ernst & Young LLP, have issued an audit report on Cheniere's internal control over financial reporting as of December 31, 2013, which is contained in this Form 10-K.
 
Management's Certifications
 
The certifications of Cheniere's Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere's Form 10-K.
 
CHENIERE ENERGY, INC.
 
 
 
 
 
By:
/s/ Charif Souki
 
By:
/s/ Michael J. Wortley
 
Charif Souki
Chief Executive Officer and President
(Principal Executive Officer)
 
 
Michael J. Wortley
Senior Vice President
and Chief Financial Officer
(Principal Financial Officer)



51




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of
Cheniere Energy, Inc.


We have audited the accompanying consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive loss, stockholders' equity (deficit), and cash flows for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cheniere Energy, Inc. 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. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cheniere Energy, Inc.'s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 21, 2014 expressed an unqualified opinion thereon.



 
/s/    ERNST & YOUNG LLP
Ernst & Young LLP
 



Houston, Texas
February 21, 2014















52





REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of
Cheniere Energy, Inc.


We have audited Cheniere Energy, Inc. and subsidiaries' internal control over financial reporting as of December 31, 2013 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). Cheniere Energy, Inc. and subsidiaries' management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Cheniere Energy, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013 based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries as of December 31, 2013 and 2012 and the related consolidated statements of operations, comprehensive loss, stockholders' equity (deficit) and cash flows for each of the three years in the period ended December 31, 2013, and our report dated February 21, 2014 expressed an unqualified opinion thereon.
                    


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






53


CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
 
December 31,
 
2013
 
2012
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
960,842

 
$
201,711

Restricted cash and cash equivalents
598,064

 
520,263

Accounts and interest receivable
4,486

 
3,486

LNG inventory
10,563

 
7,045

Prepaid expenses and other
17,225

 
16,058

Total current assets
1,591,180

 
748,563

 
 
 
 
Non-current restricted cash and cash equivalents
1,031,399

 
272,924

Property, plant and equipment, net
6,454,399

 
3,282,305

Debt issuance costs, net
313,944

 
220,949

Non-current derivative assets
98,123

 

Goodwill
76,819

 
76,819

Intangible LNG assets
3,366

 
4,356

Other
104,007

 
33,169

Total assets
$
9,673,237

 
$
4,639,085

 
 
 
 
LIABILITIES AND STOCKHOLDERS' EQUITY
 

 
 

Current liabilities
 

 
 

Accounts payable
$
10,367

 
$
74,360

Accrued liabilities
186,552

 
58,737

Deferred revenue
26,593

 
26,540

Other
13,499

 
126

Total current liabilities
237,011

 
159,763

 
 
 
 
Long-term debt, net of discount
6,576,273

 
2,167,113

Non-current derivative liabilities

 
26,424

Long-term deferred revenue
17,500

 
21,500

Other non-current liabilities
2,396

 
2,680

 
 
 
 
Commitments and contingencies


 


 
 
 
 
Stockholders' equity
 

 
 

Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued

 

Common stock, $0.003 par value
 

 
 

Authorized: 480.0 million shares at December 31, 2013 and 2012
 

 
 

Issued and outstanding: 238.1 million and 223.4 million shares at December 31, 2013 and 2012, respectively
716

 
671

Treasury stock: 9.0 million and 4.7 million shares at December 31, 2013 and 2012, respectively, at cost
(179,826
)
 
(39,115
)
Additional paid-in-capital
2,459,699

 
2,168,781

Accumulated deficit
(2,100,907
)
 
(1,592,985
)
Accumulated other comprehensive loss

 
(27,351
)
Total stockholders' equity
179,682

 
510,001

Non-controlling interest
2,660,375

 
1,751,604

Total equity
2,840,057

 
2,261,605

Total liabilities and equity
$
9,673,237

 
$
4,639,085



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


54


CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
Revenues
 
 
 
 
 
LNG terminal revenues
$
265,406

 
$
265,894

 
$
274,272

Marketing and trading revenues
242

 
(1,172
)
 
13,554

Other
1,565

 
1,498

 
2,618

Total revenues
267,213

 
266,220

 
290,444


 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
General and administrative expense
384,512

 
152,081

 
88,427

Depreciation, depletion and amortization
61,209

 
66,407

 
63,405

LNG terminal operating expense
89,169

 
57,076

 
39,101

LNG terminal development expense
60,934

 
66,112

 
40,803

Other
375

 
376

 
562

Total operating costs and expenses
596,199

 
342,052

 
232,298

Income (loss) from operations
(328,986
)
 
(75,832
)
 
58,146

 
 
 
 
 
 
Other income (expense)


 


 


Interest expense, net
(178,400
)
 
(200,811
)
 
(259,393
)
Loss on early extinguishment of debt
(131,576
)
 
(57,685
)
 

Derivative gain (loss)
83,448

 
58

 
(2,251
)
Other income (expense)
1,091

 
(11,367
)
 
320

Total other expense
(225,437
)
 
(269,805
)
 
(261,324
)
Loss before income taxes and non-controlling interest
(554,423
)
 
(345,637
)
 
(203,178
)
Income tax provision
(4,340
)
 
(4
)
 
(160
)
Net loss
(558,763
)
 
(345,641
)
 
(203,338
)
Non-controlling interest
50,841

 
12,861

 
4,582

Net loss attributable to common stockholders
$
(507,922
)
 
$
(332,780
)
 
$
(198,756
)
 
 
 
 
 
 
Net loss per share attributable to common stockholders - basic and diluted
$
(2.32
)
 
$
(1.83
)
 
$
(2.60
)
Weighted average number of common shares outstanding - basic and diluted
218,869

 
181,768

 
76,483

 


















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


55


CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in thousands)

 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
Net loss
 
$
(558,763
)
 
$
(345,641
)
 
$
(203,338
)
Other comprehensive income (loss)
 
 
 
 
 
 
Interest rate cash flow hedges
 
 
 
 
 
 
Loss on settlements retained in other comprehensive income
 
(30
)
 
(136
)
 

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

 
(27,104
)
 

Losses reclassified into earnings as a result of discontinuation of cash flow hedge accounting
 
5,973

 

 

Foreign currency translation
 
111

 
147

 
(85
)
Total other comprehensive income (loss)
 
27,351

 
(27,093
)
 
(85
)
Comprehensive loss
 
(531,412
)
 
(372,734
)
 
(203,423
)
Comprehensive loss attributable to non-controlling interest
 
48,809

 
12,861

 
4,582

Comprehensive loss attributable to common stockholders
 
$
(482,603
)
 
$
(359,873
)
 
$
(198,841
)







































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


56


CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(in thousands)
 
Total Stockholders' Equity (Deficit)
 
 
 
 
 
Common Stock
 
Treasury Stock
 
Additional Paid-in Capital
 
Accumulated Deficit
 
Accumulated Other Comprehensive Income (Loss)
 
Non- controlling Interest
 
Total Equity (Deficit)
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
 
 
Balance—December 31, 2010
67,761

 
$
204

 
1,463

 
$
(4,338
)
 
$
404,125

 
$
(1,061,449
)
 
$
(173
)
 
$
189,021

 
$
(472,610
)
Issuances of stock
55,845

 
168

 
 
 

 
468,230

 

 

 

 
468,398

Issuances of restricted stock
7,827

 
23

 

 

 
(23
)
 

 

 

 

Forfeitures of restricted stock
(39
)
 

 
39

 

 

 

 

 

 

Stock-based compensation

 

 

 

 
26,364

 

 

 

 
26,364

Shares repurchased related to tax withholdings for stock-based compensation
(1,884
)
 
(6
)
 
1,884

 
(15,857
)
 
6

 

 

 

 
(15,857
)
Comprehensive loss: Foreign currency translation

 

 

 

 

 

 
(85
)
 

 
(85
)
Loss attributable to non-controlling interest

 

 

 

 

 

 

 
(4,582
)
 
(4,582
)
Sale of common units to non-controlling interest

 

 

 

 

 

 

 
52,351

 
52,351

Distribution to non-controlling interest

 

 

 

 

 

 

 
(28,215
)
 
(28,215
)
Net loss

 

 

 

 

 
(198,756
)
 

 

 
(198,756
)
Balance—December 31, 2011
129,510

 
389

 
3,386

 
(20,195
)
 
898,702

 
(1,260,205
)
 
(258
)
 
208,575

 
(172,992
)
Issuances of stock
84,938

 
255

 

 

 
1,209,059

 

 

 

 
1,209,314

Issuances of restricted stock
10,293

 
31

 

 

 
(31
)
 

 

 

 

Forfeitures of restricted stock
(14
)
 

 
11

 

 

 

 

 

 

Stock-based compensation

 

 

 

 
61,047

 

 

 

 
61,047

Shares repurchased related to tax withholdings for stock-based compensation
(1,330
)
 
(4
)
 
1,330

 
(18,920
)
 
4

 

 

 

 
(18,920
)
Foreign currency translation

 

 

 

 

 

 
147

 
 
 
147

Interest rate cash flow hedges