CEI 2014 Form 10-K

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, 2014

¨ 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 1900
Houston, Texas	77002
(Address of principal executive offices)	(Zip code)

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

Securities registered pursuant to Section 12(b) of the Act:



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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $16.2 billion as of June 30, 2014.

236,710,964 shares of the registrant’s Common Stock, $0.003 par value, were issued and outstanding as of January 29, 2015.

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



PART I
Items 1. and 2. Business and Properties	1
Item 1A. Risk Factors	20
Item 1B. Unresolved Staff Comments	35
Item 3. Legal Proceedings	36
Item 4. Mine Safety Disclosure	37
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
Item 6. Selected Financial Data	40
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	59
Item 8. Financial Statements and Supplementary Data	61
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	104
Item 9A. Controls and Procedures	104
Item 9B. Other Information	104
PART III
PART IV
Item 15. Exhibits and Financial Statement Schedules	106
Signatures	124

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.

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 limited partnership that we created in 2007. We own 100% of the general partner interest in Cheniere Partners and 80.1% of Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) (NYSE MKT: CQH), which is a publicly traded limited liability company formed in 2013 that owns a 55.9% limited partner interest in Cheniere Partners.

The Sabine Pass LNG terminal is located on the Sabine Pass deepwater 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 nominal capacity of up to 266,000 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 a 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.

We are developing a second natural gas liquefaction and export facility and related pipeline near Corpus Christi, Texas (the “Corpus Christi Liquefaction Project”) through wholly owned subsidiaries Corpus Christi Liquefaction, LLC (“Corpus Christi Liquefaction”) and Cheniere Corpus Christi Pipeline, L.P. (“Cheniere Corpus Christi Pipeline”), respectively. As currently contemplated, the Corpus Christi LNG terminal would be designed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, three LNG storage tanks with capacity of approximately 10.1 Bcfe and two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters. The Corpus Christi Liquefaction Project also would include a 23-mile pipeline that would interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”).

One of our subsidiaries, Cheniere Marketing, LLC (“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 SPAs. Cheniere Marketing has entered into SPAs with Sabine Pass Liquefaction and Corpus Christi Liquefaction to purchase LNG produced by the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project.

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 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, CTPL, Corpus Christi Liquefaction and Cheniere Corpus Christi Pipeline as of January 31, 2015:

Our Business Strategy

Our primary business strategy is to develop energy and infrastructure assets with a focus on integrating the U.S. energy market, where supplies are abundant and inexpensive to produce, with international markets, where existing energy supplies are either uncompetitive or insufficient to satisfy growing demand. We plan to implement our strategy by:


•	completing construction and commencing operation of Sabine Pass Liquefaction’s Trains;


•	obtaining the requisite regulatory permits, long-term commercial contracts and financing to reach a final investment decision regarding the Corpus Christi Liquefaction Project;


•	safely, efficiently and reliably maintaining and operating our assets;


•	developing business relationships for the marketing of additional long-term and short-term agreements for Cheniere Marketing’s LNG volumes or additional LNG liquefaction projects or expansions;


•	expanding our existing asset base through acquisitions or development of complementary businesses or assets across the energy value chain; and


•	maintaining a flexible capital structure to finance the acquisition, development, construction and operation of the energy assets needed to supply 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, 2014, 2013 and 2012. 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 15—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 are currently focusing our development efforts on two 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; and the Corpus Christi LNG terminal near Corpus Christi, Texas. 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 80.1% of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners. We currently own a 100% interest in the Corpus Christi Liquefaction Project.

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. 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 and constructed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We have received authorization from the Federal Energy Regulatory Commission (the “FERC”) to site, construct and operate Trains 1 through 4. We commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. On September 30, 2013, we filed an application with the FERC for the approval to site, construct and operate Trains 5 and 6.

The U.S. Department of Energy (the “DOE”) has authorized the export of up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr) of domestically produced LNG by vessel from the Sabine Pass LNG terminal to countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas (“FTA countries”) for a 30-year term, beginning on the earlier of the date of first export or September 7, 2020; and to all countries without a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted (“non-FTA countries”) for a 20-year term, beginning on the earlier of the date of first export or August 7, 2017. The DOE further issued an order authorizing Sabine Pass Liquefaction to export up to the equivalent of approximately 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 25-year period. Additionally, the DOE further issued orders authorizing Sabine Pass Liquefaction to export an additional 503.3 Bcf/yr in total of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 20-year term. Sabine Pass Liquefaction’s applications for authorization to export that same 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to non-FTA countries are currently pending at the DOE.

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

Customers

Sabine Pass Liquefaction has entered into four fixed price, 20-year SPAs with third parties that in the aggregate equate to 16 mtpa (approximately 803 Bcf/yr) of LNG that commence with the date of first commercial delivery for Trains 1 through 4, which are fully permitted. In addition, 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. However, Sabine Pass Liquefaction has not yet received regulatory approval for construction of Train 5. 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, 2014, 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 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 plc (“Centrica”) has entered into an SPA that commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 91,250,000 MMBtu of LNG with a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of approximately $274 million. Centrica is organized under the laws of England and Wales.

In aggregate, the fixed fee portion to be paid by these customers is approximately $2.3 billion annually for Trains 1 through 4, and $2.9 billion annually if we make a positive final investment decision with respect to Train 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of Trains 1 through 5, respectively. The Total and Centrica SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision with respect to Train 5, which must be satisfied by June 30, 2015 or either party to the respective SPA may terminate its SPA.

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

Natural Gas Transportation and Supply

For Sabine Pass Liquefaction’s natural gas feedstock transportation requirements, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. Sabine Pass Liquefaction has also entered into enabling agreements and long-term natural gas purchase agreements with third parties in order to secure natural gas feedstock for the Sabine Pass Liquefaction Project. As of December 31, 2014, we have secured up to approximately 2,162,000,000 MMBtu of natural gas feedstock through long-term natural gas purchase agreements.

Construction

Trains 1 through 4 are being designed, constructed and commissioned by Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”).

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)”) 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, 2014. Total expected capital costs for Trains 1 through 4 are estimated to be between $9.0 billion and $10.0 billion before financing costs, and between $12.0 billion and $13.0 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

Final Investment Decision on Train 5 and Train 6

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

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 $105 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 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 Corpus Christi liquefaction facilities would be designed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, three LNG storage tanks with capacity of approximately 10.1 Bcfe and two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters (the “Corpus Christi Liquefaction Facilities”).

On December 30, 2014, the FERC issued an order granting Corpus Christi Liquefaction authorization under Section 3 of the Natural Gas Act of 1938, as amended (“NGA”), to site, construct and operate Trains 1 through 3. The Sierra Club has requested a rehearing, and the FERC has not ruled on this request. In August 2012, Cheniere Marketing filed an application with the DOE to export up to the equivalent of 15 mtpa (approximately 767 Bcf/yr) of domestically produced LNG to FTA and non-FTA countries from the Corpus Christi Liquefaction Project. In October 2012, the DOE granted Cheniere Marketing authority to export up to the equivalent of 15 mtpa (approximately 767 Bcf/yr) of domestically produced LNG to FTA countries from the Corpus Christi Liquefaction Project. Corpus Christi Liquefaction was added as an additional authorization holder to the FTA permit and an additional applicant to the non-FTA application.

Customers

Corpus Christi Liquefaction has entered into nine fixed price, 20-year SPAs with seven third parties with aggregate annual contract quantities of approximately 8.4 mtpa of LNG. However, the Corpus Christi Liquefaction Project is not yet fully permitted. Under these SPAs, the customers 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. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to cargoes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA commences upon the start of operations of the specified Train. As of December 31, 2014, Corpus Christi Liquefaction had the following third-party SPAs:

•

Endesa Generación, S.A. (which subsequently assigned its SPA to Endesa S.A.) and Endesa S.A. (together, “Endesa”) have each entered into SPAs that commence upon the date of first commercial delivery for Train 1 and include an aggregate annual contract quantity of 117,322,500 MMBtu of LNG, equating to expected annual contracted cash flow from fixed fees of approximately $411 million. Endesa is organized under the laws of Spain.

•

Iberdrola S.A. (“Iberdrola”) has entered into an SPA that commences upon the date of first commercial delivery for Train 2 and includes an annual contract quantity of 39,670,000 MMBtu of LNG, equating to expected annual contracted cash flow from fixed fees of approximately $139 million. In addition, Corpus Christi Liquefaction will provide Iberdrola with bridging volumes of 19,840,000 MMBtu per contract year, starting on the date on which Train 1 of the Corpus Christi Liquefaction Project becomes commercially operable and ending on the date of the first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project. Iberdrola is organized under the laws of Spain.


•	Gas Natural Fenosa LNG SL (“Gas Natural Fenosa LNG”) has entered into an SPA that commences upon the date of first commercial delivery for Train 2 and includes an annual contract quantity of 78,215,000 MMBtu of LNG, equating to expected annual contracted cash flow from fixed fees of approximately $274 million. Gas Natural Fenosa LNG is organized under the laws of Spain.


•	Woodside Energy Trading Singapore Pte Ltd (“Woodside”) has entered into an SPA that commences upon the date of first commercial delivery for Train 2 and includes an annual contract quantity of 44,120,000 MMBtu of LNG, equating to expected annual contracted cash flow from fixed fees of approximately $154 million. Woodside is organized under the laws of Singapore.

•

PT Pertamina (Persero) (“Pertamina”) has entered into two SPAs that commence upon the date of first commercial delivery for Trains 1 and 2, respectively, that include an annual contract quantity of 39,680,000 MMBtu of LNG from each Train, equating to expected aggregate annual contracted cash flow from fixed fees of approximately $278 million for each Train. Pertamina is organized under the laws of Indonesia.

•

Électricité de France, S.A. (“EDF”) has entered into an SPA that commences upon the date of first commercial delivery for Train 3 and includes an annual contract quantity of 40,000,000 MMBtu of LNG, equating to expected annual contracted cash flow from fixed fees of approximately $140 million. In addition, Corpus Christi Liquefaction will provide EDF with bridging volumes of 20,000,000 MMBtu per contract year, starting on the date on which Train 2 of the Corpus Christi Liquefaction Project becomes commercially operable and ending on the date of the first commercial delivery of LNG from Train 3 of the Corpus Christi Liquefaction Project. EDF is organized under the laws of France.


•	EDP Energias de Portugal S.A. (“EDP”) has entered into an SPA that commences upon the date of first commercial delivery for Train 3 and includes an annual contract quantity of 40,000,000 MMBtu of LNG, equating to expected annual contracted cash flow from fixed fees of approximately $140 million. EDP is organized under the laws of Portugal.

Each of the SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision, which must be satisfied by June 30, 2015 or either party to each SPA may terminate its SPA.

Expected annual contracted cash flow from fixed fees is approximately $1.5 billion if we make a positive final investment decision with respect to Trains 1 through 3, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $550 million, $706 million and $280 million for each of Trains 1 through 3, respectively.

Natural Gas Transportation and Supply

For Corpus Christi Liquefaction’s natural gas feedstock transportation requirements, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with third-party pipeline companies and Cheniere Corpus Christi Pipeline. Corpus Christi Liquefaction has also entered into enabling agreements with third parties and will continue to enter into such agreements in order to secure natural gas feedstock for the Corpus Christi Liquefaction Project.

Construction

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 $11.5 billion and $12.0 billion before financing costs, including an estimate for owner’s costs and contingencies.

Pipeline Facilities

On December 30, 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the NGA authorizing Cheniere Corpus Christi Pipeline to construct and operate the Corpus Christi Pipeline. The Corpus Christi 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.

Final Investment Decision

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 authorizations and obtaining adequate financing to construct the facility.

Sabine Pass Liquefaction Project and Corpus Christi Liquefaction Project Summaries

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




	Target Date
	Sabine Pass Liquefaction		Corpus Christi Liquefaction
Milestone	Trains 1 - 4	Trains 5 & 6	Trains 1 - 3
DOE export authorization	Received	Received FTA Pending Non-FTA	Received FTA; Pending Non-FTA
Definitive commercial agreements	Completed 16.0 mtpa	T5: Completed T6: 2015	T1-T2: Completed T3: 2015
- BG Gulf Coast LNG, LLC	5.5 mtpa
- Gas Natural Fenosa	3.5 mtpa
- KOGAS	3.5 mtpa
- GAIL (India) Ltd.	3.5 mtpa
- Total Gas & Power N.A.		2.0 mtpa
- Centrica plc		1.75 mtpa
- PT Pertamina (Persero)			1.52 mtpa
- Endesa, S.A.			2.25 mtpa
- Iberdrola, S.A.			0.76 mtpa
- Gas Natural Fenosa LNG SL			1.50 mtpa
- Woodside Energy Trading Singapore			0.85 mtpa
- Électricité de France, S.A.			0.77 mtpa
- EDP Energias de Portugal S.A.			0.77 mtpa
EPC contract	Completed	2015	Completed
Financing	Completed	2015	2015
- Equity commitments			Received
- Debt commitments			Received
FERC authorization	Completed
- FERC Order		2015	Received
- Certificate to commence construction		2015	2015
Issue Notice to Proceed	Completed	2015	2015
Commence operations	2015 - 2017	2018/2019	2018/2019

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 SPAs with third parties that will utilize substantially all of the liquefaction capacity available from these Trains. The Corpus Christi Liquefaction Project currently does not experience competition with respect to Trains 1 and 2. Corpus Christi Liquefaction has entered into eight fixed price, 20-year SPAs with seven third parties that will utilize a substantial majority 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 each other and other natural gas liquefaction projects throughout the world. Revenues associated with any incremental volumes, including those under the Cheniere Marketing SPAs 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 has committed to 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 requirement increases our cost of operations and construction, and failure to comply with such laws could result in substantial penalties.

Federal Energy Regulatory Commission

The design, construction and operation of our 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 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 Trains 1 through 4 of the Sabine Pass Liquefaction Project. 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. On February 20, 2014, the FERC issued an order granting the request. 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 LNG terminals, we will be subject to regular reporting requirements to the FERC and the U.S. Department of Transportation regarding the operation and maintenance of our 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. The FERC also approved CTPL’s 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. 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.

On December 30, 2014, the FERC issued an order granting Corpus Christi Liquefaction authorization under Section 3 of the NGA to site, construct and operate Trains 1 through 3 of the Corpus Christi Liquefaction Project. The Sierra Club has requested a rehearing, and the FERC has not ruled on this request. In addition, the FERC issued an order granting Cheniere Corpus Christi Pipeline a certificate of public convenience and necessity under Section 7(c) of the NGA to construct and operate the Corpus Christi Pipeline. Several other material governmental and regulatory approvals and permits will be required prior to construction

and operation of the Corpus Christi Liquefaction Project. In addition, the FERC approval requires us to obtain certain additional FERC approvals as construction progresses.

In addition to the siting and construction authority with respect to the LNG terminals 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, our pipelines are not permitted to unduly discriminate or grant undue preference as to 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.

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

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, as amended, 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 a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr) of domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries for a 30-year term, beginning on the earlier of the date of first export or September 7, 2020; and to non-FTA countries for a 20-year term, beginning on the earlier of the date of first export or August 7, 2017. The DOE further issued an order authorizing Sabine Pass Liquefaction to export up to the equivalent of approximately 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 25-year period.

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

domestically produced LNG, beginning on the earlier of the date of first export or January 22, 2022. Additional applications to the DOE for permits to allow the export of the additional 503.3 Bcf/yr of domestically produced LNG to non-FTA countries are pending.

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 FTA countries for a 25-year term, beginning on the earlier of the date of first export or October 16, 2022. On October 29, 2014, the DOE issued an order amending the authorization to include Corpus Christi Liquefaction as an additional authorization holder. An application to export LNG to non-FTA countries was filed on August 31, 2012 by Cheniere Marketing and is still pending DOE authorization. The DOE’s October 29, 2014 order also added Corpus Christi Liquefaction as an applicant to this pending application.

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

Pipelines

The Creole Trail Pipeline and the Corpus Christi Pipeline are also subject to regulation by the U.S. Department of Transportation (“DOT”), under the Pipeline and Hazardous Material Safety Administration (“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 PHMSA 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 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 PHMSA issued a final rule (known as “Control Room Management/Human Factors Rule”) requiring pipeline operators to write and institute certain control room procedures that address human factors and fatigue management. In August 2011, the PHMSA issued an advanced notice of proposed rulemaking addressing whether changes are needed to the regulations governing the safety of gas transmission pipelines. Specifically, PHMSA is considering whether integrity management requirements should be changed, including whether the definition of “high consequence area” should be revised and whether additional restrictions should be placed on the use of specific pipeline assessment methods. The PHMSA is also considering whether to revise requirements for non-integrity management issues, such as mainline valves, corrosion control issues and the safety of gathering lines. This advanced notice of proposed rulemaking is still pending at the PHMSA.

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 (increased from the prior $100,000), with a maximum of $2 million for any related series of violations (increased 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 (“USACE”), U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, Environmental Protection Agency (“EPA”) and U.S. Department of Homeland Security.

Three significant permits are the USACE Section 404 of the Clean Water Act/Section 10 of the Rivers and Harbors Act Permit (the “Section 10/404 Permit”), the Clean Air Act Title V (“Title V”) Operating Permit and the Prevention of Significant Deterioration (“PSD”) Permit, the latter two permits being issued by the LDEQ for the Sabine Pass LNG terminal and by the Texas Commission on Environmental Quality (“TCEQ”) 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. An application for a further revision to the Section 10/404 Permit, to address wetlands impacted by the construction of Trains 5 and 6, is currently pending before the USACE. We do not anticipate obtaining this permit until after FERC issues an order approving the expansion of the Liquefaction Project. In addition, a Section 10/404 permit application is pending with respect to the expansion of the Creole Trail Pipeline. Both of these permits, if issued, will require us to provide mitigation to compensate for the wetlands impacted by the respective projects. The application to amend the Sabine Pass LNG terminal’s existing Title V and PSD permits to authorize construction of 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 in the second quarter of 2015.

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 commenced in May 2013 and closed in June 2013. The permit was issued by the USACE on July 23, 2014 and subsequently modified on October 29, 2014. Corpus Christi Liquefaction applied for new PSD and Title V permits with the TCEQ in August 2012. On September 16, 2014, the TCEQ issued the PSD permit for criteria pollutants. On December 29, 2014, the TCEQ issued a preliminary decision approving Corpus Christi Liquefaction’s application for a Greenhouse Gas (“GHG”) PSD permit. Issuance of Corpus Christi Liquefaction’s Title V permit is pending issuance of the GHG PSD permit so any applicable requirements in the GHG PSD permit can be incorporated into the Title V permit.

CTPL was issued new Title V and PSD permits for the proposed modifications to the Creole Trail Pipeline system by the LDEQ in November 2013.

In August 2012, Cheniere Corpus Christi Pipeline applied to the TCEQ 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; and on November 18, 2014, the TCEQ approved an alteration

to the permit to reflect that the Sinton Compressor Station is now considered a minor source, and voided the PSD permit number. The Title V permit remains pending.

In August 2014, the Sabine Pass LNG terminal’s existing wastewater discharge permit was modified by LDEQ to authorize the discharge of wastewaters from the liquefaction facilities, including wastewaters generated with respect to the anticipated operations of Trains 5 and 6. Corpus Christi Liquefaction was issued a waste water discharge permit in January 2014 authorizing discharges from the liquefaction facilities. The permit was issued on January 28, 2014.

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 categories of “Swap Dealer” and “Major Swap Participant,” (2) require clearing and exchange-trading of certain swaps that the Commodity Futures Trading Commission (the “CFTC”) designated by rule to be cleared, (3) increase swap market transparency through robust reporting and recordkeeping requirements, (4) reduce financial risks in the derivatives market by imposing margin or collateral requirements on both cleared and, in certain cases, uncleared swaps, and (5) enhance the CFTC’s rulemaking and enforcement authority, including the authority to establish position limits on certain swaps and futures products. As required by the Dodd-Frank Act, the CFTC, the SEC and other regulators have been promulgating rules and regulations implementing the swaps regulatory provisions of the Dodd-Frank Act, although neither the CFTC nor the SEC has yet adopted all of the rules required by the Dodd-Frank Act. As a result of the Dodd-Frank Act’s provisions, the CFTC, in order to regulate excessive speculation in commodities, must adopt rules imposing new position limits on futures and options contracts and economically equivalent physical commodity swaps, on swaps traded on registered swap trading platforms and on over-the-counter swaps that perform a significant price discovery function with respect to certain markets.

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

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

rules may also adversely affect our existing derivative contracts and restrict our ability to monetize such contracts, cause us to restructure certain contracts, reduce the availability of derivatives to protect against risks or to optimize assets, adversely affect our ability to execute our hedging strategies and impact the liquidity of certain swaps products, all of which could increase our business costs.

Under the Commodity Exchange Act, the CFTC is directed generally to prevent manipulation and fraud in two markets: (a) physical commodities traded in interstate commerce, including physical energy and other commodities, as well as (b) financial instruments, such as futures, options and swaps. Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-manipulation, anti-fraud and anti-disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options and swaps markets. Should we violate these laws and regulations, we could be subject to a CFTC enforcement action and material penalties, possibly resulting in changes in the rates we can charge.

European Market Infrastructure Regulation (“EMIR”)

EMIR is a European Union (“EU”) regulation designed to increase the stability of the over-the-counter (“OTC”) derivative markets throughout the EU states that came into force on August 16, 2012. EMIR regulates OTC derivatives, central counterparties and trade repositories, and imposes requirements for certain market participants with respect to derivatives reporting, clearing and risk mitigation. In addition, certain OTC derivatives are subject to a central counterparty clearing obligation and collateral requirements. All non-cleared derivatives require risk management, including timely confirmations of transactions, portfolio reconciliation, portfolio compression (when there exists 500 or more OTC derivatives outstanding with a counterparty) and dispute resolution. Further, for non-cleared derivatives, outstanding contracts must be marked to market value daily or marked to model where conditions necessitate. Other EMIR risk management requirements for non-cleared derivatives are being considered, but those rules have yet to be finalized.

On February 12, 2014, EMIR reporting requirements took effect. Under EMIR, covered entities must report all derivatives concluded and any modification or termination to a registered or recognized trade repository within one business day of the transaction. Records related to derivatives must be retained for at least five years following termination.

Our subsidiaries and affiliates operating in the EU may, in the future, be subject to EMIR and its increased regulatory requirements for record keeping, marking to market, timely confirmation, derivative contract reporting, portfolio reconciliation and dispute resolution. Regulation under EMIR could significantly increase the cost of derivative contracts, materially alter the terms of derivatives contracts and reduce the availability of derivatives to protect against risks that we encounter.

Regulation on Wholesale Energy Market Integrity and Transparency (“REMIT”)

REMIT is an EU regulation that came into force on December 28, 2011. REMIT prohibits market manipulation and insider trading in wholesale energy markets, and imposes various obligations on participants in these markets. REMIT requires persons who professionally arrange wholesale energy transactions to notify the Office of Gas and Electricity Markets (“Ofgem”) (as national regulatory authority in the United Kingdom) of suspected breaches and implement procedures to identify breaches. All market participants, such as us, must disclose inside information and cannot use inside information to buy or sell wholesale energy products for their own account or on behalf of a third party, directly or indirectly, induce others to buy or sell wholesale information based on inside information, or disclose such inside information to any other person except in the normal course of employment. Market participants must also register with Ofgem and provide a record of wholesale energy market transactions to the European Agency for the Cooperation of Energy Regulators and information on capacity and utilization for production, storage, consumption or transmission. Should we violate these laws and regulations, we could be subject to investigation and penalties.

Environmental Regulation

Our LNG terminals are subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial civil and criminal fines and penalties for non-compliance.

Clean Air Act (“CAA”)

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 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 GHG emissions from stationary fuel combustion sources as well as all fugitive emissions throughout LNG terminals. From time to time, Congress has considered proposed legislation directed at reducing GHG emissions, and the EPA has defined GHG emissions thresholds for requiring certain permits for new and existing industrial sources. In addition, many states have already taken regulatory action to monitor and/or reduce emissions of GHGs, primarily through the development of GHG emission inventories or regional GHG cap and trade programs. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, financial position, results of operations and cash flows.

Coastal Zone Management Act (“CZMA”)

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 prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ, 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.

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, or one of its wholly owned subsidiaries, 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;


•	pursuant to the Cheniere Marketing SPA, the right to purchase, at Cheniere Marketing’s option, any LNG produced by Sabine Pass Liquefaction in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG;


•	pursuant to SPAs with Corpus Christi Liquefaction, the right to purchase, at Cheniere Marketing’s option, any LNG produced by Corpus Christi Liquefaction not required for other customers; and

•

three LNG vessel time charters with subsidiaries of two ship owners, Dynagas, Ltd. (“Dynagas”) and Teekay LNG Operating LLC (“Teekay”). 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 for a 2-year extension with similar terms as the initial term. Cheniere Marketing expects to receive delivery of the vessel from Dynagas in June 2015 and the vessels from Teekay 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.

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.

In 2002, the FERC concluded that it would apply light-handed regulation over the rates, terms and conditions agreed to by parties for LNG terminalling services, such that LNG terminal owners would not be required to provide open-access service at non-discriminatory rates or maintain a tariff or rate schedule on file with the FERC, similar to the requirements applied to our FERC-regulated natural gas pipelines. The EPAct codified the FERC’s policy, but those provisions expired on January 1, 2015. Nonetheless, we see no indication that the FERC intends to modify its longstanding policy of light-handed regulation of LNG terminals.

Market Factors

Our ability to enter into additional long-term sale and purchase agreements to underpin the development of additional Trains, sell any quantities of LNG available under the SPAs with Cheniere Marketing, or develop new projects is subject to market factors, including changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, economic growth in developing countries, investment in energy infrastructure, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and access to capital markets.

We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Global demand for natural gas is projected by the International Energy Agency to grow by approximately 29 Tcf between 2012 and 2025, with LNG increasing its current share of approximately ten percent of the global market. Wood Mackenzie forecasts that global demand for LNG will increase by 85%, from approximately 237 mtpa, or 11.5 Tcf, in 2012, to 438 mtpa, or 21.4 Tcf, in 2025 and that LNG production from existing facilities and new facilities already under construction will be able to supply the market with 337 mtpa in 2025, resulting in a market need for construction of an additional 101 mtpa of LNG production. We believe our new projects that do not already have capacity sold under long-term contracts are competitive and well-positioned to capture a portion of this incremental market need.

We have limited exposure, particularly in the LNG terminal business, to the recent decline in oil prices, even if it persists for more than 12 months, as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes. To date we have contracted approximately 19.75 mtpa of aggregate production capacity for Trains 1 through 5 of the Sabine Pass Liquefaction project with third party customers. Train 6 has not been contracted to date. We have contracted 8.4 mtpa for Trains 1 through 3 of the Corpus Christi Liquefaction project with third party customers. As of January 31, 2015, futures prices indicate that LNG exported from the U.S. continues to be competitive with LNG from alternative sources, supporting the need for additional long-term, medium-term and short-term contracting of LNG from our terminals.

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

We had 642 full-time employees at January 31, 2015.

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 1900, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is 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 1900, 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, 2014, we had $10.0 billion of total debt outstanding on a consolidated basis (before debt discounts and debt premiums). We incur, and will 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 additional project financing as well as the debt and equity capital markets. Furthermore, our financing 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 $547.9 million, $507.9 million and $332.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. In addition, our net cash flow used in operating activities was $124.1 million, $52.4 million and $107.8 million for the years ended December 31, 2014, 2013 and 2012, 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 any significant cash flows from the Sabine Pass Liquefaction Project until late 2015, at the earliest. Any delays beyond the expected development period for Train 1 of the Sabine Pass Liquefaction Project could cause, 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 any significant 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 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 the Corpus Christi Liquefaction Project, including potential issuances and sales of additional equity or equity-related securities by us, Cheniere Partners, or both. 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 stockholders may experience dilution upon the conversion of our convertible notes.

On November 26, 2014, we issued an aggregate principal amount of $1.0 billion of the 2021 Convertible Unsecured Notes to RRJ Capital II Ltd, Baytree Investments (Mauritius) Pte Ltd, and Seatown Lionfish Pte. Ltd. (the “2021 Convertible Unsecured Notes”). In January 2015, we entered into a note purchase agreement with EIG Management Company, LLC (“EIG”) to purchase $1.5 billion of convertible notes scheduled to fund once we reach a positive final investment decision on the Corpus Christi Liquefaction Project (the “EIG Convertible Notes” and together with the 2021 Convertible Unsecured Notes, collectively the “Convertible Notes”). We have the option to satisfy the Convertible Notes conversion obligations with cash, common stock or a combination thereof. The 2021 Convertible Unsecured Notes will be convertible beginning on November 28, 2015 at an initial conversion price of $93.64. The EIG Convertible Notes will be convertible (i) at our option, at any time on or after the substantial completion of Train 3 of the Corpus Christi Liquefaction Project at a conversion price equal to the lower of (x) a 10% discount to the average of the daily volume-weighted average price (“VWAP”) of our common stock, for the 90 trading-day period preceding the date on which notice of conversion is provided and (y) a 10% discount to the closing price of our common stock on the trading day prior to the date on which notice of conversion is provided or (ii) at the option of the holders of the EIG Convertible Notes, at any time on or after the six-month anniversary of the substantial completion of Train 3 of the Corpus Christi Liquefaction Project, at a conversion price equal to the average of the daily VWAP of our common stock for the 90 trading-day period preceding the date on which notice of conversion is provided. The conversion of some or all of the Convertible Notes into shares of our common stock will dilute the ownership percentages and voting power of our existing stockholders. Based on the initial conversion price, if we elect to satisfy the entire conversion obligation with common stock an aggregate of approximately 14.6 million shares of our common stock would be issued upon the conversion of all of the 2021 Convertible Notes, assuming the notes are converted at maturity and all interest on the notes is paid in kind. Because the conversion rate for the EIG Convertible Notes will depend on the price of our common stock at the time of conversion, we cannot meaningfully estimate the number of shares of our common stock, if any, that would be issued upon the conversion of such notes; however, under the note purchase agreement with EIG, a maximum of 47,108,466 shares of our common stock (subject to adjustment in the event of a stock split) may be issued in the aggregate upon the conversion of all of the EIG Convertible Notes. Any sales in the public market of the shares issuable upon conversion of the Convertible Notes could adversely affect the prevailing market prices of our common stock. In addition, the existence of the Convertible Notes may encourage short selling by market participants because the conversion of the Convertible Notes could be used to satisfy short positions, or the anticipated conversion of the Convertible Notes into shares of our common stock could depress the 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; upon satisfaction of the conditions precedent to payment thereunder, by six third-party customers that have entered into SPAs with Sabine Pass Liquefaction and agreed to pay an aggregate of $2.9 billion annually in fixed fees; and upon satisfaction of the conditions precedent to payment thereunder, by seven third-party customers that have entered into SPAs with Corpus Christi Liquefaction and agreed to pay an aggregate of $1.5 billion annually in fixed fees. We are dependent on each customer’s continued willingness and ability to perform its obligations under its SPA. We are also exposed to the credit risk of any guarantor of these customers’ obligations under their respective 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 and Centrica SPAs and the SPAs with Corpus Christi Liquefaction 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 subsidiaries’ indebtedness restrict payments that our subsidiaries can make to Cheniere Partners in certain events and limit 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. 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 and other regulations, including EMIR and REMIT, that may have an effect on our derivatives could have an adverse impact on our ability to hedge risks associated with our business and on our results of operations and cash flows.

The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder by the CFTC and SEC may adversely affect our ability to manage certain of our risks on a cost effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminals and to secure natural gas feedstock for our liquefaction facilities. As mandated by the Dodd-Frank Act, the CFTC has proposed rules setting limits on the positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, including Henry Hub natural gas, held by market participants, with exceptions for certain bona fide hedging transactions. If the position limits in the proposed rules or other similar position limits were imposed, our ability to execute our hedging strategies described above could be compromised.

Under the swaps regulatory provisions of the Dodd-Frank Act, and the rules adopted thereunder, we could have to clear on a designated clearing organization any swaps into which we enter that fall within a class of swaps designated by the CFTC for mandatory clearing and we could have to execute trades in such swaps on certain markets. The CFTC has designated six classes of interest rate swaps and credit default swaps for mandatory clearing, but has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for our swaps entered into to hedge our commercial risks, if we failed to qualify for that exception as to any swap we enter into and had to clear that swap over a designated clearing organization, we may have to post margin with respect to such swap, our cost of entering into and maintaining such swap could increase and the flexibility we enjoy with respect to entering into uncleared OTC swaps could be diminished. In addition, our counterparties that are subject to the regulations imposing the Basel III capital requirements on them may increase the cost to us of entering into swaps with them or require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as Swap Dealers, may change the cost and availability of the swaps that we use for hedging. Although we expect to qualify for the end-user exception to any margin regulations for uncleared swaps promulgated by the CFTC and federal banking regulators, if we did not qualify as a non-financial end user as to any of our swaps, our cost of entering into and maintaining swaps would be increased.

The Dodd-Frank Act’s swaps regulatory provisions, the related rules described above and the record keeping, reporting and business conduct rules imposed by the Dodd-Frank Act on other swaps market participants, as well as the regulations imposing the Basel III capital requirements on certain swaps market participants, could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and to execute our hedging strategies, and increase our exposure to less creditworthy counterparties. If, as a result of the swaps regulatory regime discussed above, we were to reduce our use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our results of operations and cash flows may become more volatile and could be otherwise adversely affected.

EMIR may result in increased costs for OTC derivative counterparties and also lead to an increase in the costs of, and demand for, the liquid collateral that EMIR requires central counterparties to accept. Although we expect to qualify as a non-financial counterparty under EMIR, our subsidiaries and affiliates operating in the EU may still be subject to increased regulatory requirements, including recordkeeping, marking to market, timely confirmations, derivatives reporting, portfolio reconciliation and dispute resolution procedures. Regulation under EMIR could significantly increase the cost of derivatives contracts, materially alter the terms of derivatives contracts and reduce the availability of derivatives to protect against risks that we encounter. These increased trading costs and collateral costs may have an adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our subsidiaries and affiliates operating in the EU may be subject to REMIT as wholesale energy market participants. This classification imposes increased regulatory obligations on our subsidiaries and affiliates, including a prohibition to use or disclose insider information or to engage in market manipulation in wholesale energy markets, and an obligation to report certain data. The increased regulatory obligations may increase the cost of compliance for our business and if we violate these laws and regulations, we could be subject to investigation and penalties.

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 Total and Centrica SPAs and the Corpus Christi Liquefaction SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision to construct the applicable Train. If these conditions are not met by June 30, 2015, each party may terminate its respective SPA.

It will take several years to construct our proposed liquefaction facilities, and we do not expect Train 1 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 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. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods, and rising sea levels; if any such effects were to occur, they could have an adverse effect on our coastal operations.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of 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. Approvals of the FERC and DOE 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 and export LNG. Although the FERC has issued an order under Section 3 of the NGA authorizing the siting, construction and operation of four Trains at the Sabine Pass Liquefaction Project and an order authorizing the siting, construction and operation of three trains at the Corpus Christi Liquefaction Project, pending a rehearing request from the Sierra Club, the FERC orders require us to obtain certain additional approvals in conjunction with ongoing construction and operations of our proposed liquefaction facilities. In addition, our application to the FERC under Section 3 of the NGA for authorization to site, construct and operate two additional Trains at the Sabine Pass Liquefaction Project is currently pending. The environmental assessment by the FERC was issued in December 2014 and the public comment period has closed with comments from the Sierra Club (as an intervenor) and the EPA (as a cooperating agency). We also have pending applications with the DOE for authorization to export LNG to FTA and non-FTA countries in addition to the orders previously granted to us by the DOE. Authorizations obtained from other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We cannot control the outcome of the review and approval process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any existing or potential interventions or other actions by third parties will interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in 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 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.

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 USACE 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 SPAs with Sabine Pass Liquefaction and Corpus Christi Liquefaction pursuant to which Cheniere Marketing has the option to purchase LNG at the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project, respectively. 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 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 all of our proposed LNG facilities or Trains or 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 or Trains, 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 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.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG, and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:


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


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


•	insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;


•	insufficient LNG tanker capacity;


•	weather conditions;


•	reduced demand and lower prices for natural gas;


•	increased natural gas production deliverable by pipelines, which could suppress demand for LNG;


•	decreased oil and natural gas exploration activities, which may decrease the production of natural gas;


•	cost improvements that allow competitors to 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;


•	political conditions in natural gas producing regions;


•	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.

Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and natural gas, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Failure of 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;


•	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 have contracted for firm capacity for our natural gas feedstock transportation requirements for the Sabine Pass Liquefaction Project and partially for the Corpus Christi Liquefaction Project. We cannot control the regulatory and permitting approvals or third parties’ construction times, which could impair our ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We face competition based upon the international market price for LNG.

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;


•	decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;


•	increases in capacity and utilization of nuclear power and related facilities; and


•	displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.

Terrorist attacks, including cyberterrorism, or military campaigns may adversely impact our business.

A terrorist, including cyberterrorist, or military incident involving an LNG facility, our infrastructure or an LNG vessel may result in delays in, or cancellation of, construction of new LNG facilities, including one or more of the Trains, which would increase our costs and decrease our cash flows. A terrorist incident may also result in temporary or permanent closure of existing LNG facilities, including the Sabine Pass LNG terminal 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, including cyberterrorism, or war could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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 terminals and construction of liquefaction facilities 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 and natural resources; the handling, storage and disposal of hazardous materials, hazardous waste, and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. Violation of these laws and regulations could lead to substantial liabilities, fines and penalties or to capital expenditures related to pollution control equipment that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.

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

Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from the Sabine Pass LNG terminal through the Sabine Pass deepwater shipping channel less than four miles from the Gulf Coast and LNG exported from the Corpus Christi LNG terminal near Corpus Christi, Texas on over 1,000 acres of land that we own or control, 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.

A major health and safety incident relating to our business could be costly in terms of potential liabilities and reputational damage.

Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, penalties for non-compliance with relevant regulatory requirements or litigation, and a failure that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities, which in turn could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We 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 flow, liquidity and prospects.

Substantially all of our anticipated revenue in 2015 will be dependent upon one facility, the Sabine Pass LNG regasification facilities 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 the proposed Corpus Christi LNG terminal including the related pipelines, or in the LNG industry, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

We may incur impairments to goodwill or long-lived assets.

We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. We test goodwill for impairment annually during the fourth quarter, or more frequently as circumstances dictate. 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. 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 or long-lived assets, we may be required to record a charge to earnings in our Consolidated Financial Statements during a period in which such impairment is determined to exist, which may negatively impact our results of operations.

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 of 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 was requested in connection with such 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.

We are subject to litigation which may impact the amount of operating costs and expenses that we have recognized in our financial statements.

During the second quarter of 2014, four lawsuits were filed in the Court of Chancery of the State of Delaware (the “Court”) against us and/or certain of our present and former officers and directors that challenge the manner in which abstentions were treated in connection with the stockholder vote on Amendment No. 1 to the Cheniere Energy, Inc. 2011 Incentive Plan (“Amendment No. 1”), pursuant to which, among other things, the number of shares of common stock available for issuance under the Cheniere Energy, Inc. 2011 Incentive Plan (the “2011 Plan”) was increased from 10 million to 35 million shares. The lawsuits contend that abstentions should have been counted as “no” votes in tabulating the outcome of the vote and that the stockholders did not approve Amendment No. 1 when abstentions are counted as such. The lawsuits further contend that portions of the Amended and Restated Bylaws of Cheniere Energy, Inc. adopted on April 3, 2014 are invalid and that certain disclosures relating to these matters made by us are misleading. The lawsuits assert claims for breach of contract and breach of fiduciary duty (both on a class and a derivative basis) and claims for unjust enrichment (on a derivative basis). The lawsuits seek, among other things, a declaration that the February 1, 2013 stockholder vote on Amendment No. 1 is void, disgorgement of all compensation distributed as a result of Amendment No. 1, voiding the awards made from the shares reserved pursuant to Amendment No. 1 and monetary damages. On June 16, 2014, we filed a verified application with the Court pursuant to 8 Del. C. § 205 (the “Section 205 Action”) in which we ask the Court to declare valid the issuance, pursuant to the 2011 Plan, of the 25 million additional shares of our common stock covered by Amendment No. 1, whether occurring in the past or the future.

We have also agreed that plaintiffs’ counsel is entitled to a fee in connection with the resolution of the stockholder lawsuits, which will be paid by us, our successors in interest and/or our insurers. On February 10, 2015, plaintiffs filed an application with the Court, accompanied by a memorandum of law and expert reports, requesting an award of fees and expenses in the amount of approximately $43 million. If no agreement is reached between us and plaintiffs, we are entitled to contest the amount of fees sought by plaintiffs. The amount of the fee has not yet been determined. We have notified our insurance carriers of the claim. No assurance can be made as to whether any amounts ultimately will be recovered from the insurance carriers.

We have accrued our best estimate of probable loss in accrued liabilities on our Consolidated Balance Sheets. We estimate that the ultimate resolution of the matter could result in a total loss of up to approximately $43 million. As the approval process for the Stipulation and plaintiffs' fee award progresses, additional information could become known and we may be required to recognize additional operating costs and expenses, and that amount could be material to our consolidated financial position, results of operations or cash flows, and could cause our investors to lose confidence in our reported financial information and have a negative effect on the price of our common stock.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.


ITEM 3.	LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.

On May 29, 2014, an alleged stockholder of Cheniere commenced a putative class and derivative action in the Court of Chancery of the State of Delaware (the “Court”) against Cheniere, certain members of the Board and certain of Cheniere’s present and former officers captioned Jones v. Souki, et al., C.A. No. 9710-VCL. Since May 29, 2014, additional litigations have been filed captioned Macguire v. Souki, et al., C.A. No. 9746-VCL, Shenker v. Souki, et al., C.A. No. 9763-VCL and Davidoff v. Souki, et al., C.A. No. 9825-VCL. These lawsuits have been consolidated into In re Cheniere Energy, Inc. Stockholders Litigation, Consolidated C.A. No. 9710-VCL (Del. Ch.) (the “Stockholder Action”). In general terms, these litigations challenge the manner in which abstentions were treated in connection with the stockholder vote on Amendment No. 1 to the Cheniere Energy, Inc. 2011 Incentive Plan (“Amendment No. 1”), pursuant to which, among other things, the number of shares of common stock available for issuance under the Cheniere Energy, Inc. 2011 Incentive Plan (the “2011 Plan”) was increased from 10 million to 35 million shares. The lawsuits contend that abstentions should have been counted as “no” votes in tabulating the outcome of the vote and that the stockholders did not approve Amendment No. 1 when abstentions are counted as such. The lawsuits further contend that portions of the Amended and Restated Bylaws of Cheniere Energy, Inc. adopted on April 3, 2014 are invalid and that certain disclosures relating to these matters made by Cheniere are misleading. The lawsuits assert claims for breach of contract and breach of fiduciary duty (both on a class and a derivative basis) and claims for unjust enrichment (on a derivative basis). The lawsuits seek, among other things, a declaration that the February 1, 2013 stockholder vote on Amendment No. 1 is void, disgorgement of all compensation distributed as a result of Amendment No. 1, voiding the awards made from the shares reserved pursuant to Amendment No. 1 and monetary damages.

On June 16, 2014, the defendants filed with the Court a joint motion to stay or dismiss the consolidated action with prejudice and Cheniere filed a verified application pursuant to 8 Del. C. § 205 (the “Section 205 Action”) in which Cheniere asks the Court to declare valid the issuance, pursuant to the 2011 Plan, whether occurring in the past or future, of the 25 million additional shares of common stock of Cheniere covered by Amendment No. 1. On June 27, 2014, the Court entered an order staying the stockholder litigation pending resolution of the Section 205 Action. On July 11, 2014, Cheniere filed a memorandum of law in support of its motion for judgment on Application I asserted in the Section 205 Action (that it correctly tabulated votes in connection with the stockholder vote on Amendment No. 1). On July 25, 2014, certain of the plaintiffs in the lawsuits (who have been given permission to intervene in the Section 205 Action) filed a brief in opposition to Cheniere’s motion for judgment on Application I in the Section 205 Action. Briefing on these issues was completed on August 20, 2014, and the Court held a hearing on the motion on August 26, 2014.

The parties to the above-referenced lawsuits and the Section 205 Action have entered into a Stipulation and Agreement of Compromise, Settlement and Release dated December 12, 2014 (the “Stipulation”), subject to its terms and conditions, including receipt, among other things, of Court approval, to resolve the litigation. If approved, the Stipulation will result in the dismissal with prejudice of the Stockholder Action and the Section 205 Action and a release being granted to the defendants by the plaintiffs and a class of Cheniere’s stockholders. As part of the settlement: (i) the parties will request that the Court validate, pursuant to 8 Del. C. § 205, all awards made pursuant to the 2011 Plan (whether vested or unvested) and declare that recipients of such awards are entitled to keep their awarded shares, subject to the terms and conditions of the award agreements, including any outstanding requirements for vesting; (ii) except with respect to the unawarded shares discussed below, Cheniere will not seek stockholder approval for any share-based compensation prior to January 1, 2017, such that no share-based compensation will be awarded to company executives, directors or consultants other than to the extent stockholders have already approved such compensation or such compensation was approved pursuant to 8 Del. C. § 205 (notwithstanding the foregoing, authorized stock (unissued or treasury) may be used to compensate new employees and a cash pay award (bonus, incentive, etc.) tied to the performance of Cheniere’s stock shall not constitute share-based compensation); (iii) all compensation-related votes through September 17, 2022 will be subject to a majority of the shares present and entitled to vote standard (pursuant to which abstentions will be counted as the functional equivalent of “no” votes and broker non-votes will not be considered in determining the outcome of the resolution, but will be counted for purposes of establishing a quorum); and (iv) the Compensation Committee will be comprised exclusively of independent directors as defined by the NYSE MKT (or the rules of the primary exchange on which Cheniere’s common stock is listed in the future). With respect to the shares authorized pursuant to Amendment No. 1, but not awarded: (i) Cheniere will not award any of these shares unless the issuance of the shares is approved by a new stockholder vote; (ii) no earlier than 90-days after Court approval of the settlement, Cheniere may submit the issue of the unawarded shares to a stockholder vote; and (iii) if stockholders approve issuance of the unawarded shares, no more than 1 million of those shares may be awarded to Mr. Souki.

Consummation of the settlement is subject to Court approval of all aspects of the settlement. Cheniere has also agreed that plaintiffs’ counsel is entitled to a fee in connection with the resolution of the stockholder lawsuits, which will be paid by Cheniere, its successors in interest and/or its insurers. On February 10, 2015, plaintiffs filed an application with the Court, accompanied by a memorandum of law and expert reports, requesting an award of fees and expenses in the amount of approximately $43 million. If no agreement is reached between Cheniere and plaintiffs, Cheniere is entitled to contest the amount of fees sought by plaintiffs. The amount of the fee has not yet been determined. Cheniere has notified its insurance carriers of the claim. No assurance can be made as to whether any amounts ultimately will be recovered from the insurance carriers.


ITEM 4.	MINE SAFETY DISCLOSURE

None.

PART II


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

Market Information, Holders and Dividends

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 sales prices of our common stock, as reported by the NYSE MKT, for each quarter during 2013 and 2014.



	High		Low
Three Months Ended
March 31, 2013	$	28.73	$	18.97
June 30, 2013	31.52		24.27
September 30, 2013	34.55		26.72
December 31, 2013	46.39		33.23
Three Months Ended
March 31, 2014	$	56.30	$	40.43
June 30, 2014	72.76		50.91
September 30, 2014	85.00		67.12
December 31, 2014	79.80		58.10

As of January 29, 2015, we had 236.7 million shares of common stock outstanding held by approximately 692 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.

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended December 31, 2014:



Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share (2)	Total Number of Shares Purchased as a Part of Publicly Announced Plans	Maximum Number of Units That May Yet Be Purchased Under the Plans
October 1 - 31, 2014	867,330	$78.05	—	—
November 1 - 30, 2014	—	—	—	—
December 1 - 31, 2014	1,368	$66.70	—	—


(1)	Represents shares surrendered to us by participants in our share-based compensation plans to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under these plans.


(2)	The price paid per share was based on the closing trading price of our common stock on the dates on which we repurchased shares from the participants under our share-based compensation plans.

For additional information, see Note 11—Share-Based Compensation in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

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, 2014. 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, 2009 and that any dividends were fully reinvested.



Company / Index	2009	2010	2011	2012	2013	2014
Cheniere Energy, Inc.	100	228	359	776	1,782	2,909
Russell 2000 Index	100	127	122	141	196	206
S&P Oil & Gas Exploration & Production Index	100	109	102	106	135	121

Sale of Unregistered Securities

On November 26, 2014, we issued the 2021 Convertible Unsecured Notes. The 2021 Convertible Unsecured Notes were issued on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act and Regulation S promulgated thereunder. Beginning one year after the closing date of the offering, provided that the closing price of our common stock is greater than or equal to the conversion price on the date of conversion, the 2021 Convertible Unsecured Notes will be convertible at the option of the holder into our common stock at an initial conversion price of $93.64. The conversion rate is subject to adjustment upon the occurrence of certain specified events.


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 Operations and our Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report.



	Year Ended December 31,
	2014			2013			2012			2011			2010
	(in thousands, except per share data)
Revenues	$	267,954		$	267,213		$	266,220		$	290,444		$	291,513
General and administrative expense (1)	323,709			384,512			152,081			88,427			68,626
Income (loss) from operations	(273,568		)	(328,986		)	(75,832		)	58,146			104,623
Interest expense, net	(181,236		)	(178,400		)	(200,811		)	(259,393		)	(262,046		)
Net loss attributable to common stockholders	(547,932		)	(507,922		)	(332,780		)	(198,756		)	(76,203		)
Net loss per share attributable to common stockholders - basic and diluted	$	(2.44	)	$	(2.32	)	$	(1.83	)	$	(2.60	)	$	(1.37	)
Weighted average number of common shares outstanding—basic and diluted	224,338			218,869			181,768			76,483			55,765



	December 31,
	2014		2013		2012		2011			2010
	(in thousands)
Cash and cash equivalents	$	1,747,583	$	960,842	$	201,711	$	459,160		$	74,161
Restricted cash and cash equivalents (current)	481,737		598,064		520,263		102,165			73,062
Non-current restricted cash and cash equivalents	550,811		1,031,399		272,924		82,892			82,892
Property, plant and equipment, net	9,246,753		6,454,399		3,282,305		2,107,129			2,157,597
Total assets	12,573,683		9,673,237		4,639,085		2,915,325			2,553,507
Current debt, net of discount	—		—		—		492,724			—
Long-term debt, net of discount	9,806,084		6,576,273		2,167,113		2,465,113			2,918,579
Long-term debt-related parties, net of discount	—		—		—		9,598			8,930
Total equity (deficit)	2,501,517		2,840,057		2,261,605		(172,992		)	(472,610		)


(1)	General and administrative expense includes $96.7 million, $252.1 million, $53.2 million, $24.4 million and $16.1 million share-based compensation expense recognized in the years ended December 31, 2014, 2013, 2012, 2011 and 2010, respectively.


ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our 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

The Sabine Pass LNG terminal is located on the Sabine Pass deepwater 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 nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Cheniere Partners is developing and constructing natural gas liquefaction facilities 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 a 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.

We are developing a second natural gas liquefaction and export facility and pipeline facility near Corpus Christi, Texas (the “Corpus Christi Liquefaction Project”) through wholly owned subsidiaries Corpus Christi Liquefaction, LLC (“Corpus Christi Liquefaction”) and Cheniere Corpus Christi Pipeline, L.P. (“Cheniere Corpus Christi Pipeline”), respectively. As currently contemplated, the Corpus Christi LNG terminal would be designed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, three LNG storage tanks with capacity of approximately 10.1 Bcfe and two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters. The Corpus Christi Liquefaction Project also would include a 23-mile pipeline that would interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”).

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, 2014 and through the filing date of this Form 10-K include the following:

Cheniere

•

Corpus Christi Liquefaction and Cheniere Corpus Christi Pipeline received authorization from the Federal Energy Regulatory Commission (the “FERC”) to site, construct and operate the Corpus Christi Liquefaction Facilities for the liquefaction and export of domestically produced natural gas at the Corpus Christi LNG terminal and for the transportation of natural gas bi-directionally between the Corpus Christi LNG terminal and existing interstate and intrastate natural gas pipeline systems, respectively. The FERC order authorizes the development of up to three modular Trains and a 23-mile pipeline.


•	Corpus Christi Liquefaction entered into the following:


◦	an SPA with each of Endesa Generación, S.A. (which was subsequently assigned to Endesa S.A.) and Endesa S.A. (together, “Endesa”) under which Endesa has agreed to purchase a total of 117.3 million MMBtu of LNG per year (approximately 2.25 mtpa) upon the date of first commercial delivery of LNG from the Corpus Christi Liquefaction Project.

◦

an SPA with Iberdrola S.A. (“Iberdrola”) under which Iberdrola has agreed to purchase a total of 39.7 million MMBtu of LNG per year (approximately 0.76 mtpa) upon the date of first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project. In addition, Corpus Christi Liquefaction will provide Iberdrola with bridging volumes of 19.8 million MMBtu per contract year, starting on the date on which Train 1 of the Corpus Christi Liquefaction Project becomes commercially operable and ending on the date of the first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project.


◦	an SPA with Gas Natural Fenosa LNG SL (“Gas Natural Fenosa LNG”) under which Gas Natural Fenosa LNG has agreed to purchase a total of 78.2 million MMBtu of LNG per year (approximately 1.5 mtpa) upon the date of first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project.


◦	an SPA with Woodside Energy Trading Singapore Pte Ltd (“Woodside”) under which Woodside has agreed to purchase a total of 44.1 million MMBtu of LNG per year (approximately 0.85 mtpa) upon the date of first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project.


◦	a second SPA with PT Pertamina (Persero) (“Pertamina”) under which Pertamina has agreed to purchase an additional 39.7 million MMBtu of LNG per year (approximately 0.76 mtpa) upon the date of first commercial delivery of LNG from Train 2 of the Corpus Christi Liquefaction Project.

◦

an SPA with Électricité de France, S.A. (“EDF”) under which EDF has agreed to purchase 40.0 million MMBtu of LNG per year (approximately 0.77 mtpa) upon the date of first commercial delivery of LNG from Train 3 of the Corpus Christi Liquefaction Project. In addition, Corpus Christi Liquefaction will provide EDF with bridging volumes of 20.0 million MMBtu per contract year, starting on the date on which Train 2 of the Corpus Christi Liquefaction Project becomes commercially operable and ending on the date of the first commercial delivery of LNG from Train 3 of the Corpus Christi Liquefaction Project.


◦	an SPA with EDP Energias de Portugal S.A. (“EDP”) under which EDP has agreed to purchase a total of 40.0 million MMBtu of LNG per year (approximately 0.77 mtpa) upon the date of first commercial delivery of LNG from Train 3 of the Corpus Christi Liquefaction Project.

•

We issued an aggregate principal amount of $1.0 billion Convertible Unsecured Notes due 2021 (the “2021 Convertible Unsecured Notes”) to RRJ Capital II Ltd, Baytree Investments (Mauritius) Pte Ltd, and Seatown Lionfish Pte. Ltd., on a private placement basis. The 2021 Convertible Unsecured Notes accrue interest at a rate of 4.875% per annum, which is payable in kind (“PIK”) semi-annually in arrears by increasing the principal amount of the 2021 Convertible Unsecured Notes outstanding. The proceeds will be used for general corporate purposes and to fund a portion of the costs of developing, constructing and operating the Corpus Christi Liquefaction Project.


•	We entered into the following:

◦

a note purchase agreement with EIG Management Company, LLC (“EIG”) to purchase $1.5 billion of convertible notes that would be issued by Cheniere CCH HoldCo II, LLC, a wholly owned direct subsidiary of Cheniere, which is scheduled to fund once we reach a positive final investment decision on the Corpus Christi Liquefaction Project. The net proceeds would be used to fund a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project.


◦	an agreement with 19 financial institutions to act as Joint Lead Arrangers to assist in the structuring and arranging of up to $11.5 billion of debt facilities. The proceeds will be used to pay for a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project.


•	Our wholly owned subsidiary, Cheniere Marketing, entered into an amended and restated SPA with Sabine Pass Liquefaction to purchase, at Cheniere Marketing’s option, any LNG produced by Sabine Pass Liquefaction in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

Cheniere Partners


•	Sabine Pass Liquefaction entered into a $325.0 million senior letter of credit and reimbursement agreement (the “Sabine Pass Liquefaction LC Agreement”) that it is using for the issuance of letters of credit on behalf of Sabine Pass Liquefaction for certain working capital requirements related to the Sabine Pass Liquefaction Project.

•

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

Cheniere Holdings


•	Cheniere Holdings completed a public offering of 10,100,000 common shares for net proceeds of approximately $229 million, after deducting offering expenses. The net proceeds were used to redeem from us the same number of common shares, which reduced our ownership of Cheniere Holdings’ common shares from 84.5% to 80.1%.

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 business. In addition, we expect to finance the construction costs of the Corpus Christi Liquefaction Project and other corporate activities from one or more of the following: project financing, debt and equity offerings by us or our subsidiaries, available cash and operating cash flow.

In November 2014, we issued the 2021 Convertible Unsecured Notes. Beginning one year after the closing date, the 2021 Convertible Unsecured Notes will be convertible at the option of the holder into our common stock at an initial conversion price of $93.64, provided that our closing price of common stock is greater than or equal to $93.64 on the conversion date. The conversion rate is subject to adjustment upon the occurrence of certain specified events. We have the option to satisfy the conversion obligation with cash, common stock or a combination thereof.

As of December 31, 2014, we had cash and cash equivalents of $1,747.6 million available to Cheniere. In addition, we had current and non-current restricted cash and cash equivalents of $1,032.5 million (which included current and non-current restricted cash and cash equivalents available to Cheniere Holdings, Cheniere Partners, Sabine Pass Liquefaction and Sabine Pass LNG) designated for the following purposes: $612.9 million for the Sabine Pass Liquefaction Project; $36.2 million for CTPL; $91.1 million for interest payments related to the Sabine Pass LNG Senior Notes described below; and $292.3 million for other restricted purposes.

Substantially all of our revenues from external customers and long-lived assets are attributed to or located in the United States.

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, 2014, we had an 80.1% direct ownership interest in Cheniere Holdings. We receive dividends on our Cheniere Holdings shares from the distributions that Cheniere Holdings receives from Cheniere Partners, and we receive management fees for managing Cheniere Holdings. For the year ended December 31, 2014, we received $14.3 million in dividends on our Cheniere Holdings common shares and $1.1 million of management fees from Cheniere Holdings.

Cheniere Partners

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of December 31, 2014, we own 80.1% of Cheniere Holdings, which owns a 55.9% 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 own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners.

Prior to the initial public offering by Cheniere Holdings (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, Sabine Pass LNG, Sabine Pass Liquefaction and CTPL. During the year ended December 31, 2014, we received $2.0 million in distributions on our general partner interest and $110.5 million in total service fees 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 the Sabine Pass Liquefaction Project, Sabine Pass LNG’s excess capacity 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 of Cheniere Partners, a merger, consolidation or other combination of Cheniere Partners with another person or the sale of all or substantially all of the assets of Cheniere Partners. 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 ratio of the Class B units owned by Cheniere Holdings and Blackstone CQP Holdco LP (“Blackstone”) was 1.41 and 1.39, respectively, as of December 31, 2014. We expect the Class B units to mandatorily convert into common units within 90 days of the substantial completion date of Train 3 of the Sabine Pass Liquefaction Project, which Cheniere Partners currently expects 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

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 and constructed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 4. We commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. On September 30, 2013, we filed an application with the FERC for the approval to site, construct and operate Trains 5 and 6.

Customers

may terminate its SPA. 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 a specified Train.

In addition, Cheniere Marketing has entered into an amended and restated SPA with Sabine Pass Liquefaction to purchase, at Cheniere Marketing’s option, any LNG produced by Sabine Pass Liquefaction in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

Natural Gas Transportation and Supply

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 Train 3 and Train 4 (the “EPC Contract (Trains 3 and 4)”) under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause 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, 2014. Total expected capital costs for Trains 1 through 4 are estimated to be between $9.0 billion and $10.0 billion before financing costs and between $12.0 billion and $13.0 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

Pipeline Facilities

Final Investment Decision on Train 5 and Train 6

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 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 its currently anticipated capital, operating and debt service requirements. We currently project that Sabine Pass Liquefaction will generate cash flow from the Sabine Pass Liquefaction Project by late 2015, when Train 1 of the Sabine Pass Liquefaction Project is anticipated to achieve initial LNG production.

Senior Secured Notes

As of December 31, 2014, Cheniere Partners’ subsidiaries had six series of senior secured notes outstanding (collectively, the “Senior Notes”):


•	$1.7 billion of 7.50% Senior Secured Notes due 2016 issued by Sabine Pass LNG (the “2016 Sabine Pass LNG Senior Notes”);


•	$0.4 billion of 6.50% Senior Secured Notes due 2020 issued by Sabine Pass LNG (the “2020 Sabine Pass LNG Senior Notes” and collectively with the 2016 Sabine Pass LNG Senior Notes, the “Sabine Pass LNG Senior Notes”);


•	$2.0 billion of 5.625% Senior Secured Notes due 2021 issued by Sabine Pass Liquefaction (the “2021 Sabine Pass Liquefaction Senior Notes”);


•	$1.0 billion of 6.25% Senior Secured Notes due 2022 issued by Sabine Pass Liquefaction (the “2022 Sabine Pass Liquefaction Senior Notes” and collectively with the 2021 Sabine Pass Liquefaction Senior Notes, the 2023 Sabine Pass Liquefaction Senior Notes and the 2024 Sabine Pass Liquefaction Senior Notes, the “Sabine Pass Liquefaction Senior Notes”);


•	$1.5 billion of 2023 Sabine Pass Liquefaction Senior Notes; and


•	$2.0 billion of 2024 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. 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 all or part of its 2016 Sabine Pass LNG Senior Notes at any 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 Sabine Pass LNG Senior Notes; or

•

the excess of: a) the present value at such redemption date of (i) the redemption price of the 2016 Sabine Pass LNG Senior Notes plus (ii) all required interest payments due on the 2016 Sabine Pass LNG Senior 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 Sabine Pass LNG Senior Notes, if greater.

Sabine Pass LNG may redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time on or after November 1, 2016 at fixed redemption prices specified in the indenture governing the 2020 Sabine Pass LNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also, at its option, redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time prior to November 1, 2016, at a “make-whole” price set forth in the indenture governing the 2020 Sabine Pass LNG Senior Notes, 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 Sabine Pass LNG Senior Notes at a redemption price of 106.5% of the principal amount of the 2020 Sabine Pass LNG Senior 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 Sabine Pass LNG Senior Notes within 180 days of the closing date for such equity offering and at least 65% of the aggregate principal amount of the 2020 Sabine Pass LNG Senior 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; December 15, 2021, with respect to the 2022 Sabine Pass Liquefaction Senior Notes; January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes; or February 15, 2024, with respect to the 2024 Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction may redeem all or part of such series 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 may also at any time on or after November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes; December 15, 2021, with respect to the 2022 Sabine Pass Liquefaction Senior Notes; January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes; or February 15, 2024, with respect to the 2024 Sabine Pass Liquefaction Senior Notes, redeem all or part of such series of the Sabine Pass Liquefaction Senior Notes at a redemption price equal to 100% of the principal amount of such series 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 common indenture 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 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, the 2013 Liquefaction Credit Facilities and the Sabine Pass Liquefaction LC Agreement described below.

2013 Liquefaction Credit Facilities

In May 2013, Sabine Pass Liquefaction entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 Liquefaction Credit Facilities”). In conjunction with Sabine Pass Liquefaction’s issuance in May 2014 of the 2024 Sabine Pass Liquefaction Senior Notes and the additional issuance of the 2023 Sabine Pass Liquefaction Senior Notes (the “Additional 2023 Sabine Pass Liquefaction Senior Notes”), in an aggregate principal amount of $2.5 billion before premium, Sabine Pass Liquefaction terminated approximately $2.1 billion of commitments under the 2013 Liquefaction Credit Facilities. As a result, as of December 31, 2014, Sabine Pass Liquefaction has available commitments aggregating $2.7 billion under the 2013 Liquefaction Credit Facilities, which will be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the 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, or 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”) or the base rate plus the applicable margin. The applicable margins for LIBOR loans range from 2.3% to 3.0% prior to the completion of Train 4 and from 2.3% to 3.25% after such completion, depending on the applicable 2013 Liquefaction Credit Facility. The 2013 Liquefaction Credit Facilities also require 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. Under the terms of the 2013 Liquefaction Credit Facilities, Sabine Pass Liquefaction is required to hedge not less than 75% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal.

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 the 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 and $100.0 million of outstanding borrowings under the 2012 Liquefaction Credit Facility were repaid in full.

2017 CTPL Term Loan

CTPL has a $400.0 million term loan facility (“2017 CTPL Term Loan”), which is being used to fund modifications to the Creole Trail Pipeline and for general business purposes. The 2017 CTPL Term Loan matures in 2017 when the full amount of the outstanding principal obligations must be repaid. CTPL’s loan may be repaid, in whole or in part, at any time without premium or penalty. As of December 31, 2014, CTPL had borrowed the full amount of $400.0 million available under the 2017 CTPL Term Loan. Borrowings under the 2017 CTPL Term Loan 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 is 3.25%. Interest on LIBOR loans is due and payable at the end of each LIBOR period.

Sabine Pass Liquefaction LC Agreement

In April 2014, Sabine Pass Liquefaction entered into the Sabine Pass Liquefaction LC Agreement that it uses for the issuance of letters of credit for certain working capital requirements related to the Sabine Pass Liquefaction Project. Sabine Pass Liquefaction pays (a) a commitment fee in an amount equal to an annual rate of 0.75% of an amount equal to the unissued portion of letters of credit available pursuant to the Sabine Pass Liquefaction LC Agreement and (b) a letter of credit fee equal to an annual rate of 2.5% of the undrawn portion of all letters of credit issued under the Sabine Pass Liquefaction LC Agreement. If draws are made upon any letters of credit issued under the Sabine Pass Liquefaction LC Agreement, the amount of the draw will be deemed a loan issued to Sabine Pass Liquefaction. Sabine Pass Liquefaction is required to pay the full amount of this loan on or prior to the business day immediately succeeding the deemed issuance of the loan. These loans bear interest at a rate of 2.0% plus the base rate as defined in the Sabine Pass Liquefaction LC Agreement. As of December 31, 2014, Sabine Pass Liquefaction had issued letters of credit in an aggregate amount of $9.5 million and no draws had been made upon any letters of credit issued under the Sabine Pass Liquefaction LC Agreement.

Corpus Christi LNG Terminal

Liquefaction Facilities

In September 2011, we formed 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 Corpus Christi Liquefaction Facilities would be designed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, three LNG storage tanks with capacity of approximately 10.1 Bcfe and two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters.

On December 30, 2014, the FERC issued an order granting Corpus Christi Liquefaction authorization under Section 3 of the NGA to site, construct and operate Trains 1 through 3. The Sierra Club has requested a rehearing and the FERC has not ruled on this request. In August 2012, Cheniere Marketing filed an application with the DOE to export up to the equivalent of 15 mtpa (approximately 767 Bcf/yr) of domestically produced LNG to FTA and non-FTA countries from the Corpus Christi Liquefaction Project. In October 2012, the DOE granted Cheniere Marketing authority to export up to the equivalent of 15 mtpa (approximately 767 Bcf/yr) of domestically produced LNG to FTA countries from the Corpus Christi Liquefaction Project. Corpus Christi Liquefaction was added as an additional authorization holder to the FTA permit and an additional applicant to the non-FTA application. In addition, the FERC approval requires us to obtain certain additional FERC approvals as construction progresses.

Customers

Corpus Christi Liquefaction has entered into nine fixed price, 20-year SPAs with seven third parties with aggregate annual contract quantities of approximately 8.4 mtpa of LNG. However, the Corpus Christi Liquefaction Project is not yet fully permitted. Under these nine SPAs, the customers 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. 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. Each of the SPAs contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision, which must be satisfied by June 30, 2015 or either party to each SPA may terminate its SPA.

In aggregate, the fixed fee portion to be paid by these customers is approximately $1.5 billion if we make a positive final investment decision with respect to Trains 1 through 3, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $550 million, $706 million and $280 million for each of Trains 1 through 3, respectively.

Natural Gas Transportation and Supply

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 $11.5 billion and $12.0 billion, before financing costs, including an estimate for owner’s costs and contingencies.

Pipeline Facilities

Final Investment Decision

Capital Resources

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

Convertible Notes

In January 2015, we entered into a note purchase agreement with EIG, under which EIG will purchase $1.5 billion of convertible notes to be issued by a wholly owned direct subsidiary of Cheniere. The investment is scheduled to close once we

reach a positive final investment decision on the Corpus Christi Liquefaction Project. The net proceeds would be used to fund a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project.

Credit Facilities

In December 2014, we entered into an agreement with 19 financial institutions to act as Joint Lead Arrangers to assist in the structuring and arranging of up to $11.5 billion of debt facilities. The proceeds will be used to pay for a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project. We have entered into contingent interest rate derivatives to hedge approximately 46% of the variable interest rate exposure of these projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. We anticipate that we will be required to hedge not less than 65% of this variable interest rate exposure.

LNG and Natural Gas Marketing 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 Investments;


•	pursuant to an amended and restated SPA with Sabine Pass Liquefaction, the right to purchase, at Cheniere Marketing’s option, any LNG produced by Sabine Pass Liquefaction in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG;


•	pursuant to SPAs with Corpus Christi Liquefaction, the right to purchase, at Cheniere Marketing’s option, any LNG produced by Corpus Christi Liquefaction not required for other customers; and

•

three LNG vessel time charters with subsidiaries of two ship owners, Dynagas and Teekay. The annual payments for the vessel charters will be approximately $92 million. The charters have an initial term of 5 years with the option to renew with Dynagas for a 2-year extension with similar terms as the initial term. Cheniere Marketing expects to receive delivery of the vessel from Dynagas in June 2015 and the vessels from Teekay in January 2016 and June 2016.

In addition, Cheniere Marketing has sold LNG cargoes to be delivered to multiple counterparties between 2016 and 2018, with delivery obligations conditioned on the performance of the Sabine Pass Liquefaction Project. The cargoes have been sold with a portfolio of delivery points, either on an FOB basis, delivered to the counterparty at the Sabine Pass LNG terminal, or a DAT basis, delivered to the counterparty’s LNG receiving terminal. Cheniere Marketing has chartered LNG vessels, as described above, to be utilized in DAT transactions. In addition, a wholly owned subsidiary of Cheniere Marketing has entered into a long-term agreement to sell LNG cargoes on a DAT basis, with delivery obligations conditioned on Corpus Christi Liquefaction achieving certain milestones, including a final investment decision. The agreement is also conditioned upon the buyer achieving its own milestones, including reaching a final investment decision related to certain projects and obtaining related financing.

Corporate and Other Activities

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

Sources and Uses of Cash

The following table summarizes (in thousands) the sources and uses of our cash and cash equivalents for the years ended December 31, 2014, 2013 and 2012. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.



	Year Ended December 31,
	2014			2013			2012
Sources of cash and cash equivalents
Proceeds from issuances of long-term debt	$	3,584,500		$	4,504,478		$	520,000
Use of restricted cash and cash equivalents for the acquisition of property, plant and equipment	2,684,433			3,129,709			1,587,495
Proceeds from sale of common shares by Cheniere Holdings	228,781			665,001			—
Proceeds from exercise of stock options	10,805			3,698			836
Excess tax benefit from share-based compensation	3,605			3,385			—
Proceeds from sale of common units by Cheniere Partners	—			364,775			204,878
Proceeds from sale of common stock, net	—			—			1,199,869
Proceeds from sales of Class B units by Cheniere Partners	—			—			1,387,342
Total sources of cash and cash equivalents	6,512,124			8,671,046			4,900,420

Uses of cash and cash equivalents
Investment in restricted cash and cash equivalents	(2,224,196		)	(4,083,707		)	(1,771,666		)
Property, plant and equipment, net	(2,829,558		)	(3,114,343		)	(1,117,956		)
Debt issuance and deferred financing costs	(111,807		)	(311,050		)	(223,079		)
Repayment of long-term debt	(177,000		)	(100,000		)	(1,326,514		)
Payments related to tax withholdings for share-based compensation	(112,324		)	(136,367		)	(20,414		)
Operating cash flow	(124,119		)	(52,436		)	(107,840		)
Distributions and dividends to non-controlling interest	(79,517		)	(69,220		)	(36,327		)
Investment in Cheniere Partners	—			(11,122		)	(545,144		)
Other	(66,862		)	(33,670		)	(8,929		)
Total uses of cash and cash equivalents	(5,725,383		)	(7,911,915		)	(5,157,869		)

Net increase (decrease) in cash and cash equivalents	786,741			759,131			(257,449		)
Cash and cash equivalents—beginning of period	960,842			201,711			459,160
Cash and cash equivalents—end of period	$	1,747,583		$	960,842		$	201,711

Proceeds from Issuances of Long-Term Debt, Debt Issuance and Deferred Financing Costs and Repayment of Long-Term Debt

In May 2014, Sabine Pass Liquefaction issued the 2024 Sabine Pass Liquefaction Senior Notes and the Additional 2023 Sabine Pass Liquefaction Senior Notes for total net proceeds of approximately $2.5 billion. Additionally, in November 2014, we issued $1.0 billion of the 2021 Convertible Unsecured Notes. Debt issuance and deferred financing costs in the year ended December 31, 2014, primarily relate to up-front fees paid upon the closing of these offerings.

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 were used to pay a portion of the capital costs incurred in connection with the construction of the Sabine Pass Liquefaction Project. In May 2013, CTPL entered into the $400.0 million 2017 CTPL Term Loan, which is being used to fund modifications to the Creole Trail Pipeline and for general business purposes. In June 2013, Sabine Pass Liquefaction borrowed $100.0 million under the 2013 Liquefaction Credit Facilities. Debt issuance and deferred financing costs in the year ended December 31, 2013 primarily relate to up-front fees paid by Sabine Pass Liquefaction upon the closing of the 2013 Liquefaction Credit Facilities and the notes issued by Sabine Pass Liquefaction during the year.

In October 2012, Sabine Pass LNG issued $420.0 million of 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.

During the year ended December 31, 2014, Sabine Pass Liquefaction repaid its $177.0 million of borrowings under the 2013 Liquefaction Credit Facilities upon the issuance of the Additional 2023 Sabine Pass Liquefaction Senior Notes and the 2024 Sabine Pass Liquefaction Senior Notes. During the year ended December 31, 2013, the 2012 Liquefaction Credit Facility was amended and restated with the 2013 Liquefaction Credit Facilities and the $100.0 million of outstanding borrowings under the 2012 Liquefaction Credit Facility were repaid in full.

In the year ended December 31, 2012, we repaid $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. 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 $250.0 million credit agreement entered into in August 2008 (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. Funds used for the repurchase included proceeds received from the 2020 Sabine Pass LNG Senior Notes that were issued in October 2012 and from an equity contribution from Cheniere Partners.

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

During the years ended December 31, 2014, 2013 and 2012, we used $2,684.4 million, $3,129.7 million and $1,587.5 million, respectively, of restricted cash and cash equivalents for investing activities to primarily fund $2,829.6 million, $3,114.3 million and $1,118.0 million, respectively, of construction costs for Trains 1 through 4 of the Sabine Pass Liquefaction Project. Trains 1 and 2 and Trains 3 and 4 of the Sabine Pass Liquefaction Project satisfied the criteria for capitalization in June 2012 and May 2013, respectively. Accordingly, costs associated with the construction of Trains 1 through 4 of the Sabine Pass Liquefaction Project have been recorded as construction-in-process since those dates.

Proceeds from Sale of Common Units by Cheniere Partners

The proceeds from the sale of common units of Cheniere Partners in the year ended December 31, 2013 primarily related to a February 2013 common unit purchase agreement with institutional investors to sell 17.6 million common units for net proceeds, after deducting expenses, of approximately $365 million. Cheniere Partners used the proceeds from this offering to purchase 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.

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.

Proceeds from Sale of Common Shares by Cheniere Holdings

The proceeds from the sale of Cheniere Holdings’ common shares in the year ended December 31, 2014 related to the public offering of 10.1 million of Cheniere Holdings’ common shares for net proceeds of approximately $229 million, after deducting offering expenses. The net proceeds were used to redeem from us the same number of Cheniere Holdings’ common shares, which reduced our ownership of Cheniere Holdings’ common shares from 84.5% to 80.1%.

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.

Proceeds from 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 $351.9 million. In June 2012, we used a portion of the net proceeds from this offering to repay in full 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 the remaining amount was used for capital expenditures on the Creole Trail Pipeline and general corporate purposes.

Proceeds from 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.

Investment in Restricted Cash and Cash Equivalents

In the year ended December 31, 2014, we invested $2,224.2 million in restricted cash and cash equivalents primarily related to the net proceeds from the notes issued by Sabine Pass Liquefaction during the year. In the year ended December 31, 2013, we invested $4,083.7 million in restricted cash and cash equivalents related to the net proceeds from the 2017 CTPL Term Loan, 2013 Liquefaction Credit Facilities and the notes issued by Sabine Pass Liquefaction during the year.

Distributions and Dividends to Non-controlling Interest

During the years ended December 31, 2014, 2013 and 2012, Cheniere Partners and Cheniere Holdings, collectively, made distributions and dividends of $79.5 million, $69.2 million and $36.3 million, respectively, to non-affiliated common unitholders and common shareholders.

Payments Related to Tax Withholdings for Share-based Compensation

During the years ended December 31, 2014, 2013 and 2012, we used $112.3 million, $136.4 million and $20.4 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 increased amounts in 2014 and 2013 primarily resulted from the vesting of awards under the long-term commercial bonus pools related to Trains 1 through 4 of the Sabine Pass Liquefaction Project.

Operating Cash Flow

During the years ended December 31, 2014, 2013 and 2012, we used $124.1 million, $52.4 million and $107.8 million, respectively, of cash in operating activities. The increase in operating cash outflows in 2014 compared to 2013 primarily related to increased cash outflows related to the settlement of interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities and increased general and administrative costs resulting from an increased number of employees and professional fees. The decrease in operating cash outflows in 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.

Investment in Cheniere Partners

In the year ended December 31, 2013, we invested $11.1 million in Cheniere Partners related to the purchase of general partner units. In the year ended December 31, 2012, we invested $545.1 million in Cheniere Partners related to the purchase of Class B units and general partner units.

Issuance of Common Stock

During the years ended December 31, 2014, 2013 and 2012, we issued 0.5 million, 18.9 million and 10.3 million shares, respectively, of restricted stock to new and existing employees.

Contractual Obligations

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



	Payments Due for Years Ended December 31,
	Total		2015		2016 - 2017		2018 - 2019		Thereafter
Construction and purchase obligations (1)	$	1,940,067	$	1,148,399	$	791,668	$	—	$	—
Long-term debt (2)	10,353,424		—		2,065,500		—		8,287,924
Interest payments (2)	3,527,087		573,945		1,004,513		870,527		1,078,102
Operating lease obligations (3)	742,442		35,912		206,867		202,851		296,812
Other obligations	4,125		4,125		—		—		—
Total	$	16,567,145	$	1,762,381	$	4,068,548	$	1,073,378	$	9,662,838


(1)	Construction and purchase obligations primarily relate to the EPC Contract (Trains 1 and 2) and the EPC Contract (Trains 3 and 4). A discussion of these obligations can be found at Note 14—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, 2014. See 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 $16.3 million due in the future under non-cancelable subleases. A discussion of these obligations and sublease rental payments can be found in Note 13—Leases of our Notes to Consolidated Financial Statements.

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 $1,032.5 million at December 31, 2014. For more information, see Note 3—Restricted Cash and Cash Equivalents of our Notes to Consolidated Financial Statements.

Results of Operations

2014 vs. 2013

Our consolidated net loss attributable to common stockholders was $547.9 million, or $2.44 per share (basic and diluted), in the year ended December 31, 2014 compared to a net loss attributable to common stockholders of $507.9 million, or $2.32 per share (basic and diluted), in the year ended December 31, 2013. This $40.0 million increase in net loss was primarily a result of decreased derivative gain, net, which was partially offset by increased net loss attributable to non-controlling interest, decreased general and administrative expense (“G&A Expense”) and decreased loss on early extinguishment of debt.

Derivative gain (loss), net decreased $201.5 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily as a result of a decrease in long-term LIBOR during the year ended December 31, 2014, as compared to an increase in long-term LIBOR during the year ended December 31, 2013, and the early settlement of interest rate swaps in connection with the early extinguishment of a portion of the 2013 Liquefaction Credit Facilities in May 2014. Net loss attributable to non-controlling interest increased $93.1 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily as a result of increased net loss recorded by Cheniere Partners and the increased portion of equity ownership in Cheniere Partners not attributable to us resulting from the Cheniere Partners’ common unit offering in the first quarter of 2013 and Cheniere Holdings’ initial public offering of 36.0 million common shares completed in December 2013. G&A Expense decreased $60.8 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily as a result of accelerated expense recognition in the year ended December 31, 2013 for bonus plan awards relating to the Sabine Pass Liquefaction Project. Loss on early extinguishment of debt decreased $17.2 million in the year ended December 31, 2014, as compared to the year ended December 31, 2013, due to the write-off of debt issuance costs in connection with the early extinguishment of $2.1 billion of commitments under the 2013 Liquefaction Credit Facilities in May 2014, as compared to the write-off of debt issuance costs and deferred commitment fees in connection with the early extinguishment of a portion of the commitments under the 2012 Liquefaction Credit Facility in April 2013 and the 2013 Liquefaction Credit Facilities in November 2013.

There was no significant change to interest expense, net in the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily as a result of our capitalization of interest costs incurred which were directly related to the construction of the first four Trains of the Sabine Pass Liquefaction Project. For the years ended December 31, 2014 and 2013, we incurred $587.0 million and $414.0 million of total interest cost, respectively, of which we capitalized and deferred $405.8 million and $235.6 million, respectively.

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 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.

Off-Balance Sheet Arrangements

As of December 31, 2014, we had no “off-balance sheet arrangements” that may have a current or future material effect on our 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. Management evaluates its estimates and related assumptions regularly, including those related to the value of properties, plant and equipment, goodwill, asset retirement obligations (“AROs”), income taxes, share-based compensation and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.

Fair Value

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

Derivative Instruments

All derivative instruments, other than those that satisfy specific exceptions, are recorded at fair value. We record changes in the fair value of our derivative positions based on the value for which the derivative instrument could be exchanged between willing parties. If market quotes are not available to estimate fair value, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or determined through industry-standard valuation techniques.

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

Gains and losses on derivative instruments are recognized currently in earnings. The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a change in the estimated fair value could occur in the near future as commodity prices and interest rates change.

Goodwill

At December 31, 2014, we had $76.8 million of goodwill associated with our LNG terminal reporting unit. Goodwill represents the excess of cost over fair value of the assets of businesses acquired.

We test goodwill for impairment annually during the fourth quarter, or more frequently as circumstances dictate. The first step in assessing whether an impairment of goodwill is necessary is an optional qualitative assessment to determine the likelihood of whether the fair value of the reporting unit is greater than its carrying amount. If we conclude that it is more likely than not that the fair value of the reporting unit exceeds the related carrying amount, further testing is not necessary. If the qualitative assessment is not performed or indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we compare the estimated fair value of the reporting unit to which goodwill is assigned to the carrying amount of the associated net assets, including goodwill. If the carrying value of the reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of goodwill impairment loss to be recorded, as necessary. The second step compares the implied fair value of the reporting unit’s goodwill to the carrying value, if any, of that goodwill. We determine the implied fair value of the goodwill in the same manner as determining the amount of goodwill to be recognized in a business combination.

Because quoted market prices for our reporting units are not available, we must apply judgment in determining the estimated fair value of our reporting units for purposes of performing goodwill impairment tests, when such tests are necessary. Management uses all available information to make these fair value estimates, including the present values of expected future cash flows using discount rates commensurate with the risks associated with the assets, future LNG liquefaction, operating costs and depreciation. These estimates are based on current conditions and historical experience and we rely on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

A lower fair value estimate in the future for our LNG terminal reporting unit could result in impairment of goodwill. Factors that could trigger a lower fair value estimate include significant negative industry or economic trends, cost increases, disruptions to our business and regulatory or political environment changes or other unanticipated events.

Impairment of Long-Lived Assets

A long-lived asset, including an intangible asset, is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may not be recoverable. A long-lived asset is not recoverable when its carrying value exceeds the sum of its future net undiscounted cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value. We use a variety of fair value measurement techniques when market information for the same or similar assets does not exist. Projections of future operating results and cash flows may vary significantly from results. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

Share-Based Compensation

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.

We recognize the cost for our share-based payment awards based on market conditions using Monte Carlo simulations. To calculate the Monte Carlo simulation, we must consider certain variables including volatility factors and dividend yield. Volatility factors are based on the historical and implied volatilities of Cheniere’s common stock over the expected lives as estimated on the grant date. The dividend yield is the expected annual dividend yield over the expected life, expressed as a percentage of the stock price on the grant date.

The fair value of stock options granted to employees is determined using a Black-Scholes valuation model. The risk-free rate is based on the U.S. Treasury securities yield curve in effect at the time of grant. The expected term (estimated period of time outstanding) of stock options granted is based on the “simplified” method of estimating the expected term for “plain vanilla” stock options, and varies based on the vesting period and contractual term of the stock option. Expected volatility for stock options granted is based on an equally weighted average of the implied volatility of exchange traded stock options on our common stock expiring more than one year from the measurement date, and historical volatility of our common stock for a period equal to the stock option’s expected life.

In addition, we are required to estimate the expected forfeiture rate for all of our share-based payment awards and only recognize expense for those shares expected to vest. We consider many factors when estimating expected forfeitures, including types of awards, employee class and historical experience. If our actual forfeiture rate is materially different from our estimate, future share-based compensation expense could be significantly different from what we have recorded in the current period.

See Note 2—Summary of Significant Accounting Policies and Note 11—Share-Based Compensation of our Notes to Consolidated Financial Statements for additional information regarding our share-based compensation.

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. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. This assessment requires significant judgment and is based upon our assessment of our ability to generate future taxable income among other factors.

Recent Accounting Standards

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

In June 2014, the FASB issued guidance that a performance target in a share-based payment that affects vesting and that could be achieved after the requisite service period should be accounted for as a performance condition. As a result, the target is not reflected in the estimation of the award’s grant date fair value and compensation cost for such an award would be recognized over the required service period, if it is probable that the performance condition will be achieved. This guidance is effective for annual reporting periods beginning after December 15, 2015, with early adoption permitted. We adopted this guidance in the quarterly period ended June 30, 2014. The adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.

In August 2014, the FASB issued authoritative guidance that requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. This guidance is effective for annual reporting periods ending after December 15, 2016, and for annual periods and interim periods thereafter, with earlier adoption permitted. The adoption of this guidance is not expected to have an impact on our consolidated financial position, results of operations or cash flows.


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:


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


•	commodity derivatives 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”); and


•	commodity derivatives consisting of natural gas purchase agreements to secure natural gas feedstock for the Sabine Pass Liquefaction Project (“Term Gas Supply 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. As of December 31, 2014, our commodity derivatives that are sensitive to changes in natural gas prices had a VaR of $48,000.

In order to test the sensitivity of the fair value of the Term Gas Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the Henry Hub price for natural gas. As of December 31, 2014, we estimated the fair value of our Term Gas Supply Derivatives to be $0.3 million. Based on actual derivative contractual volumes, a 10% increase or decrease in underlying commodity prices would have resulted in a change in the fair value of the Term Gas Supply Derivatives of $0.4 million as of December 31, 2014.

Interest Rate Risk

We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2013 Liquefaction Credit Facilities (“Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the full 7-year term of the Interest Rate Derivatives. This 10% change in interest rates would have resulted in a change in the fair value of the Interest Rate Derivatives of $16.5 million as of December 31, 2014.


ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES




Management’s Reports to the Stockholders of Cheniere Energy, Inc.	62
Reports of Independent Registered Public Accounting Firm—KPMG LLP	63
Report of Independent Registered Public Accounting Firm—Ernst & Young LLP	65
Consolidated Balance Sheets	66
Consolidated Statements of Operations	67
Consolidated Statements of Comprehensive Loss	68
Consolidated Statements of Stockholders’ Equity	69
Consolidated Statements of Cash Flows	70
Notes to Consolidated Financial Statements	71
Supplemental Information to Consolidated Financial Statements—Quarterly Financial Data	103

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, 2014, based on criteria in Internal Control—Integrated Framework (1992) issued by the COSO.

Cheniere’s independent registered public accounting firm, KPMG LLP, have issued an audit report on Cheniere’s internal control over financial reporting as of December 31, 2014, 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)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Cheniere Energy, Inc.:

We have audited the accompanying consolidated balance sheet of Cheniere Energy, Inc. and subsidiaries (the Company) as of December 31, 2014, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity, and cash flows for the year then ended. In connection with our audit of the consolidated financial statements, we also have audited financial statement schedule (Schedule I) for the year ended December 31, 2014. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audit.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cheniere Energy, Inc. and subsidiaries as of December 31, 2014, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule for the year ended December 31, 2014, when considered in relation to the basic consolidated financial statements taken as a whole, present 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, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 19, 2015, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

KPMG LLP

Houston, Texas

February 19, 2015

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Cheniere Energy, Inc.:

We have audited Cheniere Energy, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cheniere Energy, Inc.’s 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, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Cheniere Energy, Inc. and subsidiaries as of December 31, 2014, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity, and cash flows for the year then ended, and our report dated February 19, 2015 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

KPMG LLP

Houston, Texas

February 19, 2015

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

Cheniere Energy, Inc.

We have audited the accompanying consolidated balance sheet of Cheniere Energy, Inc. and subsidiaries as of December 31, 2013, and the related consolidated statements of operations, comprehensive loss, stockholders' equity, and cash flows for each of the two years in the period ended December 31, 2013. Our audits also included the financial statement schedule for each of the two years in the period ended December 31, 2013 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 the consolidated results of their operations and their cash flows for each of the two 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.

/s/ ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

February 21, 2014

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)



	December 31,
	2014			2013
ASSETS
Current assets
Cash and cash equivalents	$	1,747,583		$	960,842
Restricted cash and cash equivalents	481,737			598,064
Accounts and interest receivable	4,419			4,486
LNG inventory	4,294			10,563
Prepaid expenses and other	20,844			17,225
Total current assets	2,258,877			1,591,180

Non-current restricted cash and cash equivalents	550,811			1,031,399
Property, plant and equipment, net	9,246,753			6,454,399
Debt issuance costs, net	242,323			313,944
Non-current derivative assets	11,744			98,123
Goodwill	76,819			76,819
Other non-current assets	186,356			107,373
Total assets	$	12,573,683		$	9,673,237

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	13,426		$	10,367
Accrued liabilities	169,129			186,552
Deferred revenue	26,655			26,593
Derivative liabilities	23,247			13,484
Other	18			15
Total current liabilities	232,475			237,011

Long-term debt, net	9,806,084			6,576,273
Non-current deferred revenue	13,500			17,500
Other non-current liabilities	20,107			2,396

Commitments and contingencies

Stockholders’ equity (deficit)
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, 2014 and 2013
Issued and outstanding: 236.7 million and 238.1 million shares at December 31, 2014 and 2013, respectively	712			716
Treasury stock: 10.6 million shares and 9.0 million shares at December 31, 2014 and 2013, respectively, at cost	(292,752		)	(179,826		)
Additional paid-in-capital	2,776,702			2,459,699
Accumulated deficit	(2,648,839		)	(2,100,907		)
Total stockholders’ equity (deficit)	(164,177		)	179,682
Non-controlling interest	2,665,694			2,660,375
Total equity	2,501,517			2,840,057
Total liabilities and equity	$	12,573,683		$	9,673,237

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)



	Year Ended December 31,
	2014			2013			2012
Revenues
LNG terminal revenues	$	267,606		$	265,406		$	265,894
Marketing and trading revenues (losses)	(1,286		)	242			(1,172		)
Other	1,634			1,565			1,498
Total revenues	267,954			267,213			266,220

Operating costs and expenses
General and administrative expense	323,709			384,512			152,081
Operating and maintenance expense	85,792			89,169			57,076
Depreciation expense	64,258			61,209			66,407
Development expense	54,376			60,934			66,112
Other	13,387			375			376
Total operating costs and expenses	541,522			596,199			342,052

Loss from operations	(273,568		)	(328,986		)	(75,832		)

Other income (expense)
Interest expense, net	(181,236		)	(178,400		)	(200,811		)
Loss on early extinguishment of debt	(114,335		)	(131,576		)	(57,685		)
Derivative gain (loss), net	(118,012		)	83,448			58
Other income (expense)	(583		)	1,091			(11,367		)
Total other expense	(414,166		)	(225,437		)	(269,805		)

Loss before income taxes and non-controlling interest	(687,734		)	(554,423		)	(345,637		)
Income tax provision	(4,143		)	(4,340		)	(4		)
Net loss	(691,877		)	(558,763		)	(345,641		)
Less: net loss attributable to non-controlling interest	(143,945		)	(50,841		)	(12,861		)
Net loss attributable to common stockholders	$	(547,932	)	$	(507,922	)	$	(332,780	)

Net loss per share attributable to common stockholders—basic and diluted	$	(2.44	)	$	(2.32	)	$	(1.83	)

Weighted average number of common shares outstanding—basic and diluted	224,338			218,869			181,768

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)



	Year Ended December 31,
	2014			2013			2012
Net loss	$	(691,877	)	$	(558,763	)	$	(345,641	)
Other comprehensive income (loss)
Loss on settlements of interest rate cash flow hedges retained in other comprehensive income	—			(30		)	(136		)
Change in fair value of interest rate cash flow hedges	—			21,297			(27,104		)
Losses reclassified into earnings as a result of discontinuance of cash flow hedge accounting	—			5,973			—
Foreign currency translation	—			111			147
Total other comprehensive income (loss)	—			27,351			(27,093		)
Comprehensive loss	(691,877		)	(531,412		)	(372,734		)
Less: comprehensive loss attributable to non-controlling interest	(143,945		)	(48,809		)	(12,861		)
Comprehensive loss attributable to common stockholders	$	(547,932	)	$	(482,603	)	$	(359,873	)

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands)



	Total Stockholders’ Equity
	Common Stock					Treasury Stock				Additional Paid-in Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Non-controlling Interest			Total Equity
	Shares		Amount			Shares	Amount			Additional Paid-in Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Non-controlling Interest			Total Equity
Balance at 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	—			—			—			—			—			—
Share-based compensation	—		—			—	—			61,047			—			—			—			61,047
Shares repurchased related to share-based compensation	(1,330	)	(4		)	1,330	(18,920		)	4			—			—			—			(18,920		)
Foreign currency translation	—		—			—	—			—			—			147			—			147
Interest rate cash flow hedges	—		—			—	—			—			—			(27,240		)	—			(27,240		)
Loss attributable to non-controlling interest	—		—			—	—			—			—			—			(12,861		)	(12,861		)
Sale of Class B units to non-controlling interest	—		—			—	—			—			—			—			1,387,339			1,387,339
Sale of common units to non-controlling interest	—		—			—	—			—			—			—			204,878			204,878
Distribution to non-controlling interest	—		—			—	—			—			—			—			(36,327		)	(36,327		)
Net loss	—		—			—	—			—			(332,780		)	—			—			(332,780		)
Balance at December 31, 2012	223,397		671			4,727	(39,115		)	2,168,781			(1,592,985		)	(27,351		)	1,751,604			2,261,605
Issuances of stock	155		—			—	—			3,697			—			—			—			3,697
Issuances of restricted stock	18,860		57			—	—			(57		)	—			—			—			—
Forfeitures of restricted stock	(159	)	—			81	—			—			—			—			—			—
Share-based compensation	—		—			—	—			283,881			—			—			—			283,881
Shares repurchased related to share-based compensation	(4,162	)	(12		)	4,162	(140,711		)	12			—			—			—			(140,711		)
Excess tax benefit from share-based compensation	—		—			—	—			3,385			—			—			—			3,385
Foreign currency translation	—		—			—	—			—			—			111			—			111
Interest rate cash flow hedges	—		—			—	—			—			—			25,207			2,032			27,239
Loss attributable to non-controlling interest	—		—			—	—			—			—			—			(50,841		)	(50,841		)
Sale of Cheniere Holdings’ common shares to non-controlling interest	—		—			—	—			—			—			—			664,931			664,931
Sale of common units to non-controlling interest	—		—			—	—			—			—			2,033			361,869			363,902
Distribution to non-controlling interest	—		—			—	—			—			—			—			(69,220		)	(69,220		)
Net loss	—		—			—	—			—			(507,922		)	—			—			(507,922		)
Balance at December 31, 2013	238,091		716			8,970	(179,826		)	2,459,699			(2,100,907		)	—			2,660,375			2,840,057
Exercise of stock options	387		1			—	—			11,408			—			—			—			11,409
Issuances of restricted stock	550		2			—	—			(2		)	—			—			—			—
Forfeitures of restricted stock	(726	)	(2		)	69	—			2			—			—			—			—
Share-based compensation	—		—			—	—			110,039			—			—			—			110,039
Shares repurchased related to share-based compensation	(1,557	)	(5		)	1,557	(112,926		)	5			—			—			—			(112,926		)
Excess tax benefit from share-based compensation	—		—			—	—			3,605			—			—			—			3,605
Loss attributable to non-controlling interest	—		—			—	—			—			—			—			(143,945		)	(143,945		)
Issuance of convertible notes, net	—		—			—	—			191,946			—			—			—			191,946
Sale of Cheniere Holdings’ common shares to non-controlling interest	—		—			—	—			—			—			—			228,781			228,781
Distributions to non-controlling interest	—		—			—	—			—			—			—			(79,517		)	(79,517		)
Net loss	—		—			—	—			—			(547,932		)	—			—			(547,932		)
Balance at December 31, 2014	236,745		$	712		10,596	$	(292,752	)	$	2,776,702		$	(2,648,839	)	$	—		$	2,665,694		$	2,501,517

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2014			2013			2012
Cash flows from operating activities
Net loss attributable to common stockholders	$	(547,932	)	$	(507,922	)	$	(332,780	)
Adjustments to reconcile net loss to net cash used in operating activities:
Use of restricted cash and cash equivalents for certain operating activities	138,679			120,593			121,186
Loss on early extinguishment of debt	114,335			131,576			16,565
Depreciation	64,258			61,209			66,407
Amortization of debt issuance costs and discount	16,593			14,948			20,307
Share-based compensation	102,003			271,367			58,696
Non-cash LNG inventory write-downs	24,461			26,900			20,418
Total (gains) losses on derivatives, net	118,968			(84,281		)	(1,053		)
Net cash from settlement of derivative instruments	(22,758		)	609			770
Net loss attributable to non-controlling interest	(143,945		)	(50,841		)	(12,861		)
Other	15,914			(2,631		)	(14,797		)
Changes in operating assets and liabilities:
Accounts and interest receivable	67			(31		)	704
Accounts payable and accrued liabilities	16,073			6,687			(29,295		)
LNG inventory	(18,191		)	(26,576		)	(20,901		)
Deferred revenue	(3,938		)	(3,947		)	(4,089		)
Other, net	1,294			(10,096		)	2,883
Net cash used in operating activities	(124,119		)	(52,436		)	(107,840		)

Cash flows from investing activities
Property, plant and equipment, net	(2,829,558		)	(3,114,343		)	(1,117,956		)
Use of restricted cash and cash equivalents for the acquisition of property, plant and equipment	2,684,433			3,129,709			1,587,495
Investment in Cheniere Partners	—			(11,122		)	(545,144		)
Other	(66,862		)	(33,667		)	(8,929		)
Net cash used in investing activities	(211,987		)	(29,423		)	(84,534		)

Cash flows from financing activities
Proceeds from issuances of long-term debt	3,584,500			4,504,478			520,000
Proceeds from sale of common shares by Cheniere Holdings	228,781			665,001			—
Proceeds from sale of common units by Cheniere Partners	—			364,775			204,878
Proceeds from exercise of stock options	10,805			3,698			836
Proceeds from sale of common stock, net	—			—			1,199,869
Proceeds from sales of Class B units by Cheniere Partners	—			(3		)	1,387,342
Investment in restricted cash and cash equivalents	(2,224,196		)	(4,083,707		)	(1,771,666		)
Debt issuance and deferred financing costs	(111,807		)	(311,050		)	(223,079		)
Distributions and dividends to non-controlling interest	(79,517		)	(69,220		)	(36,327		)
Repayments of long-term debt	(177,000		)	(100,000		)	(1,326,514		)
Payments related to tax withholdings for share-based compensation	(112,324		)	(136,367		)	(20,414		)
Excess tax benefit from share-based compensation	3,605			3,385			—
Net cash provided by (used in) financing activities	1,122,847			840,990			(65,075		)

Net increase (decrease) in cash and cash equivalents	786,741			759,131			(257,449		)
Cash and cash equivalents—beginning of period	960,842			201,711			459,160
Cash and cash equivalents—end of period	$	1,747,583		$	960,842		$	201,711

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

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 80.1% of Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) (NYSE MKT: CQH), which is a publicly traded limited liability company that we created in 2013 that owns a 55.9% limited partner interest in Cheniere Partners.

One of our subsidiaries, Cheniere Marketing, LLC (“Cheniere Marketing”), is engaged in LNG and natural gas marketing business activities and is seeking to develop a portfolio of long-term, short-term and spot SPAs. Cheniere Marketing has entered into SPAs with Sabine Pass Liquefaction and Corpus Christi Liquefaction to purchase LNG produced by the Sabine Pass Liquefaction Project and the Corpus Christi Liquefaction Project.

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.

Unless the context requires otherwise, references to the “Company,” “Cheniere,” “we,” “us” and “our” refer to Cheniere Energy, Inc. and its consolidated subsidiaries, including Cheniere Partners and Cheniere Holdings.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Consolidated Financial Statements were prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The Consolidated Financial Statements include the accounts of Cheniere Energy, Inc. and its majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. The Consolidated Financial Statements include the accounts of Cheniere and entities in which it holds a controlling interest. As a result, the Consolidated Financial Statements include the accounts of Cheniere Holdings and Cheniere Partners and its wholly owned subsidiaries. Investments in non-controlled entities, over which Cheniere has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for the Company’s proportionate share of earnings, losses and distributions. Other investments are carried at original cost. Investments accounted for using the equity method and cost method are reported as a component of other assets.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.

Use of Estimates

The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, goodwill, collectability of accounts receivable, derivative instruments, asset retirement obligations (“AROs”), income taxes including valuation allowances for net deferred tax assets, share-based compensation and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

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

Recurring fair-value measurements are performed for commodity derivatives and interest rate derivatives as disclosed in Note 5—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 9—Long-Term Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a business combination, intangible assets, goodwill and AROs.

Revenue Recognition

LNG regasification capacity reservation fees are recognized as revenue over the term of the respective TUAs. Advance capacity reservation fees are initially deferred and amortized over a 10-year period as a reduction of a customer’s regasification capacity reservation fees payable under its TUA. Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of LNG delivered for each customer’s account at the Sabine Pass LNG terminal, which is recognized as revenues as Sabine Pass LNG performs the services set forth in each customer’s TUA.

LNG and Natural Gas Marketing

We have determined that our LNG and natural gas marketing business activities are energy trading and risk management activities for trading purposes and have elected to present these activities on a net basis on our Consolidated Statements of Operations. Marketing and trading revenues represent the margin earned on the purchase and transportation of LNG purchases and subsequent sales of natural gas to third parties. These energy trading and risk management activities include, but are not limited to: purchase of LNG and natural gas, transportation contracts and derivatives. Below is a brief description of our accounting treatment of each type of energy trading and risk management activity and how we account for each:

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Purchase of LNG and natural gas

The purchase value of LNG or natural gas inventory is recorded as an asset on our Consolidated Balance Sheets at the cost to acquire the product. Our inventory is subject to lower of cost or market adjustment each quarter. Recoveries of losses resulting from interim period lower of cost or market adjustments are made due to market price recoveries on the same inventory in the same fiscal year and are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. Any adjustment to our inventory is recorded on a net basis as LNG and natural gas marketing revenue on our Consolidated Statements of Operations.

Transportation contracts

We enter into transportation contracts with respect to the transport of LNG or natural gas to a specific location for storage or sale. Transportation costs that are incurred during the purchase of LNG or natural gas are capitalized as part of the acquisition costs of the product. Transportation costs incurred to sell LNG or natural gas are recorded on a net basis as LNG and natural gas marketing revenue on our Consolidated Statements of Operations.

LNG Inventory Derivatives

We use derivative instruments to hedge cash flows attributable to the future sale of LNG inventory. 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.

Cash and Cash Equivalents

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

Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consist of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets.

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

LNG Inventory

LNG inventory is recorded at cost and is subject to lower of cost or market (“LCM”) adjustments at the end of each period. LNG inventory cost is determined using the average cost method. Our LCM adjustments primarily related to LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal that are recorded in operating and maintenance expense on our Consolidated Statements of Operations. Recoveries of losses resulting from interim period LCM adjustments are recorded when market price recoveries occur on the same inventory in the same fiscal year. These recoveries are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. During the years ended December 31, 2014, 2013 and 2012, we recognized $24.5 million, $26.9 million and $20.4 million, respectively, as operating and maintenance expense as a result of LCM adjustments primarily related to LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Accounting for LNG Activities

Generally, we begin capitalizing the costs of our LNG terminals and related pipelines once the individual project meets the following criteria: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals, and other preliminary investigation and development activities related to our LNG terminals and related pipelines.

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as intangible LNG assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.

We capitalize interest and other related debt costs during the construction period of our LNG terminal. Upon commencement of operations, capitalized interest, as a component of the total cost, will be amortized over the estimated useful life of the asset.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs and general and administrative activities are charged to expense as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in other operating costs and expenses.

Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. In performing this test, an undiscounted cash flow analysis is performed at the lowest level for which identifiable cash flows are independent of cash flows from other assets. If the sum of the undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value. We have recorded no impairments related to property, plant and equipment for 2014, 2013 or 2012.

Regulated Natural Gas Pipelines

The Creole Trail Pipeline and Corpus Christi Pipeline are subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities.

Items that may influence our assessment are:


•	inability to recover cost increases due to rate caps and rate case moratoriums;


•	inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;


•	excess capacity;

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED


•	increased competition and discounting in the markets we serve; and


•	impacts of ongoing regulatory initiatives in the natural gas industry.

Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price and interest rate risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in current earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges as of December 31, 2014 and 2013.

From time to time, we have elected cash flow hedge accounting for derivatives that we use to hedge the exposure to volatility in floating-rate interest payments. Changes in fair value of derivative instruments designated as cash flow hedges, to the extent the hedge is effective, are recognized in accumulated other comprehensive loss on our 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, prospective changes in fair value of the derivative instrument are recorded in income. Once we conclude that the hedged forecasted transaction becomes probable of not occurring, the amount remaining in accumulated other comprehensive loss pertaining to the previously designated derivatives is reclassified out of accumulated other comprehensive loss and into income.

See Note 5—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk

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

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded as an other current asset and not netted within the derivative fair value. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Sabine Pass LNG has entered into certain long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal. Sabine Pass LNG is dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective TUAs. Sabine Pass LNG has mitigated this credit risk by securing TUAs for a significant portion of its regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA.

Sabine Pass Liquefaction has entered into six fixed price 20-year SPAs with six unaffiliated third parties. Corpus Christi Liquefaction has entered into nine fixed price 20-year SPAs with seven unaffiliated third parties. Sabine Pass Liquefaction and Corpus Christi Liquefaction are dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective SPAs.

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, 2014 and 2013 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 chief operating decision maker 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 2014 and 2013, we performed a qualitative assessment of goodwill in accordance with 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 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, we perform the second step of the goodwill impairment test to measure the amount of goodwill impairment loss to be recorded, as necessary. The second step compares the implied fair value of the reporting unit’s goodwill to the carrying value, if any, of that goodwill. We determine the implied fair value of the goodwill in the same manner as determining the amount of goodwill to be recognized in a business combination.

We completed our annual assessment of goodwill impairment during the fourth quarters of 2014 and 2013, and the tests indicated no impairment. As discussed above regarding our use of estimates, our judgments and assumptions are inherent in our 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 impairment charges in the Consolidated Financial Statements. A lower fair value estimate in the future for our LNG terminal reporting unit could result in an impairment of goodwill. Factors that could trigger a lower fair value estimate include significant negative industry or economic trends, cost increases, disruptions to our business, regulatory or political environment changes or other unanticipated events.

Long-Term Debt

Our debt consists of long-term secured debt securities, convertible debt securities, and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.

Debt is recorded on our balance sheet at par value adjusted for unamortized discount or premium. Discounts, premiums, and costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net using the effective interest method. Gains and losses on the extinguishment of debt are recorded in gains and losses on the extinguishment of debt on our Consolidated Statements of Operations.

Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are recorded as debt issuance costs on our Consolidated Balance Sheets and are being amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on early extinguishment of debt.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Asset Retirement Obligations

We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our recognition of AROs is described below.

Currently, the 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.

Share-based Compensation

We have awarded share-based compensation in the form of stock, restricted stock, stock options and phantom units that are more fully described in Note 11—Share-Based Compensation. A summary of our accounting policy for share-based awards follows.

We recognize share-based compensation at fair value on the date of grant. The fair value is recognized as expense (net of any capitalization) over the requisite service period. For equity-classified share-based compensation awards (which include stock, restricted stock to employees and non-employee directors and stock options), compensation cost is recognized based on the grant-date fair value using the quoted market price of Cheniere’s common stock and not subsequently remeasured. The fair value is recognized as expense (net of any capitalization) using the straight-line basis for awards that vest based on service and market conditions and using the accelerated recognition method for awards that vest based on performance conditions. We estimate the service periods for performance awards utilizing a probability assessment based on when we expect to achieve the performance conditions. For liability-classified share-based compensation awards (which include restricted stock to non-employees and phantom units), compensation cost is initially recognized on the grant date using estimated payout levels. Compensation cost is subsequently adjusted quarterly to reflect the updated estimated payout levels based on the changes in the Company’s stock price.

Non-controlling Interests

When we consolidate a subsidiary, we include 100% of the assets, liabilities, revenues, and expenses of the subsidiary in our Consolidated Financial Statements, even if we own less than 100% of the subsidiary. Non-controlling interests represent third-party ownership in the net assets of our consolidated subsidiaries and are presented as a component of equity. Changes in our ownership interests in subsidiaries that do not result in deconsolidation are recognized within equity. See Note 7—Non-controlling Interests for additional details about our non-controlling interest.

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 is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that a

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

portion or all of the deferred tax assets will expire before realization of the benefit or future deductibility is not probable. 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.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the tax position.

Net Loss Per Share

Net loss per share (“EPS”) is computed in accordance with GAAP. Basic EPS excludes dilution and is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted EPS reflects potential dilution and is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued and were dilutive. Basic and diluted EPS for all periods presented are the same since the effect of our options and unvested stock is anti-dilutive to our net loss per share. Stock options and unvested stock representing securities that could potentially dilute basic EPS in the future that were not included in the diluted computation because they would have been anti-dilutive for the years 2014, 2013 and 2012, were 10.4 million shares, 14.1 million shares and 4.4 million shares, respectively. In addition, 14.3 million shares issuable upon conversion of the 2021 Convertible Unsecured Notes, as described in Note 9—Long-Term Debt, were not included in the computation of diluted net loss per share for 2014 because the computation of diluted net loss per share utilizing the “if-converted” method would be anti-dilutive.

NOTE 3—RESTRICTED CASH AND CASH EQUIVALENTS

Sabine Pass LNG Senior Notes Debt Service Reserve

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

As of both December 31, 2014 and 2013, we classified $15.0 million as current restricted cash and cash equivalents for the payment of current interest due. As of both December 31, 2014 and 2013, we classified the permanent debt service reserve fund of $76.1 million as non-current restricted cash and cash equivalents. These cash accounts are controlled by a collateral trustee and, therefore, are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.

Sabine Pass Liquefaction Reserve

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”). During 2013, Sabine Pass Liquefaction entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 Liquefaction Credit Facilities”), which amended and restated the 2012 Liquefaction Credit Facility. Under the terms and conditions of the 2012 Liquefaction Credit Facility Sabine Pass Liquefaction was required, and under the 2013 Liquefaction Credit Facilities Sabine Pass Liquefaction is required, to deposit all cash received into reserve accounts controlled by a collateral trustee. Therefore, all of Sabine Pass Liquefaction’s cash and cash equivalents are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

During 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion, before premium, 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”). During 2014, Sabine Pass Liquefaction issued an aggregate principal amount of $2.0 billion of 5.75% Senior Secured Notes due 2024 (the “2024 Sabine Pass Liquefaction Senior Notes” and collectively with the 2021 Sabine Pass Liquefaction Senior Notes, the 2022 Sabine Pass Liquefaction Senior Notes and the 2023 Sabine Pass Liquefaction Senior Notes, the “Sabine Pass Liquefaction Senior Notes”) and additional 2023 Sabine Pass Liquefaction Senior Notes (the “Additional 2023 Sabine Pass Liquefaction Senior Notes”) in an aggregate principal amount of $0.5 billion, before premium.

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

CTPL Reserve

In May 2013, CTPL entered into a $400.0 million term loan facility (the “2017 CTPL Term Loan”). As of December 31, 2014 and 2013, we classified $24.9 million and $20.5 million, respectively, as current restricted cash and cash equivalents held by CTPL for the payment of current liabilities and $11.3 million and $81.4 million, respectively, as non-current restricted cash and cash equivalents held by CTPL because such funds may only be used for modifications of the 94-mile Creole Trail Pipeline, which interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines, in order to enable bi-directional natural gas flow and for the payment of interest during construction of such modifications. The restricted cash reserved to pay interest during construction is controlled by a collateral agent, and can only be released by the collateral agent upon satisfaction of certain terms and conditions.

See Note 9—Long-Term Debt for additional details about our long-term debt.

Other Restricted Cash and Cash Equivalents

As of December 31, 2014 and 2013, $250.1 million and $351.0 million, respectively, of cash and cash equivalents were held by Sabine Pass LNG, Cheniere Partners, and Cheniere Holdings that were restricted from use by Cheniere. In addition, as of December 31, 2014 and 2013, $35.9 million and $19.4 million, respectively, had been classified as current restricted cash and cash equivalents, and as of both December 31, 2014 and 2013, $6.3 million had been classified as non-current restricted cash and cash equivalents on our Consolidated Balance Sheets due to various other contractual restrictions.

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

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



	December 31,
	2014			2013
LNG terminal costs
LNG terminal	$	2,269,429		$	2,234,796
LNG terminal construction-in-process	7,155,046			4,489,668
LNG site and related costs, net	9,395			6,511
Accumulated depreciation	(350,497		)	(292,434		)
Total LNG terminal costs, net	9,083,373			6,438,541
Fixed assets and other
Computer and office equipment	5,111			8,115
Furniture and fixtures	5,531			4,319
Computer software	46,882			13,504
Leasehold improvements	43,622			7,303
Land and other	92,403			15,388
Accumulated depreciation	(30,169		)	(32,771		)
Total fixed assets and other, net	163,380			15,858
Property, plant and equipment, net	$	9,246,753		$	6,454,399

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

LNG Terminal Costs

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



Components		Useful life (yrs)
LNG storage tanks		50
Natural gas pipeline facilities		40
Marine berth, electrical, facility and roads		35
Regasification processing equipment (recondensers, vaporization and vents)		30
Sendout pumps		20
Other		15-30

We are developing the Corpus Christi Liquefaction Project and have capitalized certain costs associated with our proposed Corpus Christi LNG terminal for site work that improved the associated land. As of December 31, 2014 and 2013, $66.1 million and $35.5 million, respectively, of costs associated with the initial site work for the proposed Corpus Christi LNG terminal were capitalized as LNG terminal construction-in-process.

Fixed Assets and Other

Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 5—DERIVATIVE INSTRUMENTS

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


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


•	commodity derivatives 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”);


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


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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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



	Fair Value Measurements as of
	December 31, 2014										December 31, 2013
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
LNG Inventory Derivatives asset (liability)	$	—	$	1,140		$	—	$	1,140		$	—	$	(171	)	$	—	$	(171	)
Fuel Derivatives asset (liability)	—		(921		)	—		(921		)	—		126			—		126
Term Gas Supply Derivatives asset	—		—			342		342			—		—			—		—
Interest Rate Derivatives asset (liability)	—		(12,036		)	—		(12,036		)	—		84,639			—		84,639

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

The fair value of Sabine Pass Liquefaction’s Term Gas Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of Sabine Pass Liquefaction’s Term Gas Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of the Term Gas Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a particular Term Gas Supply Derivative contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. Internal fair value models that include contractual pricing with a fixed basis include fixed basis amounts for delivery at locations for which no market currently exists. Internal fair value models also include conditions precedent to the respective long-term natural gas purchase agreements. As of December 31, 2014, the majority of Sabine Pass Liquefaction’s Term Gas Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow and our internal fair value models were based on a market price that equated to our own contractual pricing due to the inactive and unobservable market as well as the conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. The fair value of the Term Gas Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. We estimated the fair value of Sabine Pass Liquefaction’s Term Gas Supply Derivatives to be $0.3 million as of December 31, 2014.

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



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

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Commodity Derivatives

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

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



		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2014			December 31, 2013
LNG Inventory Derivatives asset (liability)	Prepaid expenses and other	$	1,140		$	(171	)
Fuel Derivatives asset (liability)	Prepaid expenses and other	(921		)	126
Term Gas Supply Derivatives asset	Prepaid expenses and other	76			—
Term Gas Supply Derivatives asset	Non-current derivative assets	586			—
Term Gas Supply Derivatives liability	Other current liabilities	(53		)	—
Term Gas Supply Derivatives liability	Other non-current liabilities	(267		)	—

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



		Year Ended December 31,
	Income Statement Location	2014			2013			2012
LNG Inventory Derivatives gain (loss)	Marketing and trading revenues (losses)	$	(346	)	$	(449	)	$	995
Fuel Derivatives gain (loss)	Marketing and trading revenues (losses)	(952		)	99			—
LNG Inventory Derivatives gain	Derivative gain (loss), net	1,108			476			—
Fuel Derivatives gain (loss)	Derivative gain (loss), net	281			182			(622		)
Term Gas Supply Derivatives gain (1)	Operating and maintenance expense	342			—			—

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

LNG Inventory and Fuel Derivatives

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances where our LNG Inventory Derivatives or Fuel Derivatives are in an asset position. Our LNG Inventory Derivatives and Fuel Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for these commodity derivative activities. Collateral of $5.7 million and $5.9 million deposited for such contracts, which has not been reflected in the derivative fair value tables, is included in the other current assets balance as of December 31, 2014 and 2013, respectively.

Term Gas Supply Derivatives

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

As of December 31, 2014, the majority of Sabine Pass Liquefaction’s Term Gas Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow and our internal fair value models were based on a market price that equated to Sabine Pass Liquefaction’s own contractual pricing due to the inactive and unobservable market as well as the conditions precedent and their impact on the uncertainty in the timing of our actual receipt

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

of the physical volumes associated with each forward. As of December 31, 2014, the forward notional natural gas buy position of Sabine Pass Liquefaction’s Term Gas Supply Derivatives was approximately 1,249.4 million MMBtu.

Interest Rate Derivatives

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

Sabine Pass Liquefaction designated the Interest Rate Derivatives entered into in August 2012 as hedging instruments which was required in order to qualify for cash flow hedge accounting. As a result of this cash flow hedge designation, we recognized the Interest Rate Derivatives entered into in August 2012 as an asset or liability at fair value and reflected changes in fair value through other comprehensive income in our Consolidated Statements of Comprehensive Loss. Any hedge ineffectiveness associated with the Interest Rate Derivatives entered into in August 2012 was recorded immediately as derivative gain (loss) in our Consolidated Statements of Operations. The realized gain (loss) on the Interest Rate Derivatives entered into in August 2012 was recorded as an (increase) decrease in interest expense on our Consolidated Statements of Operations to the extent not capitalized as part of the Sabine Pass Liquefaction Project. The effective portion of the gains or losses on our Interest Rate Derivatives entered into in August 2012 recorded in other comprehensive income would have been reclassified to earnings as interest payments on the 2012 Liquefaction Credit Facility impact earnings. In addition, amounts recorded in other comprehensive income are also reclassified into earnings if it becomes probable that the hedged forecasted transaction will not occur.

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

During the first quarter of 2013, we determined that it was no longer probable that the forecasted variable interest payments on the 2012 Liquefaction Credit Facility would occur in the time period originally specified based on the continued development of our financing strategy for the Sabine Pass Liquefaction Project, and, in particular, the Sabine Pass Liquefaction Senior Notes described in Note 9—Long-Term Debt. As a result, all of the Interest Rate Derivatives entered into in August 2012 were no longer effective hedges, and the remaining portion of hedge relationships that were designated cash flow hedges as of December 31, 2012, were de-designated as of February 1, 2013. For de-designated cash flow hedges, changes in fair value prior to their de-designation date were recorded as other comprehensive income (loss) within our Consolidated Balance Sheets, and changes in fair value subsequent to their de-designation date were recorded as derivative gain (loss) within our Consolidated Statements of Operations.

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

In May 2014, Sabine Pass Liquefaction settled a portion of its Interest Rate Derivatives and recognized a derivative loss of $9.3 million within our Consolidated Statements of Operations in conjunction with the termination of approximately $2.1 billion of commitments under the 2013 Liquefaction Credit Facilities as discussed in Note 9—Long-Term Debt.

At December 31, 2014, Sabine Pass Liquefaction had the following Interest Rate Derivatives outstanding:

Initial Notional Amount

Maximum Notional Amount

Effective Date

Maturity Date

Weighted Average Fixed Interest Rate Paid

Variable Interest Rate Received

Interest Rate Derivatives - Not Designated

$20.0 million

$2.5 billion

August 14, 2012

July 31, 2019

1.98%

One-month LIBOR

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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



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

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



	Gain (Loss) in OCI			Gain (Loss) Reclassified from AOCI into Interest Expense (Effective Portion)		Losses Reclassified into Earnings as a Result of Discontinuance of Cash Flow Hedge Accounting
December 31, 2012
Interest Rate Derivatives - Designated	$	(21,290	)	$	—	$	—
Interest Rate Derivatives - De-designated	(5,814		)	—		—
Interest Rate Derivatives - Settlements	(136		)	—		—
December 31, 2013
Interest Rate Derivatives - Designated	21,297			—		5,807
Interest Rate Derivatives - De-designated	—			—		—
Interest Rate Derivatives - Settlements	(30		)	—		166
December 31, 2014
Interest Rate Derivatives - Designated	—			—		—
Interest Rate Derivatives - De-designated	—			—		—
Interest Rate Derivatives - Settlements	—			—		—

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



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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Balance Sheet Presentation

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



	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets			Gross Amounts Not Offset in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets			Derivative Instrument		Cash Collateral Received (Paid)		Net Amount
As of December 31, 2014:
LNG Inventory Derivatives	$	1,140		$	1,056		$	84		$	—	$	—	$	84
Fuel Derivatives	(921		)	(921		)	—			—		—		—
Term Gas Supply Derivatives	662			—			662			—		—		662
Term Gas Supply Derivatives	(320		)	—			(320		)	—		—		(320		)
Interest Rate Derivatives - Not Designated	11,158			—			11,158			—		—		11,158
Interest Rate Derivatives - Not Designated	(23,194		)	—			(23,194		)	—		—		(23,194		)
As of December 31, 2013:
LNG Inventory Derivatives	(171		)	(171		)	—			—		—		—
Fuel Derivatives	126			—			126			—		—		126
Interest Rate Derivatives - Not Designated	98,123			—			98,123			—		—		98,123
Interest Rate Derivatives - Not Designated	(13,484		)	—			(13,484		)	—		—		(13,484		)

NOTE 6—VARIABLE INTEREST ENTITY

Cheniere Partners

Cheniere Partners is a master limited partnership formed by us in 2006 to own and operate the Sabine Pass LNG terminal and related assets. Cheniere Holdings is a limited liability company formed by us in 2013 to hold our Cheniere Partners limited partner interests. As of December 31, 2014, we owned 80.1% of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners in the form of 12.0 million common units, 45.3 million Class B units and 135.4 million subordinated units. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners.

Cheniere Energy Partners GP, LLC (“Cheniere Partners GP”), our wholly owned subsidiary, is the general partner of Cheniere Partners. In May 2012, Cheniere Partners, Cheniere and Blackstone CQP Holdco LP (“Blackstone”) entered into a unit purchase agreement (the “Blackstone Unit Purchase Agreement”) whereby Cheniere Partners agreed to sell to Blackstone in a private placement 100.0 million Class B units of Cheniere Partners (“Class B units”) at a price of $15.00 per Class B unit. In August 2012, all conditions to funding were met and Blackstone purchased its initial 33.3 million Class B units, and as of December 31, 2012, Blackstone had purchased the remaining 66.7 million Class B units. At initial funding, the board of directors of Cheniere Partners GP was modified to include three directors appointed by Blackstone, four directors appointed by us and four independent directors mutually agreed upon by Blackstone and us and appointed by us. In addition, we provided Blackstone with a right to maintain one board seat on our board of directors. A quorum of Cheniere Partners GP directors consists of a majority of all directors, including at least two directors appointed by Blackstone, two directors appointed by us and two independent directors. Blackstone will no longer be entitled to appoint Cheniere Partners GP directors in the event that Blackstone’s ownership in Cheniere Partners is less than: (i) 20% of outstanding common units, subordinated units and Class B units, and (ii) 50.0 million Class B units.

As a result of contractual changes in the governance of Cheniere Partners GP in connection with the Blackstone Unit Purchase Agreement, we have determined that Cheniere Partners GP is a variable interest entity and that we, as the holder of the equity at risk, do not have a controlling financial interest due to the rights held by Blackstone. However, we continue to consolidate Cheniere Partners as a result of Blackstone’s right to maintain one board seat on our board of directors which creates a de facto agency relationship between Blackstone and us. GAAP requires that when a de facto agency relationship exists, one of the members of the de facto agency relationship must consolidate the variable interest entity based on certain criteria. As a result, we consolidate Cheniere Partners in our Consolidated Financial Statements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 7—NON-CONTROLLING INTEREST

In December 2013, Cheniere Holdings completed its initial public offering (the “Cheniere Holdings Offering”) of 36.0 million common shares at $20.00 per common share. Cheniere Holdings was formed by us to hold our limited partner interest in Cheniere Partners. We ultimately received all of the $665.0 million of net proceeds, after deducting offering expenses, 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. Additionally, in November 2014, Cheniere Holdings sold 10.1 million common shares at $22.76 per common share for net proceeds of approximately $229 million, after deducting offering expenses, which were used to redeem from us the same number of common shares. As of December 31, 2014 and 2013, our ownership interest in Cheniere Holdings was 80.1% and 84.5%, respectively, with the remaining non-controlling interest held by the public. Our ownership of Cheniere Partners interests is further discussed in Note 6—Variable Interest Entities.

NOTE 8—ACCRUED LIABILITIES

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



	December 31,
	2014		2013
Interest expense and related debt fees	$	112,858	$	80,151
Payroll	6,425		7,410
LNG liquefaction costs	22,014		83,651
LNG terminal costs	1,077		1,612
Other accrued liabilities	26,755		13,728
Total accrued liabilities	$	169,129	$	186,552

NOTE 9—LONG-TERM DEBT

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



	December 31,
	2014			2013
Long-term debt
2016 Sabine Pass LNG Senior Notes	$	1,665,500		$	1,665,500
2020 Sabine Pass LNG Senior Notes	420,000			420,000
2021 Sabine Pass Liquefaction Senior Notes	2,000,000			2,000,000
2022 Sabine Pass Liquefaction Senior Notes	1,000,000			1,000,000
2023 Sabine Pass Liquefaction Senior Notes	1,500,000			1,000,000
2024 Sabine Pass Liquefaction Senior Notes	2,000,000			—
2013 Liquefaction Credit Facilities	—			100,000
2021 Convertible Unsecured Notes	1,004,469			—
2017 CTPL Term Loan	400,000			400,000
Total long-term debt	9,989,969			6,585,500
Long-term debt premium (discount)
2016 Sabine Pass LNG Senior Notes	(8,998		)	(13,693		)
2021 Sabine Pass Liquefaction Senior Notes	10,177			11,562
2023 Sabine Pass Liquefaction Senior Notes	7,088			—
2021 Convertible Unsecured Notes	(189,717		)	—
2017 CTPL Term Loan	(2,435		)	(7,096		)
Total long-term debt, net	$	9,806,084		$	6,576,273

For the years ended December 31, 2014, 2013 and 2012, we incurred $587.0 million, $414.0 million and $235.9 million of total interest cost, respectively, of which we capitalized and deferred $405.8 million, $233.0 million and $35.1 million, respectively, of interest cost, including amortization of debt issuance costs, primarily related to the construction of the first four Trains of the Sabine Pass Liquefaction Project.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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



	Payments Due for the Years Ended December 31,
	Total		2015		2016 to 2017		2018 to 2019		Thereafter
Debt:
2016 Notes	$	1,665,500	$	—	$	1,665,500	$	—	$	—
2020 Notes	420,000		—		—		—		420,000
2021 Sabine Pass Liquefaction Senior Notes	2,000,000		—		—		—		2,000,000
2022 Sabine Pass Liquefaction Senior Notes	1,000,000		—		—		—		1,000,000
2023 Sabine Pass Liquefaction Senior Notes	1,500,000		—		—		—		1,500,000
2024 Sabine Pass Liquefaction Senior Notes	2,000,000		—		—		—		2,000,000
2021 Convertible Unsecured Notes	1,004,469		—		—		—		1,004,469
2017 CTPL Term Loan	400,000		—		400,000		—		—
Total Debt	$	9,989,969	$	—	$	2,065,500	$	—	$	7,924,469

Sabine Pass LNG Senior Notes

As of both December 31, 2014 and 2013, Sabine Pass LNG had an aggregate principal amount of $1,665.5 million, before discount, of the 2016 Sabine Pass LNG Senior Notes and $420.0 million of the 2020 Sabine Pass LNG Senior Notes outstanding. Borrowings under the 2016 Sabine Pass LNG Senior Notes and 2020 Sabine Pass LNG Senior Notes bear interest at a fixed rate of 7.50% and 6.50%, respectively. The terms of the 2016 Sabine Pass LNG Senior Notes and the 2020 Sabine Pass LNG Senior Notes are substantially similar. Interest on the Sabine Pass LNG Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the Sabine Pass LNG Senior Notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG’s equity interests and substantially all of its operating assets.

Sabine Pass LNG may redeem all or part of the 2016 Sabine Pass LNG Senior 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 Sabine Pass LNG Senior Notes; or

•

Sabine Pass LNG may redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time on or after November 1, 2016, at fixed redemption prices specified in the indenture governing the 2020 Sabine Pass LNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also, at its option, redeem all or part of the 2020 Sabine Pass LNG Senior Notes at any time prior to November 1, 2016, at a “make-whole” price set forth in the indenture governing the 2020 Sabine Pass LNG Senior Notes, 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 Sabine Pass LNG Senior Notes at a redemption price of 106.5% of the principal amount of the 2020 Sabine Pass LNG Senior 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 Sabine Pass LNG Senior Notes within 180 days of the closing date for such equity offering and at least 65% of the aggregate principal amount of the 2020 Sabine Pass LNG Senior Notes originally issued remains outstanding after the redemption.

Under the Sabine Pass LNG Indentures, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied as described in Note 3—Restricted Cash and Cash Equivalents. During the years ended December 31, 2014, 2013 and 2012, Sabine Pass LNG made distributions of $346.9 million, $348.9 million and $333.5 million, respectively, after satisfying all the applicable conditions in the Sabine Pass LNG Indentures.

Sabine Pass Liquefaction Senior Notes

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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

The terms of the 2021 Sabine Pass Liquefaction Senior Notes, the 2022 Sabine Pass Liquefaction Senior Notes, the 2023 Sabine Pass Liquefaction Senior Notes and the 2024 Sabine Pass Liquefaction Senior Notes are governed by a common indenture (the “Sabine Pass Liquefaction Indenture”). The Sabine Pass Liquefaction Indenture contains customary terms and events of default and certain covenants that, among other things, limit Sabine Pass Liquefaction’s ability and the ability of Sabine Pass Liquefaction’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of Sabine Pass Liquefaction’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, consolidate, merge, sell or lease all or substantially all of Sabine Pass Liquefaction’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the Sabine Pass Liquefaction Senior Notes are secured on a pari passu 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 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 for the prior 12-month period and a projected debt service coverage ratio for the upcoming 12-month period of 1.25:1.00 are satisfied.

At any time prior to November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes; December 15, 2021, with respect to the 2022 Sabine Pass Liquefaction Senior Notes; January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes; or February 15, 2024, with respect to the 2024 Sabine Pass Liquefaction Senior Notes, Sabine Pass Liquefaction may redeem all or part of such series of the Sabine Pass Liquefaction Senior Notes at a redemption price equal to the “make-whole” price set forth in the Sabine Pass Liquefaction Indenture, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass Liquefaction may also at any time on or after November 1, 2020, with respect to the 2021 Sabine Pass Liquefaction Senior Notes; December 15, 2021, with respect to the 2022 Sabine Pass Liquefaction Senior Notes; January 15, 2023, with respect to the 2023 Sabine Pass Liquefaction Senior Notes; or February 15, 2024, with respect to the 2024 Sabine Pass Liquefaction Senior Notes, redeem all or part of such series of the Sabine Pass Liquefaction Senior Notes at a redemption price equal to 100% of the principal amount of such series of the Sabine Pass Liquefaction Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

2013 Liquefaction Credit Facilities

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

Borrowings 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”) or the base rate, plus the applicable margin. The applicable margins for LIBOR loans range from 2.3% to 3.0% prior to the completion of Train 4 and from 2.3% to 3.25% after such completion, depending on the applicable 2013 Liquefaction Credit Facility. Interest on LIBOR loans is due and payable at the end of each LIBOR period. The 2013 Liquefaction Credit Facilities required Sabine Pass Liquefaction to pay certain up-front fees to the agents and lenders in the aggregate amount of approximately $144 million and provide for a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of the undrawn commitment

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

due quarterly in arrears. Annual administrative fees must also be paid to the agent and the trustee. The principal of the loans made under the 2013 Liquefaction Credit Facilities must be repaid in quarterly installments, commencing with the earlier of the last day of the first full calendar quarter after the Train 4 completion date, as defined in the 2013 Liquefaction Credit Facilities, or September 30, 2018. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2013 Liquefaction Credit Facilities.

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

The 2013 Liquefaction Credit Facilities contain conditions precedent for any subsequent borrowings, as well as customary affirmative and negative covenants. The obligations of Sabine Pass Liquefaction under the 2013 Liquefaction Credit Facilities are secured by substantially all of the assets of Sabine Pass Liquefaction as well as all of the membership interests in Sabine Pass Liquefaction on a pari passu basis with the Sabine Pass Liquefaction Senior Notes.

Under the terms of the 2013 Liquefaction Credit Facilities, Sabine Pass Liquefaction is required to hedge not less than 75% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. See Note 5— Derivative Instruments.

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

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

2012 Liquefaction Credit Facility

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

Under the terms of the 2012 Liquefaction Credit Facility, Sabine Pass Liquefaction was required to hedge not less than 75% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal. See Note 5— Derivative Instruments.

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

2021 Convertible Unsecured Notes

In November 2014, we issued an aggregate principal amount of $1.0 billion unsecured convertible notes due 2021 (the “2021 Convertible Unsecured Notes”) on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act and Regulation S promulgated thereunder. The 2021 Convertible Unsecured Notes bear interest at a rate of 4.875% per annum, which is payable in kind (“PIK”) semi-annually in arrears by increasing the principal

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

amount of the 2021 Convertible Unsecured Notes outstanding. One year after the closing date, the 2021 Convertible Unsecured Notes will be convertible at the option of the holder into our common stock at an initial conversion price of $93.64, provided that our closing price of common stock is greater than or equal to $93.64 on the conversion date. The conversion rate is subject to adjustment upon the occurrence of certain specified events. We have the option to satisfy the conversion obligation with cash, common stock or a combination thereof.

Under GAAP, certain convertible debt instruments that may be settled in cash upon conversion are required to be separately accounted for as liability (debt) and equity (conversion option) components of the instrument in a manner that reflects the issuer’s non-convertible debt borrowing rate. We determined that the fair value of the debt component was $808.8 million and the residual value of the equity component was $191.2 million as of the issuance date. The debt component is accreted to the total principal amount due at maturity by amortizing the debt discount. The effective rate of interest to amortize the debt discount was approximately 9.16% as of December 31, 2014, and the remaining period over which the debt discount will be amortized was 6.4 years.

Interest expense, before capitalization, related to the 2021 Convertible Unsecured Notes consisted of the following (in thousands):



	Year Ended December 31,
	2014		2013		2012
PIK interest per contractual rate	$	4,469	$	—	$	—
Amortization of debt discount	2,328		—		—
Amortization of debt issuance costs	4		—		—
Total interest expense related to 2021 Convertible Unsecured Notes	$	6,801	$	—	$	—

In connection with the issuance of the 2021 Convertible Unsecured Notes, we have agreed, if permitted by applicable law and approved by the Securities and Exchange Commission (“SEC”), to use commercially reasonable efforts to file with the SEC and cause to become effective registration statements relating to offers to exchange the 2021 Convertible Unsecured Notes for like aggregate principal amounts of SEC-registered notes with terms identical in all material respects to the 2021 Convertible Unsecured Notes (other than with respect to restrictions on transfer or for references to restrictive legends), by November 30, 2015. If the SEC does not approve registration of the exchange offer or an exchange offer would not be permitted by applicable laws, we have agreed to use our reasonable best efforts to prepare and file shelf registration statements to cover resales of the 2021 Convertible Unsecured Notes. If we fail to satisfy these obligations, we may be required to pay additional interest to holders of the 2021 Convertible Unsecured Notes under certain circumstances.

2017 CTPL Term Loan

In May 2013, CTPL entered into the 2017 CTPL Term Loan, which is being used to fund modifications to the Creole Trail Pipeline and for general business purposes. CTPL incurred $10.0 million of direct lender fees that were recorded as a debt discount. The 2017 CTPL Term Loan matures in 2017 when the full amount of the outstanding principal obligations must be repaid. CTPL’s loans may be repaid, in whole or in part, at any time without premium or penalty. As of December 31, 2014, CTPL had borrowed the full amount of $400.0 million available under the 2017 CTPL Term Loan.

Borrowings under the 2017 CTPL Term Loan 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 is 3.25%. Interest on LIBOR loans is due and payable at the end of each LIBOR period.

Under the terms and conditions of the 2017 CTPL Term Loan, all cash reserved to pay interest during construction is controlled by a collateral agent. These funds can only be released by the collateral agent upon satisfaction of certain terms and conditions, and are classified as restricted on our Consolidated Balance Sheets. CTPL is also required to pay annual fees to the administrative and collateral agents.

The 2017 CTPL Term Loan contains customary affirmative and negative covenants. The obligations of CTPL under the 2017 CTPL Term Loan are secured by a first priority lien on substantially all of the personal property of CTPL and all of the general partner and limited partner interests in CTPL.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Cheniere Partners has guaranteed (i) the obligations of CTPL under the 2017 CTPL Term Loan if the maturity of the CTPL loans is accelerated following the termination by Sabine Pass Liquefaction of a transportation precedent agreement in limited circumstances and (ii) the obligations of Cheniere Energy Investments, LLC (“Cheniere Investments”), Cheniere Partners’ wholly owned subsidiary, in connection with its obligations under an equity contribution agreement (a) to pay operating expenses of CTPL until CTPL receives revenues under a service agreement with Sabine Pass Liquefaction and (b) to fund interest payments on the CTPL loans after the funds in an interest reserve account have been exhausted.

Sabine Pass Liquefaction LC Agreement

In April 2014, Sabine Pass Liquefaction entered into a $325.0 million senior letter of credit and reimbursement agreement (the “Sabine Pass Liquefaction LC Agreement”) that it uses for the issuance of letters of credit for certain working capital requirements related to the Sabine Pass Liquefaction Project. Sabine Pass Liquefaction pays (a) a commitment fee in an amount equal to an annual rate of 0.75% of an amount equal to the unissued portion of letters of credit available pursuant to the Sabine Pass Liquefaction LC Agreement and (b) a letter of credit fee equal to an annual rate of 2.5% of the undrawn portion of all letters of credit issued under the Sabine Pass Liquefaction LC Agreement. If draws are made upon any letters of credit issued under the Sabine Pass Liquefaction LC Agreement, the amount of the draw will be deemed a loan issued to Sabine Pass Liquefaction. Sabine Pass Liquefaction is required to pay the full amount of this loan on or prior to the business day immediately succeeding the deemed issuance of the loan. These loans bear interest at a rate of 2.0% plus the base rate as defined in the Sabine Pass Liquefaction LC Agreement. As of December 31, 2014, Sabine Pass Liquefaction had issued letters of credit in an aggregate amount of $9.5 million and no draws had been made upon any letters of credit issued under the Sabine Pass Liquefaction LC Agreement.

Fair Value Disclosures

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



	December 31, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2016 Sabine Pass LNG Senior Notes, net of discount (1)	$	1,656,502	$	1,718,621	$	1,651,807	$	1,868,607
2020 Sabine Pass LNG Senior Notes (1)	420,000		428,400		420,000		432,600
2021 Sabine Pass Liquefaction Senior Notes, net of premium (1)	2,010,177		1,985,050		2,011,562		1,961,273
2022 Sabine Pass Liquefaction Senior Notes (1)	1,000,000		1,020,000		1,000,000		982,500
2023 Sabine Pass Liquefaction Senior Notes, net of premium (1)	1,507,089		1,476,947		1,000,000		935,000
2024 Sabine Pass Liquefaction Senior Notes (1)	2,000,000		1,970,000		—		—
2013 Liquefaction Credit Facilities (2)	—		—		100,000		100,000
2021 Convertible Unsecured Notes (3)	814,751		1,025,563		—		—
2017 CTPL Term Loan, net of discount (4)	397,565		400,000		392,904		400,000


(1)	The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on December 31, 2014 and 2013, as applicable.


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


(3)	The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.


(4)	The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and CTPL has the ability to call this debt at any time without penalty.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 10—INCOME TAXES

Income tax provision included in our reported net loss consisted of the following (in thousands):



	Year Ended December 31,
	2014		2013		2012
Current:
Federal	$	—	$	—	$	—
State	—		—		—
Foreign	4,143		4,082		145
Total current	4,143		4,082		145

Deferred:
Federal	—		—		—
State	—		—		—
Foreign	—		258		(141		)
Total deferred	—		258		(141		)
Total income tax provision	$	4,143	$	4,340	$	4

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:



	Year Ended December 31,
	2014		2013		2012
U.S. federal statutory tax rate	35.0	%	35.0	%	35.0	%
Non-controlling interest	(4.8	)%	(3.3	)%	(1.4	)%
State tax benefit	4.3	%	4.5	%	2.7	%
Uncertain tax position	(12.5	)%	—	%	—	%
Net impact of non-U.S. taxes	(2.0	)%	(0.8	)%	—	%
Valuation allowance	(19.8	)%	(34.3	)%	(33.2	)%
Other	(0.6	)%	(1.9	)%	(3.1	)%
Effective tax rate as reported	(0.4	)%	(0.8	)%	—	%

Significant components of our deferred tax assets and liabilities at December 31, 2014 and 2013 are as follows (in thousands):



	December 31,
	2014			2013
Deferred tax assets
Net operating loss carryforwards
Federal	$	637,919		$	608,631
State	136,917			111,624
Book deferred gain	77,182			77,182
Share-based compensation expense	28,432			24,089
Property, plant and equipment	29,483			27,260
Other	15,464			3,931
Total deferred tax assets	$	925,397		$	852,717

Deferred tax liabilities
Investment in limited partnership	$	(46,601	)	$	(109,884	)
Other	—			(142		)
Total deferred tax liabilities	$	(46,601	)	$	(110,026	)

Net deferred tax assets	878,796			742,691
Less: net deferred tax asset valuation allowance	(878,796		)	(742,691		)
Total net deferred tax asset	$	—		$	—

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

At December 31, 2014, we had federal and state net operating loss (“NOL”) carryforwards of approximately $3.5 billion. This excludes the NOL carryforwards related to unrecognized tax benefits and stock compensation windfalls that have not been recognized under GAAP. These NOL carryforwards will expire between 2028 and 2034.

Due to our history of NOLs, current year NOLs and significant risk factors related to our ability to generate taxable income, we have established a valuation allowance to fully offset our net deferred tax assets as of December 31, 2014 and 2013. We will continue to evaluate our ability to release the valuation allowance in the future. The change in the net deferred tax asset valuation allowance was $136.1 million for the year ended December 31, 2014.

Changes in the balance of unrecognized tax benefits are as follows (in thousands):



	Year Ended December 31,
	2014			2013
Balance at beginning of the year	$	19,484		$	19,773
Additions based on tax positions related to current year	85,932			—
Additions for tax positions of prior years	—			2,162
Reductions for tax positions of prior years	(925		)	(2,451		)
Settlements	—			—
Balance at end of the year	$	104,491		$	19,484

Our effective tax rate will not be affected if the unrecognized federal income tax benefits provided above were recognized. Currently, we do not recognize any accrued liabilities, interest and penalties associated with the unrecognized tax benefits provided above in our Consolidated Statements of Operations or our Consolidated Balance Sheets. Any applicable interest and penalties related to unrecognized tax benefits would be recorded to our income tax provision.

We experienced an ownership change within the provisions of Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. An analysis of the annual limitation on the utilization of our NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of our NOLs in full over the carryover period. We will continue to monitor trading activity in our shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize our existing tax NOL carryforwards.

We are subject to taxation in the U.S., United Kingdom, Chile, Singapore and various state jurisdictions. The federal tax returns for the years before 2010 remain open to examination for the purpose of determining the amount of remaining tax NOL and other carryforwards. The federal tax returns for the years 2011 through 2014 remain open for all purposes of examination by the IRS and other taxing authorities.

Accounting for share-based compensation provides that when settlement of a share based award contributes to an NOL carryforward, neither the associated excess tax benefit nor the credit to additional paid-in capital (“APIC”) should be recorded until the share-based award deduction reduces income tax payable. Upon utilization of the loss in future periods, a benefit of $130.5 million will be reflected in APIC.

NOTE 11—SHARE-BASED COMPENSATION

We have granted stock, restricted stock, phantom units and options to purchase common stock to employees, outside directors and a consultant under the Cheniere Energy, Inc. Amended and Restated 1997 Stock Option Plan (the “1997 Plan”), Amended and Restated 2003 Stock Incentive Plan, as amended (the “2003 Plan”), and 2011 Incentive Plan, as amended (the “2011 Plan”).

The 1997 Plan provides for the issuance of stock options to purchase up to 5.0 million shares of our common stock, all of which have been granted. Non-qualified stock options were granted to employees, contract service providers and outside directors. The 2003 Plan and 2011 Plan provide for the issuance of 21.0 million shares and 35.0 million shares, respectively, of our common stock that may be in the form of non-qualified stock options, incentive stock options, purchased stock, restricted (non-vested) stock, bonus (unrestricted) stock, stock appreciation rights, phantom units and other share-based performance awards deemed by the Compensation Committee of our Board of Directors (the “Compensation Committee”) to be consistent with the purposes of the 2003 Plan and 2011 Plan. As of December 31, 2014, all of the shares under the 2003 Plan have been granted and approximately 27 million shares, net of cancellations, have been granted under the 2011 Plan.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

For the years ended December 31, 2014, 2013 and 2012, the total share-based compensation expense, net of capitalization, recognized in our net loss was $102.0 million, $271.4 million and $58.7 million, respectively, and for the same periods we capitalized as part of the cost of capital assets $8.2 million, $12.5 million and $2.4 million, respectively. We did not recognize any cumulative adjustments in our compensation expense for the years ended December 31, 2014, 2013 and 2012.

The total unrecognized compensation cost at December 31, 2014 relating to non-vested share-based compensation arrangements granted under the 1997 Plan, 2003 Plan and 2011 Plan was $172.1 million, which is expected to be recognized over a weighted average period of 2.8 years.

During the year ended December 31, 2014, we recognized $10.8 million of share-based compensation expense related to the modification of long-term commercial bonus awards resulting from an employee termination.

We have disclosed the deferred tax benefit realized from share-based compensation exercised during the annual period in Note 10—Income Taxes. A valuation allowance equal to the deferred tax asset has been established due to the uncertainty of realizing the tax benefits related to this deferred tax asset.

Restricted Stock

Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the recipient terminates employment with the Company prior to the lapse of the restrictions. For the years ended December 31, 2014, 2013 and 2012, we issued 549,774 shares,18,860,000 shares and 10,293,000 shares, respectively, of restricted stock awards to our employees, executives, directors and a consultant. These awards vest based on service conditions (one, three or four-year service periods), performance conditions and/or market conditions. The amortization of the value of restricted stock grants is accounted for as a charge to compensation expense or capitalized, depending on the employee, with a corresponding increase to additional paid-in-capital over the requisite service period.

Grants of restricted stock to employees and non-employee directors that vest based on service and/or performance conditions are measured at the closing quoted market price of the Company’s common stock on the grant date. For restricted stock awards granted to non-employees that vest based on service and/or performance conditions, the Company records compensation cost equal to the fair value of the award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. In addition, compensation cost for unvested restricted stock awards to non-employees is adjusted quarterly for any changes in the Company’s stock price.

Grants of restricted stock to employees and non-employees based on market conditions are measured using valuations based on Monte Carlo simulations. There were no awards granted with market conditions in 2014 or 2012. For the awards granted in 2013 with market conditions, we used the following variables in our Monte Carlo simulations:


•	Expected Volatility 44% - 62%


•	Risk Free Rate 2.80% - 2.83%


•	Cost of Equity 16.50% - 16.60%

In July 2012, we met the criteria to determine the long-term commercial bonus pool that was established by the Compensation Committee in the 2011-2013 Bonus Plan in relation to Trains 1 and 2 of the Sabine Pass Liquefaction Project. In August 2012, the Compensation Committee approved a long-term commercial bonus pool, which consisted of approximately $60 million in cash awards and 10 million restricted shares of common stock to be issued under the 2011 Plan. The first restricted stock award installment vested in August 2012 when Sabine Pass Liquefaction issued its full notice to proceed (“NTP”) to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) under the lump sum turnkey contract Sabine Pass Liquefaction entered into with Bechtel for the engineering, procurement and construction of Trains 1 and 2 of the Sabine Pass Liquefaction Project. The restricted stock awards vest in five installments as follows:


•	35% when NTP is issued;


•	10% on the first anniversary of the issuance of NTP;


•	15% on the second anniversary of the issuance of NTP;


•	15% on the third anniversary of the issuance of NTP; and

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED


•	25% on the fourth anniversary of the issuance of NTP.

In general, employees must be employed at the time of each vesting to receive the awards or will otherwise forfeit such awards. Vesting and payment of the awards would accelerate in full upon (i) termination of employment by the Company without “Cause” or, solely in the case of executive officers, termination of employment by the employee for “Good Reason” (each as defined in the restricted stock award agreement), (ii) the employee’s death or disability, or (iii) the occurrence of a change of control.

On December 12, 2012, pursuant to the 2011-2013 Bonus Plan, the Compensation Committee approved a Long-Term Bonus Pool for 2012 for all employees of the Company consisting of a total of 18 million shares of restricted stock. The Long-Term Commercial Bonus Awards for Trains 3 and 4 of the Sabine Pass Liquefaction Project were granted to employees in February 2013 under the 2003 Plan and 2011 Plan. A portion of each employee’s Long-Term Commercial Bonus Award for Trains 3 and 4 of the Sabine Pass Liquefaction Project was granted as a milestone award (“Milestone Award”), with vesting of the Milestone Award conditional on certain performance milestones relating to financing and constructing Trains 3 and 4 of the Sabine Pass Liquefaction Project, and a portion was granted as a stock price award (“Stock Price Award”), with vesting of the Stock Price Award conditional on the achievement of minimum average Company stock price hurdles.

On May 22, 2013, the $25 stock price hurdle was achieved. Following certification by a subcommittee of the Compensation Committee, 50% of the Stock Price Awards vested. On December 6, 2013, the $35 stock price hurdle was achieved. Following certification by a subcommittee of the Compensation Committee, the remaining 50% of the Stock Price Awards vested.

On May 28, 2013, the first performance milestone was achieved when Sabine Pass Liquefaction completed the financing for, and issued notice to proceed with construction under, the lump sum turnkey contract that Sabine Pass Liquefaction entered into with Bechtel for the engineering, procurement and construction of Trains 3 and 4 of the Sabine Pass Liquefaction Project (the “EPC Contract (Trains 3 and 4)”). Following certification of the achievement of the performance milestone by a subcommittee of the Compensation Committee, 30% of the Milestone Awards vested.

On October 1, 2014, the second performance milestone was achieved upon Sabine Pass Liquefaction’s payment of 60% of the original contract price of the EPC Contract (Trains 3 and 4). Following certification of the achievement of the performance milestone by a subcommittee of the Compensation Committee, 20% of the Milestone Awards vested.

The remaining Milestone Awards will vest based on the achievement of the following performance milestones:


•	20% upon substantial completion, as defined in the EPC Contract (Trains 3 and 4), of Train 4 of the Sabine Pass Liquefaction Project; and


•	30% on the first anniversary of substantial completion of Train 4 of the Sabine Pass Liquefaction Project.

The table below provides a summary of the status of our restricted stock under the 2003 Plan and 2011 Plan as of December 31, 2014 (in thousands, except for per share information):



	Non-Vested Shares		Weighted Average Grant Date Fair Value Per Share
Non-vested at January 1, 2014	15,081		$	19.40
Granted	550		60.09
Vested	(4,428	)	18.99
Forfeited	(726	)	21.54
Non-vested at December 31, 2014	10,477		$	21.56

The weighted average grant date fair values per share of restricted stock granted during the years ended December 31, 2014, 2013 and 2012 were $60.09, $21.89 and $14.06, respectively. The total grant date fair value per share of shares vested during the years ended December 31, 2014, 2013 and 2012 were $18.99, $19.40 and $12.76, respectively.

Phantom Units

Phantom units are incentive based equity awards issued to employees over a vesting period that entitle the grantee to receive the cash equivalent to the value of a share of our common stock upon each vesting. Phantom units are not eligible to receive quarterly distributions. The Company records compensation cost equal to the fair value of the award at the measurement date,

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

which is determined to be the earlier of the performance commitment date or the service completion date. In addition, compensation cost for unvested phantom unit awards is adjusted quarterly for any changes in the Company’s stock price. During the year ended December 31, 2014, we granted approximately 79,000 phantom units to employees and recognized $0.2 million of share-based compensation related to these grants.

Stock Options

Stock options to employees are valued at the date of grant using a Black-Scholes valuation model and the cost is recognized over the option vesting period. We did not issue any options to purchase shares of our common stock and did not declare dividends on our common stock during the years ended December 31, 2014, 2013 and 2012.

The table below provides a summary of option activity under the 1997 Plan, 2003 Plan and 2011 Plan as of December 31, 2014:



	Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)				(in years)	(in thousands)
Outstanding at January 1, 2014	480		$	30.73	1.32	$	5,947
Granted	—		—
Exercised	(387	)	29.50
Forfeited or Expired	—		—
Outstanding at December 31, 2014	93		$	35.81	0.81	$	3,224
Exercisable at December 31, 2014	93		$	35.81	0.81	$	3,224

The weighted average grant-date fair value of options granted during each of the years ended December 31, 2014, 2013 and 2012 was zero. The total intrinsic value of options exercised during the years ended December 31, 2014, 2013 and 2012 was $11.9 million, $2.0 million and $0.7 million, respectively.

We received $10.8 million, $3.7 million and $0.8 million in the years ended December 31, 2014, 2013 and 2012, respectively, of proceeds from the exercise of stock options.

NOTE 12—EMPLOYEE BENEFIT PLAN

In 2005, we established a defined contribution plan (“401(k) Plan”). The 401(k) Plan allows eligible employees to contribute up to 100% of their compensation up to the IRS maximum. We match each employee’s salary deferrals (contributions) up to six percent of compensation and may make additional contributions at our discretion. Effective January 1, 2007, employees are immediately vested in the contributions made by us. Our contributions to the 401(k) Plan were $3.6 million, $2.3 million and $1.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. We have made no discretionary contributions to the 401(k) Plan to date.

NOTE 13—LEASES

During the years ended December 31, 2014, 2013 and 2012, we recognized rental expense for all operating leases of $19.1 million, $13.9 million and $12.9 million, respectively.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Future Annual Minimum Lease Payments

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



Years Ending December 31,	Operating Leases (2)
2015	$	35,912
2016	97,367
2017	109,500
2018	101,742
2019	101,109
Thereafter (1)	296,813
Total	$	742,443


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

(2)

Operating leases primarily relate to LNG vessel time charters, land site and tug leases. Lease payments for Sabine Pass LNG’s tug boat lease represent its lease payment obligation and do not take into account the payments Sabine Pass LNG will receive from third-party TUA customers that effectively offset $16.3 million, or two-thirds, of Sabine Pass LNG’s lease payment obligations, as discussed below.

Land Site Leases

We recognized $3.0 million, $2.7 million and $2.3 million of LNG terminal operating expense on our Consolidated Statements of Operations in 2014, 2013 and 2012, respectively, under the following land site leases:

In January 2005, Sabine Pass LNG exercised its options and entered into three land leases for the site of the Sabine Pass LNG terminal. The leases have an initial term of 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. In February 2005, two of the three leases were amended, thereby increasing the total acreage under lease to 853 acres. In July 2012, Sabine Pass LNG entered into an additional land lease, thereby increasing the total acreage under lease to 883 acres. The annual lease payments are adjusted for inflation every five years based on a consumer price index, as defined in the lease agreements.

In November 2011, Sabine Pass Liquefaction entered into a land lease of 80.7 acres to be used as the laydown area during the construction of the Sabine Pass Liquefaction Project. The lease has an initial term of 5 years, with options to renew for five 1-year extensions with similar terms as the initial term. In December 2011, Sabine Pass Liquefaction entered into a land lease of 80.6 acres to be used for the site of the Sabine Pass Liquefaction Project. The lease has an initial term of 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. The annual lease payment is adjusted for inflation every 5 years based on a consumer price index, as defined in the lease agreement.

In January 2013, Corpus Christi Liquefaction entered into a land lease of 110 acres to be used as the laydown area during the construction of the Corpus Christi Liquefaction Project. The lease has an initial term of one year, eleven months, with an option to renew for an additional period of four years, eleven months with similar terms as the initial term.

Tug Boat Agreements

In the second quarter of 2009, Sabine Pass Tug Services, LLC (“Tug Services”), Cheniere Partners’ wholly owned subsidiary, entered into a Marine Services Agreement (the “Tug Agreement”) for the use of tug boats and marine services for the Sabine Pass LNG terminal. The term of the Tug Agreement commenced in January 2008 for a period of 10 years, with an option to renew two additional, consecutive terms of 5 years each. We determined that the Tug Agreement contains a lease for the tugs specified in the Tug Agreement. In addition, we have concluded that the tug boat lease contained in the Tug Agreement is an operating lease, and as such, the equipment component of the Tug Agreement will be charged to expense over the term of the Tug Agreement as it becomes payable.

In the second quarter of 2009, Tug Services entered into a Tug Sharing Agreement with Sabine Pass LNG’s three TUA customers to provide their LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal and effectively

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

offset the cost of the tug boat lease. The Tug Sharing Agreement provides for each of our customers to pay Tug Services an annual service fee.

LNG Vessel Time Charters

In June 2013, Cheniere Marketing entered into three LNG vessel leases with subsidiaries of two ship owners, Dynagas, Ltd. (“Dynagas”) and Teekay LNG Operating LLC (“Teekay”), for the purpose of securing shipping capacity for its SPA with Sabine Pass Liquefaction. The leases have an initial term of 5 years with the option to renew the lease with Dynagas for a 2-year extension with similar terms as the initial term. In accordance with accounting literature on determining whether an arrangement contains a lease, we determined that the LNG vessel leases are operating leases and, as such, the equipment component of the LNG vessel leases is charged to expense over the term of the LNG vessel leases as it becomes payable.

Cheniere Marketing expects to receive delivery of the vessel leased from Dynagas in June 2015 and the vessels leased from Teekay in January 2016 and June 2016, respectively.

NOTE 14—COMMITMENTS AND CONTINGENCIES

LNG Terminal Commitments and Contingencies

Obligations under LNG TUAs

Sabine Pass LNG has entered into third-party TUAs with Total and Chevron to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG terminal.

Obligations under Bechtel EPC Contracts

Sabine Pass Liquefaction has entered into lump sum turnkey contracts for the engineering, procurement and construction (“EPC”) of Trains 1 and 2 (the “EPC Contract (Trains 1 and 2)”) and the EPC Contract of Trains 3 and 4 (the “EPC Contract (Trains 3 and 4)”) with Bechtel in November 2011 and December 2012, respectively.

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

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

In December 2013, Corpus Christi Liquefaction entered into lump sum turnkey contracts for the engineering, procurement and construction of Trains and related facilities for the Corpus Christi Liquefaction Project. The Corpus Christi Liquefaction stage 1 EPC contract (the “Stage 1 EPC Contract”) with Bechtel includes two Trains, two 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 tank and completion of the second berth. The contract price of 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. Corpus Christi Liquefaction has the right to terminate each of these EPC contracts for its convenience, in which case Bechtel will be paid costs reasonably incurred by Bechtel on account of such termination and demobilization. In addition, upon termination Bechtel will be paid the portion of the contract price for the work performed and a lump sum of $2.5 million if such EPC contract is terminated prior to issuance of the notice to proceed and up to $30.0 million depending on the termination date if such EPC contract is terminated after issuance of the notice to proceed.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Obligations under SPAs

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

Corpus Christi Liquefaction has entered into third-party SPAs which obligates Corpus Christi Liquefaction to purchase natural gas in sufficient quantities, liquefy the natural gas purchased, and deliver 438.7 million MMBtu per year of LNG to the customers’ vessels, subject to completion of regulatory approvals, securing adequate financing, reaching a final investment decision to construct the relevant infrastructure, and construction of the first Train at the Corpus Christi Liquefaction Project.

Obligations under Term Gas Supply Contracts

Sabine Pass Liquefaction has entered into index-based physical natural gas supply contracts to secure natural gas feedstock for the Sabine Pass Liquefaction Project. The terms of these contracts range from approximately one to seven years and commence upon the occurrence of conditions precedent, including the date of first commercial operation of specified Trains of the Sabine Pass Liquefaction Project. As of December 31, 2014, the forward notional natural gas buy position of Sabine Pass Liquefaction’s Term Gas Supply Derivatives was approximately 1,249.4 million MMBtu.

Restricted Net Assets

At December 31, 2014, our restricted net assets of consolidated subsidiaries were approximately $2,641 million.

Other Commitments

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position.

Legal Proceedings

During the second quarter of 2014, four lawsuits were filed in the Court of Chancery of the State of Delaware (the “Court”) against us and/or certain of our present and former officers and directors that challenge the manner in which abstentions were treated in connection with the stockholder vote on Amendment No. 1 to the Cheniere Energy, Inc. 2011 Incentive Plan (“Amendment No. 1”), pursuant to which, among other things, the number of shares of common stock available for issuance under the Cheniere Energy, Inc. 2011 Incentive Plan (the “2011 Plan”) was increased from 10 million to 35 million shares. The lawsuits contend that abstentions should have been counted as “no” votes in tabulating the outcome of the vote and that the stockholders did not approve Amendment No. 1 when abstentions are counted as such. The lawsuits further contend that portions of the Amended and Restated Bylaws of Cheniere Energy, Inc. adopted on April 3, 2014 are invalid and that certain disclosures relating to these matters made by us are misleading. The lawsuits assert claims for breach of contract and breach of fiduciary duty (both on a class and a derivative basis) and claims for unjust enrichment (on a derivative basis). The lawsuits seek, among other things, a declaration that the February 1, 2013 stockholder vote on Amendment No. 1 is void, disgorgement of all compensation distributed as a result of Amendment No. 1, voiding the awards made from the shares reserved pursuant to Amendment No. 1 and monetary damages. On June 16, 2014, we filed a verified application with the Court pursuant to 8 Del. C. § 205 (the “Section 205 Action”) in which we asked the Court to declare valid the issuance, pursuant to the 2011 Plan, of the 25 million additional shares of our common stock covered by Amendment No. 1, whether occurring in the past or the future.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

We have accrued our best estimate of probable loss in accrued liabilities on our Consolidated Balance Sheets. We estimate that the ultimate resolution of the matter could result in a total loss of up to approximately $43 million. As the approval process for the Stipulation and plaintiffs' fee award progresses, additional information could become known and we may be required to recognize additional general and administrative expense, and that amount could be material to our consolidated financial position, results of operations or cash flows.

NOTE 15—BUSINESS SEGMENT INFORMATION

We have two reportable segments: LNG terminal reporting segment and LNG and natural gas marketing reporting segment. We determine our reportable segments by identifying each segment 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 maker for purposes of resource allocation and performance assessment, and had discrete financial information. Substantially all of our revenues from external customers and long-lived assets are attributed to or located in the United States.

Our LNG terminal reporting segment consists of the Sabine Pass and Corpus Christi LNG terminals. We own and operate the Sabine Pass LNG terminal located on the Sabine Pass shipping channel in Louisiana through our ownership interest in and management agreements with Cheniere Partners. We own 100% of the general partner interest in Cheniere Partners and 80.1% of the common shares of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners. We are also developing a natural gas liquefaction facility near Corpus Christi, Texas.

Our LNG and natural gas marketing reporting segment consists of Cheniere Marketing, LLC (“Cheniere Marketing”) marketing LNG and natural gas on its own behalf and assisting Cheniere Investments in an effort to utilize the regasification capacity held at the Sabine Pass LNG terminal. Cheniere Marketing is developing a platform for LNG sales to international markets with professional staff based in the United States, United Kingdom, Singapore and Chile.

100

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table summarizes revenues (losses), loss from operations and total assets for each of our reporting segments (in thousands):



	Segments
	LNG Terminal			LNG & Natural Gas Marketing			Corporate and Other (1)			Total Consolidation
As of or for the Year Ended December 31, 2014
Revenues (losses) from external customers (2)	$	267,606		$	(1,285	)	$	1,633		$	267,954
Intersegment revenues (losses) (3) (4)	(779		)	41,908			(41,129		)	—
Depreciation expense	58,883			271			5,104			64,258
Loss from operations	(91,179		)	(12,993		)	(169,396		)	(273,568		)
Interest expense, net	(177,400		)	—			(3,836		)	(181,236		)
Loss before income taxes and non-controlling interest (5)	(480,366		)	(14,874		)	(192,494		)	(687,734		)
Share-based compensation	14,129			6,027			90,073			110,229
Goodwill	76,819			—			—			76,819
Total assets	10,580,612			567,460			1,425,611			12,573,683
Expenditures for additions to long-lived assets	2,684,045			1,888			161,882			2,847,815

As of or for the Year Ended December 31, 2013
Revenues from external customers (2)	$	265,409		$	242		$	1,562		$	267,213
Intersegment revenues (losses) (3) (4)	2,983			45,049			(48,032		)	—
Depreciation expense	58,099			941			2,169			61,209
Loss from operations	(121,698		)	(47,966		)	(159,322		)	(328,986		)
Interest expense, net	(182,003		)	—			3,603			(178,400		)
Loss before income taxes and non-controlling interest (5)	(350,734		)	(48,851		)	(154,838		)	(554,423		)
Share-based compensation	29,805			46,293			207,783			283,881
Goodwill	76,819			—			—			76,819
Total assets	8,663,795			62,327			947,115			9,673,237
Expenditures for additions to long-lived assets	3,222,454			39			9,778			3,232,271

As of or for the Year Ended December 31, 2012
Revenues (losses) from external customers (2)	$	265,900		$	(1,172	)	$	1,492		$	266,220
Intersegment revenues (losses) (3) (4)	8,137			5,354			(13,491		)	—
Depreciation expense	62,547			2,067			1,793			66,407
Income (loss) from operations	5,176			(35,988		)	(45,020		)	(75,832		)
Interest expense, net	(218,143		)	12			17,320			(200,811		)
Loss before income taxes and non-controlling interest (5)	(255,000		)	(36,022		)	(54,615		)	(345,637		)
Share-based compensation	7,539			11,485			42,023			61,047
Goodwill	76,819			—			—			76,819
Total assets	4,411,396			62,797			164,892			4,639,085
Expenditures for additions to long-lived assets	1,233,577			(374		)	1,512			1,234,715


(1)	Includes corporate activities, business development, oil and gas exploration, development and exploitation, strategic activities and certain intercompany eliminations. These activities have been included in the corporate and other column due to the lack of a material impact that these activities have on our Consolidated Financial Statements.


(2)	Substantially all of the LNG terminal revenues relate to regasification capacity reservation fee payments made by Total Gas & Power North America, Inc. and Chevron U.S.A. Inc. LNG and natural gas marketing and trading revenue consists primarily of the domestic marketing of natural gas imported into the Sabine Pass LNG terminal.


(3)	Intersegment revenues primarily related to our LNG terminal segment are from tug revenues from Cheniere Marketing. These LNG terminal segment intersegment revenues are eliminated with intersegment losses in our Consolidated Statements of Operations.

101

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(4)

Intersegment revenues (losses) related to our LNG and natural gas marketing segment are primarily a result of international revenue allocations using a cost plus transfer pricing methodology and from Cheniere Marketing’s tug costs. These LNG and natural gas marketing segment intersegment revenues (losses) are eliminated with intersegment revenues (losses) in our Consolidated Statements of Operations.


(5)	Items to reconcile loss from operations and loss before income taxes and non-controlling interest include consolidated other income (expense) amounts as presented on our Consolidated Statements of Operations primarily related to our LNG terminal segment.

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Year Ended December 31,
	2014		2013		2012
Cash paid during the year for interest, net of amounts capitalized and deferred	$	130,578	$	120,908	$	200,323
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities	129,842		154,517		99,751

NOTE 17—SUBSEQUENT EVENTS

Convertible Notes

On January 16, 2015, Cheniere CCH HoldCo II, LLC, our wholly owned direct subsidiary, entered into a note purchase agreement with EIG Management Company, LLC (“EIG”) to purchase $1.5 billion of convertible notes, which is scheduled to close once we reach a positive final investment decision on the Corpus Christi Liquefaction Project. The net proceeds would be used to fund a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project.

Contingent Interest Rate Derivatives

In February 2015, Cheniere Corpus Christi Holdings, LLC (“Cheniere Corpus Christi Holdings”) entered into contingent interest rate derivatives (“Contingent Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on upcoming debt facilities that will be used to pay for a portion of the costs of developing, constructing and placing into service the Corpus Christi Liquefaction Project. The Contingent Interest Rate Derivatives are conditional upon certain conditions including reaching a final investment decision to commence construction of the Corpus Christi Liquefaction Project. We will contemplate making this final investment decision based upon, among other things, entering into acceptable commercial arrangements, receiving regulatory authorizations and obtaining adequate financing to construct the facility. Upon reaching a final investment decision to commence construction of the Corpus Christi Liquefaction Project, we estimate that we will pay $32.1 million to $45.5 million related to contingency and syndication premiums. Cheniere Corpus Christi Holdings has the following Contingent Interest Rate Derivatives outstanding:



Initial Notional Amount	Maximum Notional Amount	Maturity	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
$20.1 million	$3.8 billion	85 months	2.48%	One-month LIBOR

102

CHENIERE ENERGY, INC. AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

QUARTERLY FINANCIAL DATA

(unaudited)

Quarterly Financial Data—(in thousands, except per share amounts)



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2014:
Revenues	$	67,550		$	67,645		$	66,807		$	65,952
Loss from operations	(47,612		)	(62,135		)	(61,358		)	(102,463		)
Net loss	(122,345		)	(280,710		)	(104,800		)	(184,022		)
Net loss attributable to common stockholders	(97,810		)	(201,928		)	(89,581		)	(158,613		)
Net loss per share attributable to common stockholders—basic and diluted (1)	(0.44		)	(0.90		)	(0.40		)	(0.70		)

Year ended December 31, 2013:
Revenues	$	65,906		$	67,177		$	67,710		$	66,420
Loss from operations	(67,454		)	(136,278		)	(45,876		)	(79,379		)
Net loss	(124,629		)	(163,904		)	(122,483		)	(147,747		)
Net loss attributable to common stockholders	(117,105		)	(154,764		)	(100,824		)	(135,229		)
Net loss per share attributable to common stockholders—basic and diluted (1)	(0.54		)	(0.71		)	(0.46		)	(0.61		)


(1)	The sum of the quarterly net loss per share—basic and diluted may not equal the full year amount as the computations of the weighted average common shares outstanding for basic and diluted shares outstanding for each quarter and the full year are performed independently.

103


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

None.


ITEM 9A.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Based on their evaluation as of the end of the fiscal year ended December 31, 2014, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (i) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (ii) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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

Management’s Report on Internal Control Over Financial Reporting

Our Management’s Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements on page 62 and is incorporated herein by reference.


ITEM 9B.	OTHER INFORMATION

Compliance Disclosure

Pursuant to Section 13(r) of the Exchange Act, if during the fiscal year ended December 31, 2014, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our Annual Report on Form 10-K as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012 (“ITRA”). During the fiscal year ended December 31, 2014, we did not engage in any transactions with Iran or with persons or entities related to Iran.

Blackstone CQP Holdco LP, an affiliate of The Blackstone Group L.P. (“Blackstone Group”), is a holder of approximately 29% of the outstanding equity interests of Cheniere Partners and has three representatives on the Board of Directors of Cheniere Partners’ general partner. Accordingly, Blackstone Group may be deemed an “affiliate” of Cheniere Partners, as that term is defined in Exchange Act Rule 12b-2. We have received notice from Blackstone that it may include in its Annual Report on Form 10-K for the fiscal year ended December 31, 2014 disclosures pursuant to ITRA regarding one of its portfolio companies that may be deemed to be an affiliate of Blackstone Group. Because of the broad definition of “affiliate” in Exchange Act Rule 12b-2, this portfolio company of Blackstone Group, through Blackstone Group’s ownership of Cheniere Partners, may also be deemed to be an affiliate of ours.

We have received notice from Blackstone Group that Travelport Limited (“Travelport”) has engaged in the following activities: as part of its global business in the travel industry, Travelport provides certain passenger travel-related GDS and airline IT services to Iran Air and airline IT services to Iran Air Tours. The gross revenues and net profits attributable to such activities by Travelport during the fiscal year ended December 31, 2014 have not been reported by Travelport. Blackstone Group has informed us that Travelport intends to continue these business activities with Iran Air and Iran Air Tours as such activities are either exempt from applicable sanctions prohibitions or specifically licensed by the Office of Foreign Assets Control.

104

In our Form 10-Q reports for the quarterly periods ended on March 31, 2014, June 30, 2014 and September 30, 2014, we disclosed, under “Item 5. Other Information—Compliance Disclosure” in each such report, as amended, activities as required by Section 13(r) of the Exchange Act as transactions or dealings with the government of Iran that have not been specifically authorized by a U.S. federal department or agency. Such disclosures are incorporated herein by reference.

PART III

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Items 10 through 14 of Part III of this Report is incorporated by reference from Cheniere’s definitive proxy statement, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2014.

105

PART IV


ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


(a)	Financial Statements, Schedules and Exhibits


(1)	Financial Statements—Cheniere Energy, Inc. and Subsidiaries:



Management’s Reports to the Stockholders of Cheniere Energy, Inc.	62
Reports of Independent Registered Public Accounting Firm—KPMG LLP	63
Report of Independent Registered Public Accounting Firm—Ernst & Young LLP	65
Consolidated Balance Sheets	66
Consolidated Statements of Operations	67
Consolidated Statements of Comprehensive Loss	68
Consolidated Statements of Stockholders’ Equity	69
Consolidated Statements of Cash Flows	70
Notes to Consolidated Financial Statements	71
Supplemental Information to Consolidated Financial Statements—Quarterly Financial Data	103


(2)	Financial Statement Schedules:



Schedule I—Condensed Financial Information of Registrant for the years ended December 31, 2014, 2013 and 2012	119


(3)	Exhibits:

Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:


•	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;


•	may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;


•	may apply standards of materiality that differ from those of a reasonable investor; and


•	were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.



Exhibit No.		Description
2.1		Amended and Restated Purchase and Sale Agreement, dated as of August 9, 2012, by and among Cheniere Energy Partners, L.P., Cheniere Pipeline Company, Grand Cheniere Pipeline, LLC and Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
3.1		Restated Certificate of Incorporation of the Company (Incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2004 (SEC File No. 001-16383), filed on August 10, 2004)

106



Exhibit No.		Description
3.2		Certificate of Amendment of Restated Certificate of Incorporation of the Company (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on February 8, 2005)
3.3		Certificate of Amendment of Restated Certificate of Incorporation of the Company (Incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-8 (SEC File No. 333-160017), filed on June 16, 2009)
3.4		Certificate of Amendment of Restated Certificate of Incorporation of the Company (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on June 7, 2012)
3.5		Certificate of Amendment of Restated Certificate of Incorporation of the Company (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on 8-K (SEC File No. 001-16383), filed on February 5, 2013)
3.6		Cheniere Energy, Inc. Amended and Restated Bylaws, dated April 3, 2014 (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on April 9, 2014)
4.1		Specimen Common Stock Certificate of the Company (Incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-10905), filed on August 27, 1996)
4.2		Indenture, dated as of November 9, 2006, by and among Sabine Pass LNG, L.P., as issuer, the guarantors as defined therein and The Bank of New York, as trustee (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
4.3		Form of 7.50% Senior Secured Note due 2016 (Included as Exhibit A1 to Exhibit 4.2 above)
4.4		Indenture, dated as of October 16, 2012, by and among Sabine Pass LNG, L.P., the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to Sabine Pass LNG L.P.’s Current Report on Form 8-K (SEC File No. 001-138916), filed on October 19, 2012)
4.5		Form of 6.5% Senior Secured Note due 2020 (Included as Exhibit A1 to Exhibit 4.4 above)
4.6		Indenture, dated as of February 1, 2013, by and among Sabine Pass Liquefaction, LLC, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33363), filed on February 4, 2013)
4.7		Form of 5.625% Senior Secured Note due 2021 (Included as Exhibit A-1 to Exhibit 4.6 above)
4.8		First Supplemental Indenture, dated as of April 16, 2013, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 1-33366), filed on April 16, 2013)
4.9		Second Supplemental Indenture, dated as of April 16, 2013, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 1-33366), filed on April 16, 2013)
4.10		Form of 5.625% Senior Secured Note due 2023 (Included as Exhibit A-1 to Exhibit 4.9 above)
4.11		Third Supplemental Indenture, dated as of November 25, 2013, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 1-33366), filed on November 25, 2013)
4.12		Form of 6.25% Senior Secured Note due 2022 (Included as Exhibit A-1 to Exhibit 4.11 above)
4.13		Fourth Supplemental Indenture, dated as of May 20, 2014, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on May 22, 2014)
4.14		Form of 5.750% Senior Secured Note due 2024 (Incorporated by reference as Exhibit A-1 to Exhibit 4.13 above)
4.15		Fifth Supplemental Indenture, dated as of May 20, 2014, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on May 22, 2014)
4.16		Form of 5.625% Senior Secured Note due 2023 (Included as Exhibit A-1 to Exhibit 4.15 above)
4.17		Indenture, dated as of November 28, 2014, by and between Cheniere Energy, Inc., as Issuer, and The Bank of New York Mellon, as Trustee (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 2, 2014)

107



Exhibit No.		Description
4.18		Form of 4.875% Unsecured PIK Convertible Note due 2021 (Included as Exhibit A to Exhibit 4.17 above)
10.1		LNG Terminal Use Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.2		Amendment of LNG Terminal Use Agreement, dated January 24, 2005, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.40 to the Company’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 10, 2005)
10.3		Amendment of LNG Terminal Use Agreement, dated June 15, 2010, by and between Total Gas & Power North America, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 6, 2010)
10.4		Omnibus Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.5		Parent Guarantee, dated as of November 5, 2004, by Total S.A. in favor of Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001 16383), filed on November 15, 2004)
10.6		Letter Agreement, dated September 11, 2012, between Total Gas & Power North America, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.7		LNG Terminal Use Agreement, dated November 8, 2004, between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.8		Amendment to LNG Terminal Use Agreement, dated December 1, 2005, by and between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.28 to Sabine Pass LNG, L.P.’s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on November 22, 2006)
10.9		Amendment of LNG Terminal Use Agreement, dated June 16, 2010, by and between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 6, 2010)
10.10		Omnibus Agreement, dated November 8, 2004, between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.11		Guaranty Agreement, dated as of December 15, 2004, from ChevronTexaco Corporation to Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.12 to Sabine Pass LNG, L.P.’s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on November 22, 2006)
10.12		Second Amended and Restated Terminal Use Agreement, dated as of July 31, 2012, between Sabine Pass LNG, L.P. and Sabine Pass Liquefaction, LLC (Incorporated by reference to Exhibit 10.1 to Sabine Pass LNG, L.P.’s Current Report on Form 8-K (SEC File No. 333-138916), filed on August 6, 2012)
10.13		Letter Agreement, dated May 28, 2013, by and between Sabine Pass LNG, L.P. and Sabine Pass Liquefaction, LLC (Incorporated by reference to Exhibit 10.1 to Sabine Pass LNG, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 333-138916), filed on August 2, 2013)
10.14		Guarantee Agreement, dated as of July 31, 2012, by Cheniere Partners in favor of Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.2 to Sabine Pass LNG, L.P.’s Current Report on Form 8-K (SEC File No. 333-138916), filed on August 6, 2012)
10.15†		Form of Cancellation and Grant of Non-Qualified Stock Options (three-year vesting) under the Cheniere Energy, Inc. 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 2, 2005)
10.16†		Cheniere Energy, Inc. Amended and Restated 1997 Stock Option Plan (Incorporated by reference to Exhibit 10.14 to the Company’s Quarterly on Form 10-Q (SEC File No. 000-16383), filed on November 4, 2005)
10.17†		Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 4, 2005)
10.18†		Addendum to Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 (SEC File No. 001-16383), filed on March 13, 2006)

108



Exhibit No.		Description
10.19†		Amendment No. 1 to Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 4.10 to the Company’s Registration Statement on Form S-8 (SEC File No. 333-134886), filed on June 9, 2006)
10.20†		Amendment No. 2 to Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.84 to the Company’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2007)
10.21†		Amendment No. 3 to Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit A to the Company’s Proxy Statement (SEC File No. 001-16383), filed on April 23, 2008)
10.22†		Amendment No. 4 to the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on June 15, 2009)
10.23†		Form of Non-Qualified Stock Option Grant for Employees and Consultants (three-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on January 11, 2007)
10.24†		Form of Non-Qualified Stock Option Grant for Employees and Consultants (four-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on January 11, 2007)
10.25†		Form of Restricted Stock Grant (three-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on January 11, 2007)
10.26†		Form of Restricted Stock Grant (four-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on January 11, 2007)
10.27†		Form of Amendment to Non-Qualified Stock Option Grant under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 7, 2008)
10.28†		Form of Restricted Stock Grant under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (US - New Hire) (Incorporated by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.29†		Form of Restricted Stock Grant under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (UK - New Hire) (Incorporated by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.30†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant (Train 3 and Train 4) under the 2003 Stock Incentive Plan (US Executive Form) (Incorporated by reference to Exhibit 10.97 to the Company’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 22, 2013)
10.31†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant (Train 3 and Train 4) under the 2003 Stock Incentive Plan (US Non-Executive Form) (Incorporated by reference to Exhibit 10.99 to the Company’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 22, 2013)
10.32†		Form of Amendment to Non-Qualified Stock Option Grant (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on April 3, 2007)
10.33†		Cheniere Energy, Inc. 2008 Change of Control Cash Payment Plan (Incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 14, 2008)
10.34†		Form of Change of Control Agreement (Incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 14, 2008)
10.35†		Form of Release and Separation Agreement (Incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 14, 2008)
10.36†		Form of Indemnification Agreement for directors of Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 19, 2008)

109



Exhibit No.		Description
10.37†		Indefinite Term Employment Agreement, dated February 20, 2006, between Cheniere International, Inc. and Jean Abiteboul; Letter Agreement, dated February 23, 2006, between Cheniere Energy, Inc. and Jean Abiteboul; Amendment to a Contract of Employment, dated March 20, 2007, between Cheniere LNG Services SARL and Jean Abiteboul; and Amendment to Indefinite Term Contract of Employment, effective January 16, 2008, between Cheniere LNG Services and Jean Abiteboul (Incorporated by reference to Exhibit 10.94 to the Company’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2009)
10.38†		Second Amendment to Contract of Employment, dated effective April 30, 2012, by and between Jean Abiteboul and Cheniere LNG Services, SARL (Incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on April 27, 2012)
10.39†		Form of Indemnification Agreement for officers of Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on April 6, 2009)
10.40†		Form of Long-Term Incentive Award - Restricted Stock Grant (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on January 10, 2011)
10.41†		Cheniere Energy, Inc. 2011 Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on June 22, 2011)
10.42†		Amendment No. 1 to the Cheniere Energy, Inc. 2011 Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on February 5, 2013)
10.43†		Cheniere Energy, Inc. 2011 - 2013 Bonus Plan (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed March 8, 2011)
10.44†		Form of Restricted Stock Grant under the Cheniere Energy, Inc. 2011 Incentive Plan (US - New Hire) (Incorporated by reference to Exhibit 10.13 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.45†		Form of Restricted Stock Grant under the Cheniere Energy, Inc. 2011 Incentive Plan (UK - New Hire) (Incorporated by reference to Exhibit 10.14 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.46†		Form of 2011 - 2013 Bonus Plan Long-Term Commercial Cash Award (US Form) (Incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.47†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant under the 2011 Incentive Plan (US Form) (Incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.48†		Form of 2011 - 2013 Bonus Plan Long-Term Commercial Cash Award (UK - Executive Form) (Incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.49†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant under the 2011 Incentive Plan (UK - Executive) (Incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.50†		Form of 2011 - 2013 Bonus Plan Long-Term Commercial Cash Award (UK Form) (Incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.51†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant under the 2011 Incentive Plan (UK Form) (Incorporated by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.52†		Form of 2011 - 2013 Bonus Plan Long-Term Commercial Cash Award (US - Consultant/Independent Contractor) (Incorporated by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.53†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant under the 2011 Incentive Plan (US - Consultant/Independent Contractor) (Incorporated by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.54†		Form of 2011 - 2013 Bonus Plan Long-Term Commercial Cash Award (US - Executive Form) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)

110



Exhibit No.		Description
10.55†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant under the 2011 Incentive Plan (US - Executive Form) (Incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 10, 2012)
10.56†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant (Train 3 and Train 4) under the 2011 Incentive Plan (US Executive Form) (Incorporated by reference to Exhibit 10.96 to the Company’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 22, 2013)
10.57†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant (Train 3 and Train 4) under the 2011 Incentive Plan (US Non-Executive Form) (Incorporated by reference to Exhibit 10.98 to the Company’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 22, 2013)
10.58†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant (Train 3 and Train 4) under the 2011 Incentive Plan (UK Executive Form) (Incorporated by reference to Exhibit 10.100 to the Company’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 22, 2013)
10.59†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant (Train 3 and Train 4) under the 2011 Incentive Plan (UK Non-Executive Form) (Incorporated by reference to Exhibit 10.101 to the Company’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 22, 2013)
10.60†		Form of 2011 - 2013 Bonus Plan Restricted Stock Grant (Train 3 and Train 4) under the 2011 Incentive Plan (US Consultant Form) (Incorporated by reference to Exhibit 10.102 to the Company’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 22, 2013)
10.61†		Meg Gentle’s Assignment Letter, dated July 30, 2013 (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on July 30, 2013)
10.62†		Termination Agreement and Release, dated March 7, 2014, between H. Davis Thames and Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 1, 2014)
10.63		Collateral Trust Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New York, as collateral trustee, Sabine Pass LNG-GP, Inc. and Sabine Pass LNG-LP, LLC (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.64		Amended and Restated Parity Lien Security Agreement, dated November 9, 2006, by and between Sabine Pass LNG, L.P. and The Bank of New York, as collateral trustee (Incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.65		Third Amended and Restated Multiple Indebtedness Mortgage, Assignment of Rents and Leases and Security Agreement, dated November 9, 2006, between Sabine Pass LNG, L.P. to and for the benefit of The Bank of New York, as collateral trustee (Incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.66		Amended and Restated Parity Lien Pledge Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., Sabine Pass LNG-GP, Inc., Sabine Pass LNG-LP, LLC and The Bank of New York, as collateral trustee (Incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.67		Security Deposit Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New York, as collateral trustee, and The Bank of New York, as depositary agent (Incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.68		Amended and Restated Common Terms Agreement, dated as of May 28, 2013, among Sabine Pass Liquefaction, LLC, as borrower, the Secured Debt Holder Group Representatives, Secured Hedge Representatives and Secured Gas Hedge Representatives from time to time party thereto, and Société Générale, as the common security trustee and intercreditor agent (Incorporated by reference to Exhibit 10.5 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)
10.69		KEXIM Direct Facility Agreement, dated as of May 28, 2013, among Sabine Pass Liquefaction, LLC, as borrower, KEB NY Financial Corp., as the KEXIM Facility Agent, Société Générale, as the common security trustee, and The Export-Import Bank of Korea, as the KEXIM Direct Facility Lender and as the Joint Lead Arranger (Incorporated by reference to Exhibit 10.2 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)

111



Exhibit No.		Description
10.70		KEXIM Covered Facility Agreement, dated as of May 28, 2013, among Sabine Pass Liquefaction, LLC, as borrower, KEB NY Financial Corp., as the KEXIM Facility Agent, Société Générale, as the common security trustee, The Export-Import Bank of Korea and the other lenders from time to time party thereto (Incorporated by reference to Exhibit 10.3 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)
10.71		KSURE Covered Facility Agreement, dated as of May 28, 2013, among Sabine Pass Liquefaction, LLC, as borrower, The Korea Development Bank, New York Branch, as the KSURE Covered Facility Agent, Société Générale, as the common security trustee, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.4 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)
10.72		Credit Agreement, dated as of May 28, 2013, among Cheniere Creole Trail Pipeline, L.P., as borrower, the lenders party thereto from time to time, Morgan Stanley Senior Funding, Inc., as administrative agent, The Bank of New York Mellon, as collateral agent, and The Bank of New York Mellon, as depositary bank (Incorporated by reference to Exhibit 10.6 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)
10.73		Amended and Restated Credit Agreement (Term Loan A), dated as of May 28, 2013, among Sabine Pass Liquefaction, LLC, as borrower, Société Générale, as the commercial banks facility agent and common security trustee, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 29, 2013)
10.74		Senior Letter of Credit and Reimbursement Agreement, dated as of April 21, 2014, among Sabine Pass Liquefaction, LLC, as Borrower, The Bank of Nova Scotia, as Senior Issuing Bank and Senior LC Facility Administrative Agent, Société Générale, as Common Security Trustee, and the lenders named therein, as Senior LC Lenders (Incorporated by reference to Exhibit 10.1 to Sabine Pass Liquefaction, LLC’s Current Report on Form 8-K (SEC File No. 333-192373), filed on April 25, 2014)
10.75		Amended and Restated Subscription Agreement, dated as of November 26, 2014, by and among Cheniere Energy, Inc., RRJ Capital II Ltd, Baytree Investments (Mauritius) Pte Ltd and Seatown Lionfish Pte. Ltd. relating to convertible PIK notes of Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 2, 2014)
10.76		Master Ex-Ship LNG Sales Agreement, dated April 26, 2007, between Cheniere Marketing, Inc. and Gaz de France International Trading S.A.S., including Letter Agreement, dated April 26, 2007, and Specific Order No. 1, dated April 26, 2007 (Incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 9, 2007)
10.77		GDF Transatlantic Option Agreement, dated April 26, 2007, between Cheniere Marketing, Inc. and Gaz de France International Trading S.A.S. (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 9, 2007)
10.78		LNG Lease Agreement, dated June 24, 2008, between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 11, 2008)
10.79		LNG Lease Agreement, dated September 30, 2011, by and between Cheniere Marketing, LLC and Cheniere Energy Investments, LLC (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 7, 2011)
10.80		Cooperative Endeavor Agreement & Payment in Lieu of Tax Agreement, dated October 23, 2007, by and between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2007)
10.81		Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on November 14, 2011)

112



Exhibit No.		Description
10.82		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0001 EPC Terms and Conditions, dated May 1, 2012, (ii) the Change Order CO-0002 Heavies Removal Unit, dated May 23, 2012, (iii) the Change Order CO-0003 LNTP, dated June 6, 2012, (iv) the Change Order CO-0004 Addition of Inlet Air Humidification, dated July 10, 2012, (v) the Change Order CO-0005 Replace Natural Gas Generators with Diesel Generators, dated July 10, 2012, (vi) the Change Order CO-0006 Flange Reduction and Valve Positioners, dated June 20, 2012, and (vii) the Change Order CO-0007 Relocation of Temporary Facilities, Power Poles Relocation Reimbursement, and Duck Blind Road Improvement Reimbursement, dated July 13, 2012 (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on August 3, 2012)
10.83		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0008 Delay in Full Placement of Insurance, dated July 27, 2012, (ii) the Change Order CO-0009 HAZOP Action Items, dated July 31, 2012, (iii) the Change Order CO-00010 Fuel Provisional Sum, dated August 8, 2012, (iv) the Change Order CO-00011 Currency Provisional Sum, dated August 8, 2012, (v) the Change Order CO-00012 Delay in NTP, dated August 8, 2012, and (vi) the Change Order CO-00013 Early EPC Work Credit, dated August 29, 2012 (Incorporated by reference to Exhibit 10.2 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.84		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00014 Bundle of Changes, dated September 5, 2012, (ii) the Change Order CO-00015 Static Mixer, Air Cooler Walkways, etc., dated November 8, 2012, (iii) the Change Order CO-0016 Delay in Full Placement of Insurance, dated October 29, 2012, (iv) the Change Order CO-00017 Condensate Header, dated December 3, 2012 and (v) the Change Order CO-00018 Increase in Power Requirements, dated January 17, 2013 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.26 to Cheniere Partners’ Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 22, 2013)
10.85		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00019 Delete Tank 6 Scope of Work, dated February 27, 2013 and (ii) the Change Order CO-00020 Modification to Builder’s Risk Insurance Sum Insured Value, dated March 14, 2013 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.2 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on May 3, 2013)
10.86		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00021 Increase to Insurance Provisional Sum, dated April 17, 2013, (ii) the Change Order CO-00022 Removal of LNG Static Mixer Scope, dated May 8, 2013, (iii) the Change Order CO-00023 Revised LNG Rundown Line, dated May 30, 2013, (iv) the Change Order CO-00024 Reroute Condensate Header, Substation HVAC Stacks, Inlet Metering Station Pile Driving, dated June 11, 2013 and (v) the Change Order CO-00025 Feed Gas Connection Modifications, dated June 11, 2013 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.45 to Cheniere Energy Partners LP Holdings, LLC’s Registration Statement on Form S-1 (SEC File No. 333-191298), filed on October 18, 2013)
10.87		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00026 Bundle of Changes, dated June 28, 2013, (ii) the Change Order CO-00027 16” Water Pumps, dated July 12, 2013, (iii) the Change Order CO-00028 HRU Operability, dated July 26, 2013, (iv) the Change Order CO-00029 Belleville Washers, dated August 14, 2013 and (v) the Change Order CO-00030 Soils Preparation Provisional Sum Transfer dated August 29, 2013 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 8, 2013)

113



Exhibit No.		Description
10.88		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00031 LNG Intank Pump Replacement Scope Reduction/OSBL Additional Piling for the Cathodic Protection Rectifier Platform and Drum Storage Shelter dated October 15, 2013 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.35 to Sabine Pass Liquefaction, LLC’s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on January 28, 2014)
10.89		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00032 Intra-Plant Feed Gas Header and Jefferson Davis Electrical Distribution, dated January 9, 2014, (ii) the Change Order CO-00033 Revised EPC Agreement Attachments S & T, dated March 24, 2014 and (iii) the Change Order CO-00034 Greenfield/Brownfield Demarcation Adjustment, dated February 19, 2014 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 1, 2014)
10.90		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00035 Resolution of FERC Open Items, Additional FERC Support Hours and Greenfield/Brownfield Milestone Adjustment, dated May 9, 2014 (Incorporated by reference to Exhibit 10.3 to Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on July 31, 2014)
10.91		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00036 Future Tie-Ins and Jeff Davis Invoices, dated July 9, 2014 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment) (Incorporated by reference to Exhibit 10.23 to Sabine Pass Liquefaction, LLC’s Registration on Form S-4 (SEC File No. 333-198358), filed on August 26, 2014)
10.92		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00037 Performance and Attendance Bonus (PAB) Incentive Program Provisional Sum, dated October 31, 2014 and (ii) the Change Order CO-00038 Control Room Modifications and Miscellaneous Items, dated January 6, 2015 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment) (Incorporated by reference to Exhibit 10.26 to Sabine Pass Liquefaction LLC’s Annual Report on Form 10-K (SEC File No. 333-192373), filed on February 19, 2015)
10.93		Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated December 20, 2012, by and between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to the SEC’s grant of a confidential treatment request.) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on December 27, 2012)
10.94		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0001 Electrical Station HVAC Stacks, dated May 29, 2013, (ii) the Change Order CO-0002 Revised LNG Rundown Lines, dated May 30, 2013, (iii) the Change Order CO-0003 Currency Provisional Sum Closure, dated May 29, 2013 and (iv) the Change Order CO-0004 Fuel Provisional Sum Closure, dated June 4, 2013 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.48 to Cheniere Energy Partners LP Holdings, LLC’s Registration Statement on Form S-1 (SEC File No. 333-191298), filed on October 18, 2013)

114



Exhibit No.		Description
10.95		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0005 Credit to EPC Contract Value for TSA Work, dated June 24, 2013, (ii) the Change Order CO-0006 HRU Operability with Lean Gas & Controls Upgrade and Ultrasonic Meter Configuration and Calibration, dated July 26, 2013, (iii) the Change Order CO-0007 Additional Belleville Washers, dated August 15, 2013, (iv) the Change Order CO-0008 GTG Switchgear Arrangement/Upgrade Fuel Gas Heater System, dated August 26, 2013, and (iv) the Change Order CO-0009 Soils Preparation Provisional Sum Transfer and Closure, dated August 26, 2013 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.49 to Cheniere Energy Partners LP Holdings, LLC’s Registration Statement on Form S-1 (SEC File No. 333-191298), filed on October 18, 2013)
10.96		Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 2 Liquefaction Facility, dated December 6, 2013, by and between Corpus Christi Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 10, 2013)
10.97		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00010 Insurance Provisional Sum Adjustment, dated January 23, 2014, (ii) the Change Order CO-00011 Additional Stage 2 GTGs, dated January 23, 2014, (iii) the Change Order CO-0012 Lien and Claim Waiver Modification, dated March 24, 2014 and (iv) the Change Order CO-00013 Revised Stage 2 EPC Agreement Attachments S&T, dated March 24, 2014 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.2 to Sabine Pass Liquefaction, LLC’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on May 1, 2014)
10.98		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00014 Additional 13.8kv Circuit Breakers and Miscellaneous Items, dated July 14, 2014 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment) (Incorporated by reference to Exhibit 10.28 to Sabine Pass Liquefaction, LLC’s Registration on Form S-4 (SEC File No. 333-198358), filed on August 26, 2014)
10.99		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00015 Performance and Attendance Bonus (PAB) Incentive Program Provisional Sum, dated October 31, 2014 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment) (Incorporated by reference to Exhibit 10.32 to Sabine Pass Liquefaction LLC’s Annual Report on Form 10-K (SEC File No. 333-192373), filed on February 19, 2015)
10.100		Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated December 6, 2013, by and between Corpus Christi Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 10, 2013)
10.101		LNG Sale and Purchase Agreement (FOB), dated November 21, 2011, between Sabine Pass Liquefaction, LLC (Seller) and Gas Natural Aprovisionamientos SDG S.A. (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on November 21, 2011)
10.102		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated April 3, 2013, between Sabine Pass Liquefaction, LLC (Seller) and Gas Natural Aprovisionamientos SDG S.A. (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on May 3, 2013)
10.103		LNG Sale and Purchase Agreement (FOB), dated December 11, 2011, between Sabine Pass Liquefaction, LLC (Seller) and GAIL (India) Limited (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on December 12, 2011)

115



Exhibit No.		Description
10.104		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between Sabine Pass Liquefaction, LLC (Seller) and GAIL (India) Limited (Buyer) (Incorporated by reference to Exhibit 10.18 to Cheniere Partners’ Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 22, 2013)
10.105		Amended and Restated LNG Sale and Purchase Agreement (FOB), dated January 25, 2012, between Sabine Pass Liquefaction, LLC (Seller) and BG Gulf Coast LNG, LLC (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on January 26, 2012)
10.106		LNG Sale and Purchase Agreement (FOB), dated January 30, 2012, between Sabine Pass Liquefaction, LLC (Seller) and Korea Gas Corporation (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on January 30, 2012)
10.107		Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between Sabine Pass Liquefaction, LLC (Seller) and Korea Gas Corporation (Buyer) (Incorporated by reference to Exhibit 10.19 to Cheniere Partners’ Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 22, 2013)
10.108		LNG Sale and Purchase Agreement (FOB), dated December 14, 2012, between Sabine Pass Liquefaction, LLC (Seller) and Total Gas & Power North America, Inc. (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on December 17, 2012)
10.109		LNG Sale and Purchase Agreement (FOB), dated March 22, 2013, between Sabine Pass Liquefaction, LLC (Seller) and Centrica plc (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on March 25, 2013)
10.110		LNG Sale and Purchase Agreement (FOB), dated December 4, 2013, between Corpus Christi Liquefaction, LLC (Seller) and PT Pertamina (Persero) (Buyer) (Incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 5, 2013)
10.111		Omnibus Agreement, dated December 4, 2013, among Cheniere Energy, Inc., Corpus Christi Liquefaction, LLC and PT Pertamina (Persero) (Incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 5, 2013)
10.112		LNG Sale and Purchase Agreement (FOB), dated April 1, 2014, between Corpus Christi Liquefaction, LLC (Seller) and Endesa Generación, S.A. (Buyer) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on April 2, 2014)
10.113		LNG Sale and Purchase Agreement (FOB), dated April 7, 2014, between Corpus Christi Liquefaction, LLC (Seller) and Endesa S.A. (Buyer) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on April 8, 2014)
10.114		Assignment and Amendment Agreement, dated April 7, 2014, among Endesa Generación S.A., Endesa S.A. and Corpus Christi Liquefaction, LLC. (Incorporated by reference to Exhibit 10.3 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 1, 2014)
10.115		LNG Sale and Purchase Agreement (FOB), dated May 30, 2014, between Corpus Christi Liquefaction, LLC (Seller) and Iberdrola, S.A. (Buyer) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on May 30, 2014)
10.116		LNG Sale and Purchase Agreement (FOB), dated June 2, 2014, between Corpus Christi Liquefaction, LLC (Seller) and Gas Natural Fenosa LNG SL (Buyer) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on June 2, 2014)
10.117		LNG Sale and Purchase Agreement (FOB), dated June 30, 2014, between Corpus Christi Liquefaction, LLC (Seller) and Woodside Energy Trading Singapore Pte Ltd (Buyer) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on June 30, 2014)
10.118		LNG Sale and Purchase Agreement (FOB), dated July 1, 2014, between Corpus Christi Liquefaction, LLC (Seller) and PT Pertamina (Persero) (Buyer) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on July 1, 2014)
10.119		LNG Sale and Purchase Agreement (FOB), dated July 17, 2014, between Corpus Christi Liquefaction, LLC (Seller) and Électricité de France, S.A. (Buyer) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on July 17, 2014)
10.120		Amended and Restated LNG Sale and Purchase Agreement (FOB), dated August 5, 2014, between Sabine Pass Liquefaction, LLC (Seller) and Cheniere Marketing, LLC (Buyer) (Incorporated by reference to Exhibit 10.1 to Sabine Pass Liquefaction, LLC’s Current Report on Form 8-K (SEC File No. 333-192373), filed on August 11, 2014)

116



Exhibit No.		Description
10.121		LNG Sale and Purchase Agreement (FOB), dated December 18, 2014, between Corpus Christi Liquefaction, LLC (Seller) and EDP Energias de Portugal S.A. (Buyer) (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 18, 2014)
10.122		Unit Purchase Agreement, dated May 14, 2012, by and among Cheniere Energy Partners, L.P., Cheniere Energy, Inc. and Blackstone CQP Holdco LP (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.123		Class B Unit Purchase Agreement, dated as of May 14, 2012, by and between Cheniere Energy Partners, L.P. and Cheniere LNG Terminals, LLC (Incorporated by reference to Exhibit 10.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.124		First Amendment to Class B Unit Purchase Agreement, dated as of August 9, 2012, by and between Cheniere Energy Partners, L.P. and Cheniere Class B Units Holdings, LLC (Incorporated by reference to Exhibit 10.3 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
10.125		Subscription Agreement, dated May 14, 2012, by and between Cheniere Energy Partners, L.P. and Cheniere LNG Terminals, LLC (Incorporated by reference to Exhibit 10.4 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.126		Letter Agreement, dated as of August 9, 2012, among Cheniere Energy, Inc., Cheniere Energy Partners, L.P. and Blackstone CQP Holdco LP (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
10.127		Investors’ and Registration Rights Agreement, dated as of July 31, 2012, by and among Cheniere Energy, Inc., Cheniere Energy Partners, L.P., Cheniere Energy Partners GP, LLC, Blackstone CQP Holdco LP and the other investors party thereto from time to time (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on 8-K (SEC File No. 001-33366), filed on August 6, 2012)
10.128		Third Amended and Restated Agreement of Limited Partnership of Cheniere Energy Partners, L.P., dated August 9, 2012 (Incorporated by reference to Exhibit 3.1 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
10.129		Amended and Restated Limited Liability Company Agreement of Cheniere Energy Partners LP Holdings, LLC, dated December 13, 2013 (Incorporated by reference to Exhibit 3.1 to Cheniere Energy Partners LP Holdings, LLC’s Current Report on Form 8-K (SEC File No. 001-36234), filed on December 18, 2013)
10.130		Amended and Restated Limited Liability Company Agreement of Cheniere GP Holding Company, LLC, dated December 13, 2013 (Incorporated by reference to Exhibit 10.3 to Cheniere Energy Partners LP Holdings, LLC’s Current Report on Form 8-K (SEC File No. 001-36234), filed on December 18, 2013)
10.131		Terms and Conditions of Employment Agreement between Cheniere Supply & Marketing, Inc. and Jean Abiteboul (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-6383), filed on February 5, 2014)
10.132		Payment Deferral Agreement (O&M Agreement), dated March 27, 2014, between Cheniere Energy Investments, LLC and Cheniere LNG O&M Services, LLC (Incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 1, 2014)
21.1*		Subsidiaries of Cheniere Energy, Inc.
23.1*		Consent of KPMG LLP
23.2*		Consent of Ernst & Young LLP
31.1*		Certification by Chief Executive Officer required by Rule 13a-14(a) and Rule 15d-14(a) under the Exchange Act
31.2*		Certification by Chief Financial Officer required by Rule 13a-14(a) and Rule 15d-14(a) under the Exchange Act
32.1**		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**		Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

117



Exhibit No.		Description
101.LAB*		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document



*	Filed herewith
**	Furnished herewith
†	Management contract or compensatory plan or arrangement

118

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY, INC.

CONDENSED BALANCE SHEETS

(in thousands)



	December 31,
	2014			2013
ASSETS
Non-current restricted cash and cash equivalents	$	5,847		$	5,844
Property, plant and equipment	2,596			—
Debt receivable—affiliates	809,416			775,202
Other	414			—
Investments in affiliates
Cheniere’s investment in affiliates	(25,169		)	(475,957		)
Non-controlling interest investments in affiliates	2,665,694			2,660,380
Investment in affiliates, net	2,640,525			2,184,423
Total assets	$	3,458,798		$	2,965,469

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current accrued liabilities	$	8,086		$	104
Current debt—affiliate	134,444			125,307
Long-term debt, net	814,751			—

Commitments and contingencies

Stockholders’ equity (deficit)	(164,177		)	179,678
Non-controlling interest	2,665,694			2,660,380
Total liabilities and stockholders’ equity	$	3,458,798		$	2,965,469

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

119

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY, INC.

CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

(in thousands)



	Year Ended December 31,
	2014			2013			2012
Operating costs and expenses	$	8,223		$	55		$	36

Interest expense, net	(4,205		)	—			(12,883		)
Interest expense, net—affiliates	(9,137		)	(9,137		)	(9,137		)
Interest income	3			—			—
Interest income—affiliates	34,213			34,213			34,213
Equity losses of affiliates
Equity losses of affiliates attributable to Cheniere	(416,638		)	(532,942		)	(344,937		)
Equity losses of affiliates attributable to non-controlling interest	(143,945		)	(50,841		)	(12,861		)
Net loss	$	(547,932	)	$	(558,762	)	$	(345,641	)

Other comprehensive income (loss)	—			27,351			(27,093		)
Comprehensive loss attributable to non-controlling interest	—			48,809			12,861
Comprehensive loss	$	(547,932	)	$	(482,602	)	$	(359,873	)

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

120

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2014			2013			2012
Net cash used in operating activities	$	(240	)	$	(5,796	)	$	(6,699	)

Cash flows from investing activities
Investments in affiliates	(901,329		)	139,494			(968,962		)
Net cash provided by (used in) investing activities	(901,329		)	139,494			(968,962		)

Cash flows from financing activities
Proceeds from issuance of long-term debt	1,000,000			—			—
Proceeds from sale of common stock, net	—			3,628			1,200,705
Payments related to tax withholdings for share-based compensation	(112,324		)	(140,711		)	(20,414		)
Repayments of long-term debt	—			—			(204,630		)
Excess tax benefit from share-based compensation	3,605			3,385			—
Proceeds from exercise of stock options	10,806			—			—
Other	(518		)	—			—
Net cash provided by (used in) financing activities	901,569			(133,698		)	975,661

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

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

121

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY, INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The condensed financial statements represent the financial information required by Securities and Exchange Commission Regulation S-X 5-04 for Cheniere Energy, Inc. (“Cheniere”).

In the condensed financial statements, Cheniere’s investments in affiliates are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are recorded in the balance sheets. The loss from operations of the affiliates is reported on a net basis as investment in affiliates (investment in and equity in net losses of affiliates).

A substantial amount of Cheniere’s operating, investing and financing activities are conducted by its affiliates. The condensed financial statements should be read in conjunction with Cheniere’s Consolidated Financial Statements.

NOTE 2—DEBT

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



	December 31,
	2014		2013

Note—Affiliate	$	134,444	$	125,307

Note—Affiliate

In May 2007, we entered into a $391.7 million long-term note (“Note—Affiliate”) with Cheniere Subsidiary Holdings, LLC (“Cheniere Subsidiary”), a wholly owned subsidiary of Cheniere. Cheniere Subsidiary received the $391.7 million net proceeds from a $400.0 million credit agreement entered into in May 2007. Borrowings under the Note—Affiliate bear interest equal to the terms of Cheniere Subsidiary’s credit agreement at a fixed rate of 9¾% per annum. Interest is calculated on the unpaid principal amount of the Note—Affiliate outstanding and is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year. In August 2008, the Note—Affiliate was replaced with a global intercompany note entered into by all Cheniere subsidiaries that were parties to the $250.0 million credit agreement entered into in August 2008. Each subsidiary is both a maker and a payee under the global intercompany note, and balances between subsidiaries are as recorded on Cheniere’s books and records. The $391.7 million of proceeds from the Note—Affiliate were used for general corporate purposes, including our repurchase, completed during 2007, of approximately 9 million shares of our outstanding common stock pursuant to the exercise of the call options acquired in the issuer call spread purchased by us in connection with the issuance of the $325.0 million convertible senior unsecured notes due August 2012. In January 2012, we decreased a portion of the Note—Affiliate principal balance with offsetting intercompany receivables that resulted in a new principal balance of $93.7 million.

NOTE 3—GUARANTEES

Guarantees on Behalf of Cheniere Marketing, LLC

Many of Cheniere Marketing, LLC’s natural gas purchase, sale, transportation and shipping agreements have been guaranteed by Cheniere. As of December 31, 2014, these guaranteed contracts have zero amount of exposure to the potential of future payments and there was zero carrying amount of liability related to these guaranteed contracts.

Guarantee on behalf of Sabine Pass Tug Services, LLC

Sabine Pass Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of Cheniere Energy Partners, L.P., entered into a Marine Services Agreement (“Tug Agreement”) for three tugs with Alpha Marine Services, LLC. The initial term of the Tug Agreement ends on the tenth anniversary of the service date, with Tug Services having the option for two additional extension terms of five years each. This contract has been guaranteed by Cheniere for up to $5.0 million.

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTE 4 —SUPPLEMENTAL CASH FLOW INFORMATION



	Year Ended December 31,
	2014			2013			2012
	(in thousands)
Non-cash capital contributions (1)	$	(560,583	)	$	(583,788	)	$	(357,798	)


(1)	Amounts represent equity losses of affiliates and non-controlling interest not funded by Cheniere.

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SIGNATURES

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



	CHENIERE ENERGY, INC.
	(Registrant)

	By:	/s/ Charif Souki
		Charif Souki Chief Executive Officer, President and Chairman of the Board
	Date:	February 19, 2015

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



Signature	Title	Date

/s/ Charif Souki	Chief Executive Officer, President and Chairman of the Board (Principal Executive Officer)	February 19, 2015
Charif Souki		February 19, 2015

/s/ Michael J. Wortley	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 19, 2015
Michael J. Wortley		February 19, 2015

/s/ Leonard Travis	Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 19, 2015
Leonard Travis		February 19, 2015

/s/ Vicky A. Bailey	Director	February 19, 2015
Vicky A. Bailey	Director	February 19, 2015

/s/ G. Andrea Botta	Director	February 19, 2015
G. Andrea Botta	Director	February 19, 2015

/s/ Nuno Brandolini	Director	February 19, 2015
Nuno Brandolini	Director	February 19, 2015

/s/ Keith F. Carney	Director	February 19, 2015
Keith F. Carney	Director	February 19, 2015

/s/ John M. Deutch	Director	February 19, 2015
John M. Deutch	Director	February 19, 2015

/s/ David I. Foley	Director	February 19, 2015
David I. Foley	Director	February 19, 2015

/s/ Randy A. Foutch	Director	February 19, 2015
Randy A. Foutch	Director	February 19, 2015

/s/ Paul J. Hoenmans	Director	February 19, 2015
Paul J. Hoenmans	Director	February 19, 2015

/s/ David B. Kilpatrick	Director	February 19, 2015
David B. Kilpatrick	Director	February 19, 2015

/s/ Donald F. Robillard, Jr.	Director	February 19, 2015
Donald F. Robillard, Jr.	Director	February 19, 2015

/s/ Neal A. Shear	Director	February 19, 2015
Neal A. Shear	Director	February 19, 2015

/s/ Heather R. Zichal	Director	February 19, 2015
Heather R. Zichal	Director	February 19, 2015

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