Cheniere, a Delaware corporation, was organized in 1983 and is a Houston-based energy company primarily engaged in LNG-related businesses. Our vision is to be recognized asprovide clean, secure and affordable energy to the premier global LNG company and provideworld, while responsibly delivering a reliable, competitive and integrated source of LNG, to our customers while creatingin a safe productive and rewarding work environment for our employees.environment. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Partners, which is a publicly traded limited partnership that we created in 2007. We own 100% of the general partner interest in Cheniere Partners and 82.6%82.7% of Cheniere Holdings, which is a publicly traded limited liability company formed in 2013 that owns a 55.9%48.6% limited partner interest in Cheniere Partners. We are currently developing and constructing two natural gas liquefaction and export facilities. 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 economically justify the use of LNG.

  

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “SPL Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities (described below) through a wholly owned subsidiary, SPL. Cheniere Partners plans to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 and 2 have commenced operating activities,through 4 are operational, Train 35 is undergoing commissioning and has produced LNG, Trains 4 and 5 are under construction and Train 6 is fully permitted.being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa of LNG and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, that include existingpre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each 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 also owns a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through a wholly owned subsidiary, CTPL.

We are developing and constructing a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal, which is on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas, and a pipeline facility (collectively, the “CCL Project”) through wholly owned subsidiaries CCL and CCP, respectively. The CCL Project is being developed in stages for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The CCL Project is being developed in stages. The first stage (“Stage 1”) includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the CCL Project’s necessary infrastructure facilities. The second stage (“Stage 2”) includes Train 3, one LNG storage tank and the completion of the second partial berth. The CCL Project also includes a 23-mile natural gas supply pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”). Stage 1 and the Corpus Christi Pipeline are currently under construction, and Train 3 is being commercialized and has all necessary regulatory approvals in place. The construction of the Corpus Christi Pipeline is nearing completion.

The CCL Stage III entities, our wholly owned subsidiaries separate from the CCH Group,Additionally, we are also developing additional Trains and one LNG storage tank atan expansion of the Corpus Christi LNG terminal adjacent to the CCL Project along(the “Corpus Christi Expansion Project”) and recently began the process of amending our regulatory filings with FERC to incorporate a second natural gas pipeline.

Although results are consolidated for financial reporting, Cheniere, Cheniere Holdings, Cheniere Partners, SPL SPLNG, CTPL and the CCH Group operate with independent capital structures. The following diagram depicts our abbreviated capital structure as of December 31, 2016:2017:

During 2016,the first quarter of 2017, we initiated certainfinalized organizational changes to simplify our corporate structure, improve our operational efficiencies and implement a strategy for sustainable, long-term stockholder value creation through financially disciplined development, construction, operation and investment.  We are currently evaluatingAs a result of these efforts, we revised the way we manage our business, as a result of these changes. This evaluation is expected to be completed during the first quarter of 2017 and may resultwhich resulted in a change to our reportable segmentssegments. We previously had two reportable segments: LNG terminal segment and LNG and natural gas marketing segment. We have now determined that we operate as organizational alignment is finalized.

We began developing our first 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 currently under construction: the Sabine Pass LNG terminal in western Cameron Parish, Louisiana, less than four miles from the Gulf Coast on the Sabine-Neches Waterway; and the Corpus Christi LNG terminal, which is on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas.terminal. Through Cheniere Partners, we are developing, constructing and operating the SPL Project and have constructed and are operating regasification facilities at the Sabine Pass LNG terminal. We own 100% of the general partner interest in Cheniere Partners and 82.6%82.7% of Cheniere Holdings, which owns a 55.9%48.6% limited partner interest in Cheniere Partners. We currently own a 100% interest in the CCL Project.

We are developing, constructing and operating the SPL Project at the Sabine Pass LNG terminal.terminal adjacent to the existing regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. The following table summarizes the overall project status of the SPL Project as of December 31, 2016:

In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from five to 10 years from the date the order was issued. In addition, weSPL received an order providing for a three-year makeup period with respect to each of the non-FTA orders for LNG volumes we wereSPL was authorized but unable to export during any portion of the initial 20-year export period of such order.

In January 2016,2018, the DOE issued an orderorders authorizing usSPL to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing on January 15, 2016,2018, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports to non-FTA countries under this order, when combined with exports to non-FTA countries under the orders related to Trains 1 through 4 above, may not exceed 1,0061,511 Bcf/yr).

SPL has entered into six fixed price 20-year SPAs with terms of at least 20 years (plus extension rightsrights) with third parties to make available an aggregate amount of LNG that equatesis between approximately 80% to approximately 19.75 mtpa of LNG, which is approximately 88%95% of the expected aggregate adjusted nominal production capacity of Trains 1 through 5. The obligation to make LNG available under the SPAs commences from the date of first commercial delivery for Trains 1 through 5, as specified in each SPA. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub per MMBtu of LNG.Hub. 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 the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation related to, and operating and maintenance costs to produce, the LNG to be sold under each such SPA. 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 generally commences upon the start of operations of a specified Train.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.9$1.6 billion annually for Trains 1 through 3, increasing to $2.3 billion upon the date of first commercial delivery of Train 4 and to $2.9 billion upon the date of first commercial delivery of Train 5, with the applicable fixed fees starting from the date of first commercial delivery from the applicable Train. TheseTrain, as specified in each SPA.

SPL also has SPAs with Total Gas & Power North America, Inc. (“Total”), which is guaranteed by Total S.A., and Centrica plc with annual aggregate fixed fees of approximately $590 million. In addition, Cheniere Marketing has entered into an SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers.

RevenuesDuring the year ended December 31, 2017, revenues from external customers that were derived from domestic customers was $1.6 billion and from customers outside of the United States was $4.0 billion, of which $1.2 billion, $787 million and $762 million were $514.3 million forderived from customers in Japan, Ireland and South Korea, respectively. During the year ended December 31, 2016, revenues from external customers that were derived from domestic customers was $769 million and from customers outside of the United States was $514 million, of which $161.7$162 million was derived from a customer in Japan. Substantially all of our revenues from external customers for each of the yearsyear ended December 31, 2015 and 2014 were attributed to the United States. We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing volatility in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of December 31, 2016,2017, SPL has secured up to approximately 1,993.9 million MMBtu2,214 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts.

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 5 of the SPL 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 SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract pricesprice of the EPC contract for Trains 1 and 2, the EPC contract for Trains 3 and 4 and the EPC contract for Train 5 of the SPL Project areis approximately $4.1$3.1 billion $3.9 billion and $3.0 billion, respectively, reflecting amounts incurred under change orders through December 31, 2016.2017. Total expected capital costs for Trains 1 through 5 are estimated to be between $12.5 billion and $13.5 billion before financing costs and between $17.0$17.5 billion and $18.0$18.5 billion after financing costs including, in each case, estimated owner’s costs and contingencies.

We will contemplate making an FID to commence construction of Train 6 of the SPL Project based upon, among other things, entering into an EPC contract, entering into acceptable commercial arrangements and obtaining adequate financing to construct the Train.

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 SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal.  Each of 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 SPLNG 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 SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, continuing until at least 20 years after SPL delivers its first commercial cargo at the SPL Project. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 3, SPL will progressively gaingained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement will provideprovides SPL 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 SPL to more flexibly manage its LNG storage capacity withand accommodate the commencementdevelopment of Train 1.Trains 5 and 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During the year ended December 31, 2017, SPL recorded $23 million as operating and maintenance expense under this partial TUA assignment agreement.

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

Through the CCL Stage III entities, which are separateTrain 3 is being commercialized and has all necessary regulatory approvals in place. Separate from the CCH Group, we are also developing two additional Trains and one LNG storage tank at the Corpus Christi LNG terminalExpansion Project, adjacent to the CCL Project, along with a second natural gas pipeline, and weProject. We commenced the regulatory approval process in June 2015.2015 and recently began the process of amending our regulatory filings with FERC to incorporate a project design change, from two Trains with an expected aggregate nominal production capacity of approximately 9.0 mtpa to up to seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa.

In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from 7 to 10 years from the date the order was issued.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to $1.4 billion annually for Trains 1 and 2, and $1.5 billion if we make a positive FID with respect to Stageupon the date of first commercial delivery of Train 2 of the CCL Project, with the applicable fixed fees generally starting from the date of first commercial delivery from the applicable Train. TheseTrain, as specified in each SPA.

In addition, Cheniere Marketing has entered into SPAsan SPA with CCL to purchase, at Cheniere Marketing’s option, any LNG produced by CCL in excess of that is not required for other customers.

To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing volatility in natural gas needs for the CCL Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the CCL Project. We expectAs of December 31, 2017, CCL has secured up to enter intoapproximately 2,024 TBtu of natural gas feedstock through long-term natural gas supply contracts, under these enabling agreements asa portion of which is subject to the achievement of certain project milestones and when required for the CCL Project.other conditions precedent.

  

CCL entered into separate lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Stages 1 and 2 of the CCL 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 CCL to enter into a change order, or CCL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Stage 1, which does not include the Corpus Christi Pipeline, is approximately $7.7$7.8 billion, reflecting amounts incurred under change orders through December 31, 2016.2017. Total expected capital costs for Stage 1 and the Corpus Christi Pipeline are estimated to be between $9.0 billion and $10.0 billion before financing costs, and between $11.0 billion and $12.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies.contingencies and total expected capital costs for the Corpus Christi Pipeline of between $350 million and $400 million. The total contract price of the EPC contract for Stage 2, which was amended and restated in December 2017, is approximately $2.4 billion.

In December 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the Natural Gas Act of 1938, as amended (the “NGA”), authorizing CCP to construct and operate the Corpus Christi Pipeline. The Corpus Christi Pipeline is designed to transport 2.25 Bcf/d of natural gas feedstock required by the CCL Project from the existing regional natural gas pipeline grid. The construction of the Corpus Christi Pipeline commenced in January 2017.2017 and is nearing completion.

We will contemplate making an FID to commence construction of Stage 2 of the CCL Project based upon, among other things, entering into acceptable commercial arrangements and obtaining adequate financing to construct the facility.

The SPL Project currently does not experience competition with respect to Trains 1 through 5. SPL has entered into six fixed price 20-year SPAs with terms of at least 20 years (plus extension rights) with third parties that will utilize substantially all of the liquefaction capacity available from these Trains. The CCL Project currently does not experience competition with respect to Trains 1 and 2. CCL has entered into seveneight fixed price 20-year SPAs with sixterms of at least 20 years (plus extension rights) with seven third

If and when SPL or CCL need 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 SPAs with Cheniere Marketingsold by our integrated marketing function 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.

SPLNG 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 SPLNG has to replace any TUAs, it will compete with other then-existing LNG terminals for customers.

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 the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.

In December 2014, the FERC issued an order granting CCL authorization under Section 3 of the NGA to site, construct and operate Stage 1 and Stage 2 of the CCL Project and issued a certificate of public convenience and necessity under Section 7(c) of the NGA authorizing CCP to construct and operate the Corpus Christi Pipeline (the “December 2014 Order”). A party to the proceeding requested a rehearing of the December 2014 Order, and in May 2015, the FERC denied rehearing (the “Order Denying Rehearing”). The party petitioned the U.S. Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) to review the December 2014 Order and the Order Denying Rehearing, and that petition was denied on November 4, 2016.

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, as distinguished from the requirements applied to our FERC-regulated natural gas pipeline. 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.

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 has authority to approve, and if necessary, set “just and reasonable rates” for the transportation or saleFERC’s approval under Section 7 of natural gas in interstate commerce. In addition, under the NGA, our pipelines are not permittedas well as several other material governmental and regulatory approvals and permits, may be required prior to unduly discriminate or grant undue preference as to rates or the terms and conditions of service tomaking any shipper, including its own marketing affiliate. 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 extendsmodifications 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, local distribution or export of natural gas.

The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in marketing functions. Interstate pipelines must treat all transmission customers on a not unduly discriminatory basis. The general principles of the Standards of Conduct are: (1) independent functioning, which requires transmission function employees to function independently of marketing function employees; (2) no-conduit rule, which prohibits passing transmission function information to marketing function employees; and (3) transparency, which imposes posting requirements to detect undue preference. CTPL has established the required policies and procedures to comply with the FERC’s Standards of Conduct and is subject to audit by the FERC to review compliance, policies and its training programs.

The EPAct amendedFERC’s jurisdiction under the NGA allows it to strengthen the prohibition of manipulation in the natural gas markets under the FERC’s jurisdiction and increasedimpose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to $1.0$1.3 million per day per violation, (increased civil penalties were also provided for underincluding any conduct that violates the Natural Gas Policy Act of 1978 (the “NGPA”)).NGA’s prohibition against market manipulation. In accordance with the EPAct, the FERC issued a final rule under the NGA 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. Finally, 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.

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 currently import LNG now or will do so by the end of 2017 include Canada, Chile, Colombia, Dominican Republic, Israel, Jordan, Mexico, Singapore, and South Korea and the Dominican Republic.Korea. 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.

The Creole Trail Pipeline and the Corpus Christi Pipeline are also subject to regulation by the 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 2009, the PHMSA issued a final rule (known as “Control Room Management/Human Factors Rule”) that became effective in 2010 requiring pipeline operators to write and institute certain control room procedures that address human factors and fatigue management.

In May 2015, PHMSA issued a notice of proposed rulemaking proposing to amend gas pipeline safety regulations regarding plastic piping systems used in gas services, including the installation of plastic pipe used for gas transmission lines. The PHMSA has not finalized any of the regulations proposed in this notice.

In April 2016, the PHMSA issued a notice of proposed rulemaking addressing changes to the regulations governing the safety of gas transmission pipelines. Specifically, PHMSA is considering certain integrity management requirements for “moderate consequence areas,” requiring an integrity verification process for specific categories of pipelines, and mandating more explicit requirements for the integration of data from integrity assessments to an operator’s compliance procedures. The PHMSA is also considering whether to revise requirements for corrosion control issues and expanding the definition of regulated gathering lines. These notices of proposed rulemaking are still pending at the PHMSA. The PHMSA has not finalized any of the regulations proposed in this notice.

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 sanctions.

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 approximately $200,000 per day per violation (increased from the prior $100,000), with a maximum

The construction and operation of the Sabine Pass LNG terminal and the CCL Project are subject to additional federal permits, orders, approvals and consultations required by other federal agencies, including the DOT, 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 (the “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 Operating Permit (the “Title V Permit”) and the Prevention of Significant Deterioration Permit (the “PSD Permit”), of which the latter two permits are issued by the LDEQ for the Sabine Pass LNG terminal and by the Texas Commission on Environmental Quality (“TCEQ”) for the CCL Project.

The application for revision of the Sabine Pass LNG terminal’s Section 10/404 Permit to authorize construction of Trains 1 through 4 was submitted in January 2011. The process included a public comment period, which commenced in March 2011 and closed in April 2011. The revised Section 10/404 Permit was received from the USACE in March 2012. A modification to the Section 10/404 Permit, to address wetlands impacted by the construction of Trains 5 and 6, was issued by the USACE in June 2015. The USACE acted in the capacity as a cooperating agency in the review process under the National Environmental Policy Act of 1969. In addition, a Section 10/404 Permit application is pending with respect to the expansion of the Creole Trail Pipeline. These permits will require us to provide mitigation to compensate for the wetlands impacted by the respective projects. The application to amend the Sabine Pass LNG terminal’s existing Title V and PSD Permits to authorize construction of Trains 1 through 4 was initially submitted in December 2010 and revised in March 2011. The process included a public comment period from June 2011 to August 2011 and a public hearing in August 2011. The final revised Title V and PSD Permits were issued by the LDEQ in December 2011. Although these permits are final, a petition with the EPA has been filed pursuant to the Clean Air Act requesting that the EPA object to the Title V Permit. The EPA has not ruled on this petition. In June 2012, SPL applied to the LDEQ for a further amendment to the Title V and PSD Permits to reflect proposed modifications to the SPL 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, SPL applied to the LDEQ for anotheran amendment to its PSD and Title V Permits seeking approval to, among other things, construct and operate Trains 5 and 6. The LDEQ issued the amended PSD and Title V PermitsPermit in June 2015. These permits

An application for an amendment to CCL’s Section 10/404 Permit to authorize construction of the CCL Project was submitted in August 2012. The process included a public comment period which commenced in May 2013 and closed in June 2013. The amended permit was issued by the USACE in July 2014 and subsequently modified in October 2014. CCL applied for new PSD and Title V Permits with the TCEQ in August 2012. The TCEQ issued the PSD Permit for criteria pollutants in September 2014, the PSD Permit for greenhouse gases (“GHG”) in February 2015 and the Title V Permit in July 2015. The PSD Permit issued in September 2014 was altered in February 2015 to reflect CCL’s decision to change the emissions control technology on the refrigeration turbines from water-injected to dry low emission turbines. CCL has submitted an application to amend the PSD permit for criteria pollutants. The planned amendment would reflect updates related to refined operational direction and changes that were made during the design and procurement process. The amendment process is expected to include a public comment period.

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 in December 2013. In November 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 for the Sinton Compressor Station was issued by the TCEQ in May 2015.2015, however TCEQ voided the Title V Permit in October 2017 as the facility was no longer a major source.

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. We intend to apply for aIn December 2017, further modification of this permit in mid-2017was granted to include wastewaters generated with respect to the anticipated operations of Trains 5 and 6. CCL was issued a waste water discharge permit in January 2014 authorizing discharges from the liquefaction facilities.

The Sabine Pass LNG terminal and the Corpus Christi LNG terminal are subject to PHMSA 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.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The regulatory regime created by 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 standardized swaps of certain classes as designated by the CFTC, (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, (5) provide the CFTC with expanded authority to establish position limits on certain physical commodity futures and options contracts and their economically equivalent swaps as it finds necessary and appropriate and (6) otherwise enhance the rulemaking and enforcement authority of the CFTC and the SEC regarding the derivatives markets. As required by the Dodd-Frank Act, the CFTC, the SEC and other regulators have been promulgating rules and regulations implementing the regulatory provisions of the Dodd-Frank Act, although neitherAct. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTC nor the SEC has yet adopted or implemented all of the rules required by the Dodd-Frank Act. In addition, the CFTCcontinues to review and refine its staff regularly issue rule amendmentsrulemakings through additional interpretations and guidance, policy statements and letters interpreting or taking no-action positions, including time-limited no action positions, regarding the derivatives provisions of the Dodd-Frank Act and the rules of the CFTC under these provisions.supplemental rulemakings.

A provision of the Dodd-Frank Act requires the CFTC, in order to diminish or prevent excessive speculation in commodity markets, to adopt rules, as it finds necessary and appropriate, imposing new position limits on certain physical commodity futures contracts and options thereon, as well as economically equivalent 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. In that regard, the CFTC has proposedre-proposed position limits rules that would modify and expand the applicability of limits on the speculative positions in certain physical commodity futures contracts, and economically equivalent futures, options and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants may hold, subject to limited exemptions for certain bona

As required by provisions of the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require Swap Dealers and Major Swap Participants, including those that are regulated financial institutions, to collect initial andand/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules, which, as to the collection of initial margin, are being phased in, do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We expect to qualify as such a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.

Under the Commodity Exchange Act as amended by the Dodd-Frank Act, the CFTC is directed generally to prevent manipulation of or fraud involving financial instruments, such as futures, options and swaps, on any commodity, including contracts for sale of physical commodities such as physical energy. Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge. The Dodd-Frank Act’s swaps regulatory provisions and the related rules may 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, increase the costs of entering into and maintaining swaps, 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.

EMIR is a European Union (“EU”) regulation designed to increase the stability of the OTC derivative markets throughout the EU member states. 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 market participants 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 exist 500 or more OTC derivatives outstanding with a counterparty) and dispute resolution. In addition, standards for the imposition of margin requirements under EMIR have been adopted and, as to the collection of initial margin, are being phased in, under which the exchange of initial and variation margin in respect of certain non-cleared derivatives is required, including from non-financial counterparties that have positions in any derivatives of any class that, in the aggregate, are above the EMIR clearing threshold for the class of derivatives involved. 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 requirements have yet to be finalized.

Under EMIR, covered entities must report all derivatives concluded and any modification or termination of a derivative 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 are subject to EMIR and its increased regulatory requirements for record keeping, marking to market, timely confirmation, derivative contract reporting, portfolio reconciliation, the posting of margin and

REMIT is an EU regulation that prohibits market manipulation and insider trading in European wholesale energy markets and imposes various obligations on participants in these markets. REMIT requires persons who enter into transactions, including the placing of orders to trade, in one or more wholesale energy markets in the EU to notify the applicable national regulatory authority (“NRA”) of suspected breaches and implement procedures to identify breaches. All market participants, such as us, must publicly 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 energy products 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 the relevant NRA (the Office of Gas and Electricity Markets (“Ofgem”) is the NRA in the United Kingdom) and provide a record of wholesale energy market transactions to the European Agency for the Cooperation of Energy Regulators (“ACER”) and information on capacity and utilization for production, storage, consumption or transmission. An affiliate of Cheniere Marketing is registered with Ofgem as a market participant under REMIT. Should we violate these laws and regulations, we could be subject to investigation and penalties.

Market participants and third parties acting on their behalf are required to report transactions in wholesale energy contracts admitted to trading at organized market placesREMIT transaction and fundamental data fromreporting obligations have been fully implemented since April 2016.  With regard to REMIT transaction reporting, transactions carried out on an organized market place must be reported by the European Networkmarket operator, all other contracts for the delivery of Transmission System Operators for Electricity (ENTSO) central information transparency platforms to ACER. Additional records of transactions and fundamental data with respectnatural gas to the remaining wholesale energy contracts (OTC standard and non-standard supply contracts and transportation contracts) and reportable fundamentalEU are reported by market participants. Fundamental data fromreporting obligations are largely managed by transmission system operators (TSOs), storage system operators (SSOs) and LNG system operators (LSOs) will.  LNG fundamental data may be reported by either LSOs or terminal capacity holders.  In addition, under REMIT, market participants have obligations to be providedpublicly disclose inside information pertaining to ACER beginning April 7, 2016.their business or facilities.

MiFID II is an EU directive that is due to apply startingcame into effect on January 3, 2017. Under2018.  This new directive has replaced the current regulatory regime,original Markets in Financial Instruments Directive (“MiFID”), we are exempt from needing to have our trading activities authorized.and, like its predecessor, applies across the EU and EEA member states.  MiFID II will narrowhas narrowed the scope of exemptions currently available and broadensfor commodity derivatives dealers.  In addition, MiFID II has expanded the scope of the directive’s application to include commodity derivatives that can be physically settled and which are traded on an organized trading facility in addition to other regulated markets or multilateral trading facilities. Notably, physically settled power and gas contracts have been excluded from the scope of MiFID II and are regulated under REMIT.

We expect to beare eligible to trade on our own account in commodity derivatives without requiring authorization from the Financial Conduct Authority (“FCA”) in the United Kingdom by relying onas a result of the “ancillary activity” exemption under MiFID II provided that (1) such activity is ancillary to our main business, when considered on a group basis, and that main business is not the provision of investment services or market making in relation to commodity derivatives; (2) we do not apply a high-frequency algorithmic trading technique; and (3) we notify the relevant competent authority on an annual basis that we are relying on this exemption and, upon request, report the basis upon which we fall within the exemption.  If we are unable to meet the ancillary activity exemption, and no other exemption is available to us, then we will needwould be subject to become authorized by the FCA in order to trade on our own account in commodity derivatives. FCA authorization would require additional regulatory obligations such as capital requirements conduct of business rules, systems and control issues and approval byunder the FCA of significant controllers, i.e. our shareholders and certain persons involved in our management.EU’s Capital Requirements Directive IV (“CRD IV”).  A temporary exemption applies to CRD IV, which precludes commodity trading firms from thethese capital requirements of other investment firms until the end of 2017.requirements.  This exemption is dueslated to end in 2020 when a new prudential framework for review priorMiFID investment firms is expected to December 31, 2017.come into effect.

Further, if we were to become authorized, we will be counted as a financial counterparty (instead of a non-financial counterparty) for the purpose of EMIR. This may require additional reporting obligations and risk mitigation requirements under EMIR, including collateral exchange and marking transactions either to market or to an approved model.

MAR, which applies beginningcame into effect on July 3, 2016, is intended to update and strengthen the existing EU market abuse framework by extending its scope to new markets and by introducing new requirements. MAR prohibits market abuse on EU regulated markets, which encompasses trading in financial instruments on the basis of inside information, the improper disclosure of inside information and the manipulation of market prices through practices such as the dissemination of rumors or the conducting of certain trades in financial instruments. This will apply to financial instruments (as defined under MiFID II) which are traded on

Our ability to enter into additional long-term SPAs 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. These factors include 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, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and economic growth in developing countries. In addition, our ability to obtain additional funding to execute itsour business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and our ability to access 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 2119 trillion cubic feet (“Tcf”) between 20142016 and 2025, with LNG maintaining its currentLNG’s share of approximatelygrowing from about 10% currently to about 15% of the global gas market.  Wood Mackenzie forecasts that global demand for LNG will increase by 67%65%, from approximately 255 mtpa, or 12.2 Tcf, in 2016, to 425approximately 422 mtpa, or 20.420.3 Tcf, in 2025, and that LNG production from existing facilities and new facilities already under construction will be able to supply the market with 368approximately 386 mtpa in 2025, resulting in a market need for construction of additional facilities capable of producing an incremental 5736.4 mtpa of LNG.  We believe the capital and operating costs of the uncommitted capacity of our new projects that do not already have full capacity sold under long-term contractsSPL Project, CCL Project and Corpus Christi Expansion Project are competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.

We have limited exposure, particularly in the LNG terminal business for our seven Trains under construction, to the decline in oil prices 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, weWe have contracted an aggregate amount of LNG that is between approximately 19.75 mtpa80% to 95% of the expected aggregate adjusted nominal production capacity for Trains 1 through 5 of the SPL Project with third-party customers. Train 6 has not been contracted to date. We have contracted an aggregate amount of LNG that is between approximately 7.7 mtpa for85% to 95% of the expected aggregate adjusted nominal production capacity of Trains 1 and 2 of the CCL Project, and approximately 0.8 mtpa for Train 3 of the CCL Project with third-party customers. As of January 12, 2017,31, 2018, U.S. natural gas prices indicate that LNG exported from the U.S. continues to be competitively priced, supporting the opportunity for U.S. LNG to fill uncontracted future demand through the execution of long-term, medium-term and short-term contracting of LNG from our terminals.

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.

We had 9111,230 full-time employees at January 31, 2017.  2018.  

Our common stock has been publicly traded since March 24, 2003 and is traded on the NYSE MKTAmerican 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

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.

In November 2014, we issued an aggregate principal amount of $1.0 billion Convertible Unsecured Notes due 2021 (the “2021 Cheniere Convertible Unsecured Notes”) to RRJ Capital II Ltd, Baytree Investments (Mauritius) Pte Ltd and Seatown Lionfish Pte. Ltd. In March 2015, we issued $625.0 million aggregate principal amount of 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) to certain investors through a registered direct offering. In May 2015, CCH HoldCo II issued $1.0 billion aggregate principal amount of 11% Convertible Senior Secured Notes due 2025 (the “2025 CCH HoldCo II Convertible Senior Notes” and together with the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes, the “Convertible Notes”) to EIG Management Company, LLC.  We have the option to satisfy the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes conversion obligations with cash, common stock or a combination thereof. The 2025 CCH HoldCo II Convertible Senior Notes conversion obligations must be satisfied with common stock. The 2021 Cheniere Convertible Unsecured Notes are convertible at an initial conversion price of $93.64. Prior to December 15, 2044, the 2045 Cheniere Convertible Senior Notes will be convertible upon the occurrence of certain conditions, and on and after such date they will become freely convertible. The 2045 Cheniere Convertible Senior Notes will become convertible into the common stock of Cheniere at an initial conversion price of $138.38 per share. Provided the total market capitalization of Cheniere at that time is not less than $10.0 billion, the 2025 CCH HoldCo II Convertible Senior Notes will be convertible at CCH HoldCo II’s option on or after the later of (1) 58 months from May 1, 2015 and (2) the substantial completion of Train 2 of the CCL Project (the “Eligible Conversion Date”). The conversion price for 2025 CCH HoldCo II Convertible Senior Notes converted at CCH HoldCo II’s option is the lower of (1) a 10% discount to the average of the daily volume-weighted average price (“VWAP”) of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided and (2) a 10% discount to the closing price of our common stock on the trading day preceding the date on which notice of conversion is provided. At the option of the holders, the 2025 CCH HoldCo II Convertible Senior Notes are convertible on or after the six-month anniversary of the Eligible Conversion Date, provided the total market capitalization of Cheniere at that time is not less than $10.0 billion, at a conversion price equal to the average of the daily VWAP of our common stock for the 90 trading day period prior to 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 obligations of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes with common stock, an aggregate of approximately 19.1 million shares of our common stock would be

The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

The provisions of the Dodd-Frank Act and the rules adopted and to be adopted by the CFTC, the SEC and other federal regulators establishing federal regulation of the over-the-counter (“OTC”) derivatives market and entities like us that participate in that market 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.

The CFTC has proposedre-proposed position limits rules that would modify and expand the applicability of position limits on the amounts of certain speculative futures contracts, as well as economically equivalent options, futures and swaps for or linked to

Under the Dodd-Frank Act and the rules adopted thereunder, we may be required to clear through a derivatives 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 trading platforms or exchanges. The CFTC has designated four classes ofcertain interest rate swaps (denominated in numerous currencies) and two classes of index credit default swaps for mandatory clearing, but has not yet proposed rules designating any physical commodity swaps, for mandatory clearing or mandatory exchange trading. 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 fail to qualify for that exception as to any swap we enter into and have to clear that swap through a derivatives clearing organization, we could be required to post margin with respect to such swap, our cost of entering into and maintaining such swap could increase and we would not enjoy the same flexibility with the cleared swaps that we enjoy with the uncleared OTC swaps we enter into. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.

As required by the Dodd-Frank Act, the CFTC and federal banking regulators have adopted rules to require certain market participants to collect and post initial andand/or variation margin with respect to uncleared swaps from their counterparties that are financial end users and certain registered swap dealers and major swap participants. The requirements of those rules as to the collection of initial margin are being phased in. Although we believe we will not be required to post margin with respect to any uncleared swaps we enter into in the future, were we not to do so and haverequired to post margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would be increased. 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, although not required to collect margin from us under the margin rules, contractually 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.

The Dodd-Frank Act also imposes other regulatory requirements on swaps market participants, including end users of swaps, such as regulations relating to swap documentation, reporting and recordkeeping, and certain business conduct rules applicable to swap dealers and major swap participants. Together with the Basel III capital requirements on certain swaps market participants, the regulatory requirements of the Dodd-Frank Act and the rules thereunder relating to swaps and derivatives market participants could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter and reduce our ability to monetize or restructure our existing derivative contracts and to execute our hedging strategies. 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 operating results and cash flows may become more volatile and could be otherwise adversely affected.

The Federal Reserve Board also has proposed rules that would limit certain physical commodity activities of financial holding companies. Such rules, if adopted, may adversely affect our ability to execute our strategies by restricting our available counterparties for certain types of transactions, limiting our ability to obtain certain services, and reducing liquidity in physical and financial markets. It is uncertain at this time whether, when and in what form the Federal Reserve’s proposed rules regarding financial holding companies may become final and effective.

EMIR may result in increased costs for OTC derivative counterparties entering into swaps subject to EMIR. We, and our non-EU subsidiaries and affiliates, are each categorized as an entity that would be a non-financial counterparty below EMIR’s clearing threshold (a “TCE NFC-”) when transacting OTC derivatives with EU counterparties as our derivatives business is used for hedging alone. Our entities which are TCE NFC-s are not directly subject to EMIR when transacting with EU counterparties. However, an EU counterparty requires a TCE NFC- to undertake certain obligations required by EMIR in order to ensure the EU counterparty’s compliance with EMIR. Further, our EU subsidiaries 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 qualifyaffiliates are each categorized as a non-financial counterparty below EMIR’s clearing threshold (a “NFC-”) when transacting OTC derivatives and accordingly are directly subject

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. These 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.

It will take several years to construct the SPL Project and the CCL Project, and even if successfully constructed, the SPL Project and the CCL Project would be subject to the operating risks described herein. Accordingly, there are many risks associated with the SPL Project and the CCL 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 impacteffect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The actual construction costs of the Trains or the Corpus Christi Pipeline may be significantly higher than our current estimates as a result of many factors, including change orders under existing or future EPC contracts resulting from the occurrence of certain specified events that may give Bechtel the right to cause us to enter into change orders or resulting from changes with which we otherwise agree. We have already experienced increased costs due to change orders. We do not have any prior experience in constructing liquefaction facilities, and other than Trains 1 and 2through 4 of the SPL Project, as of January 2018, 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, including change orders to comply with existing or future environmental or other regulations.

Delays in the construction of one or more Trains or the Corpus Christi Pipeline beyond the estimated development periods, as well as change orders to the EPC contracts with Bechtel or any future EPC contract related to additional Trains or the Corpus Christi Pipeline, 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 fully 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.

We will require significant additional funding to be able to commence construction of Train 6 of the SPL Project and Train 3 of the CCL 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 future 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.

The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the SPL Project and the CCL 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 orders under Section 3 of the NGA authorizing the siting, construction and operation of six Trains and related facilities of the SPL Project and an orderthree Trains and related facilities of the CCL Project and Section 7 of the NGA authorizing the siting, construction and operation of three trains of the CCL Project,Creole Trail Pipeline and the Corpus Christi Pipeline, the FERC orders require us to comply with certain ongoing conditions

Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We do not know whether or when any such approvals or permits can be obtained, or whether 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, including as a result of untimely notices or filings, 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, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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 SPL Project and the CCL Project, 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 SPL Project and the CCL Project or result in a contractor’s unwillingness to perform further work on the SPL Project and the CCL Project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

    

We are relying on third parties, principally Bechtel, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of the SPL Project and the CCL Project. 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

We will depend upon third-party pipelines and other facilities that will provide gas delivery options to our 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, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The interstate pipelines’ FERCIn addition, as a natural gas tariffs (the “Tariff”), including the pro forma transportation agreements, must be filed with and approved by the FERC. Before we enter into a transportation agreement with a shipper that contains terms that deviate in any material aspect from the filed Tariff, referred to as non-confirming terms, we must seek FERC approval. The FERC may approve the non-conforming terms in the transportation agreement; however, in that case, the non-conforming terms must be made available to our other similarly-situated customers. If we fail to seek FERC approval of a transportation agreement with non-conforming terms, 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.

Cheniere Marketing has entered intoWe expect to sell any LNG produced in excess of the aggregate annual contract quantity committed to SPL’s and CCL’s third-party SPAs with SPLthrough our integrated marketing function. We are developing a portfolio of long-, medium- and CCL pursuantshort-term SPAs to transport and unload commercial LNG cargoes to locations worldwide, which Cheniere Marketing has the option to purchaseis primarily sourced by LNG atproduced by the SPL Project and the CCL Project respectively.  Cheniere Marketing has also entered into LNG vessel charters in orderexcess of the contract quantities committed to secure shipping capacity for the export of LNG to purchasers.  Under the charters, some of which have terms of up to 5 years, Cheniere Marketing is obligated to make payments for these vessels regardless of use.  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.SPL’s and CCL’s third party SPAs, supplemented by volume procured from other locations worldwide, as needed. Failure to secure buyers for a sufficient amount of LNG could materially and adversely affect Cheniere Marketing’s business,our operating results, cash flows and liquidity.

Operations of the SPL Project are, and operations at the CCL Project 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 alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.

Operations at the Sabine Pass LNG terminal are dependent, in part, 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 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.

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 purchasers or suppliers and merchants in such countries to import or export LNG from or to the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction or regasification facilities in the United States.

 

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 in markets accessible to our customers 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 the SPL Project and the CCL Project specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

    

A terrorist, including a 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.

The construction and operation of our LNG terminals and liquefaction facilitiesour pipelines are, and will be, 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 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 operating results.

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.

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

None.

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.

Certain of our subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG terminal and the commissioning of the SPL Project, and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of our subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of our subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.

In 2015, Cheniere’sour wholly owned subsidiary, Cheniere LNG Terminals, LLC (“CLNGT”), entered into discussions with Parallax Enterprises, LLC (“Parallax Enterprises”) regarding the potential joint development of two liquefaction plants in Louisiana (the “Potential Liquefaction Transactions”). While the parties negotiated regarding the Potential Liquefaction Transactions, CLNGT loaned Parallax Enterprises approximately $46 million, as reflected in a secured note dated April 23, 2015, as amended on June 30, 2015, September 30, 2015 and November 4, 2015 (the “Secured Note”). The Secured Note was secured by all assets of Parallax Enterprises and its subsidiary entities. On June 30, 2015, Parallax Enterprises’ parent entity, Parallax Energy LLC (“Parallax Energy”), executed a Pledge and Guarantee Agreement further securing repayment of the Secured Note by providing a parent guaranty and a pledge of all of the equity of Parallax Enterprises in satisfaction of the Secured Note (the “Pledge Agreement”). CLNGT and Parallax Enterprises never executed a definitive agreement to pursue the Potential Liquefaction Transactions. The Secured Note matured on December 11, 2015, and Parallax Enterprises failed to make payment. On February 3, 2016, CLNGT filed an action against Parallax Energy, Parallax Enterprises and certain of Parallax Enterprises’ subsidiary entities, styled Cause No. 4:16-cv-00286, Cheniere LNG Terminals, LLC v. Parallax Energy LLC, et al., in the United States District Court for the Southern District of Texas (the “Texas Federal Suit”). CLNGT asserted claims in the Texas Federal Suit for (1) recovery of all amounts due under the Secured Note and (2) declaratory relief establishing that CLNGT is entitled to enforce its rights under the Secured Note and Pledge Agreement in accordance with each instrument’s terms and that CLNGT has no obligations of any sort to Parallax Enterprises concerning the Potential Liquefaction Transactions. On March 11, 2016, Parallax Enterprises and the other defendants in the Texas Federal Suit moved to dismiss the suit for lack of subject matter jurisdiction. On August 2, 2016, the court denied the defendants’ motion to dismiss without prejudice and permitted the parties to pursue jurisdictional discovery, which is ongoing.discovery.

On March 11, 2016, Parallax Enterprises filed a suit against Cheniereus and CLNGT styled Civil Action No. 62-810, Parallax Enterprises LLP v. Cheniere Energy, Inc. and Cheniere LNG Terminals, LLC, in the 25th Judicial District Court of Plaquemines Parish, Louisiana (the “Louisiana Suit”), wherein Parallax Enterprises asserted claims for breach of contract, fraudulent inducement, negligent misrepresentation, detrimental reliance, unjust enrichment and violation of the Louisiana Unfair Trade Practices Act. Parallax Enterprises predicated its claims in the Louisiana Suit on an allegation that Chenierewe and CLNGT breached a purported agreement to jointly develop the Potential Liquefaction Transactions. Parallax Enterprises sought $400 million in alleged economic damages and rescission of the Secured Note. On April 15, 2016, Chenierewe and CLNGT removed the Louisiana Suit to the United

We do not expect that the resolution of this litigation will have a material adverse impact on itsour financial results.

Our common stock has traded on the NYSE MKTAmerican 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,American, for each quarter during 20162017 and 2015.2016. 

As of February 17, 2017,15, 2018, we had 237.9237.7 million shares of common stock outstanding held by approximately 614478 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 (our “Board”) in light of our financial condition, capital requirements, earnings, prospects and any restrictions under any financing agreements, as well as other factors our Board deems relevant.

The following graph compares the five-year total return on our common stock, the S&P 500 Index and a customized peer group of 17 companies that includes: (1) Calpine Corp. (CPN), (2) Dynegy Inc. (DYN), (3) Dominion Resources, Inc. (D), (4) PG&E Corporation (PCG), (5) Sempra Energy (SRE), (6) Public Service Enterprise Group Inc. (PEG), (7) DTE Energy Company (DTE), (8) Ameren Corporation (AEE), (9) CMS Energy Company (CMS), (10) Enterprise Product Partners L.P. (EPD), (11) Enbridge (ENB), (12) TransCanada Corporation (TRP), (13) Spectra Energy Corp (SE), which merged with Enbridge in 2017, (14) Magellan Midstream Partners LP (MMP), (15) MarkWest Energy Partners, L.P. (MWE), which was acquired by MPLX LP in 2015, (16) ONEOK Inc. (OKE) and (17) Targa Resources Corp. (TRGP) (collectively, the “New Peer“Peer Group”).  We selected the New Peer Group companies because they are publicly traded companies that have: (1) comparable Global Industries Classification Standards, (2) similar market capitalization, (3) similar enterprise values and (4) similar operating characteristics and capital intensity. The New Peer Group companies were revised during 2016. Our previous peer group consisted of 20 companies, including the 17 companies of the New Peer Group, Kinder Morgan, Inc. (KMI), Energy Transfer Equity, L.P. (ETE) and Plains All American Pipeline, L.P. (PAA) (collectively, the “Old Peer Group”).

The graph was constructed on the assumption that $100 was invested in our common stock, the S&P 500 Index the New Peer Group and the Old Peer Group on December 31, 20112012 and that any dividends were fully reinvested.

Selected financial data set forth below (in thousands, except per share data) are derived from our audited Consolidated Financial Statements for the periods indicated.indicated (in millions, except per share data). 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.

Cheniere, a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. Our vision is to be recognized asprovide clean, secure and affordable energy to the premier global LNG company and provideworld, while responsibly delivering a reliable, competitive and integrated source of LNG, to our customers while creatingin a safe productive and rewarding work environment for our employees.environment. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Partners, which is a publicly traded limited partnership that we created in 2007. We own 100% of the general partner interest in Cheniere Partners and 82.6%82.7% of Cheniere Holdings, which is a publicly traded limited liability company formed in 2013 that owns a 55.9%48.6% limited partner interest in Cheniere Partners. We are currently developing and constructing two natural gas liquefaction and export facilities. 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 economically justify the use of LNG.

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “SPL Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, SPL. Cheniere Partners plans to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 and 2 have commenced operating activities,through 4 are operational, Train 35 is undergoing commissioning and has produced LNG, Trains 4 and 5 are under construction and Train 6 is fully permitted.being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa of LNG and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, that include existingpre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each 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 also owns a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through a wholly owned subsidiary, CTPL.

We are developing and constructing a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal, which is on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas, and a pipeline facility (collectively, the “CCL Project”) through wholly owned subsidiaries CCL and CCP, respectively. The CCL Project is being developed for up to three Trains, with expected aggregate nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 13.5 mtpa of LNG, three LNG storage tanks with aggregate capacity of approximately 10.1 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. The CCL Project is being developed in stages. The first stage (“Stage 1”) includes Trains 1 and 2, two LNG storage tanks, one complete

The CCL Stage III entities, our wholly owned subsidiaries separate from the CCH Group,Additionally, we are also developing additional Trains and one LNG storage tank atan expansion of the Corpus Christi LNG terminal adjacent to the CCL Project along(the “Corpus Christi Expansion Project”) and recently began the process of amending our regulatory filings with FERC to incorporate a second natural gas pipeline.

The following table provides a summary of our liquidity position at December 31, 2017 and 2016 and 2015 (in thousands)millions):

 

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, 2016,2017, we had an 82.6%82.7% 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. During the years ended December 31, 2016, 2015 and 2014, wePartners. We received $14.8$98 million, $14.7$15 million and $14.3$15 million respectively, in dividends on our Cheniere Holdings common shares during each of the years ended December 31, 2017, 2016 and $1.0 million, $1.0 million and $1.1 million, respectively, of management fees from Cheniere Holdings.2015, respectively.

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of December 31, 2016,2017, we own 82.6%owned 82.7% of Cheniere Holdings, which ownsowned a 55.9% limited partner48.6% interest in Cheniere Partners in the form of 11,963,488104.5 million common units 45,333,334 Class B units and 135,383,831135.4 million subordinated units. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners.

We also receive fees for providing management services to Cheniere Holdings, Cheniere Partners, SPLNG, SPL and CTPL. We received $2.0$106 million, in distributions on our general partner interest during each of the years ended December 31, 2016, 2015 and 2014, and we received $117.8 million, $92.6$119 million and $110.5$94 million in total service fees from Cheniere Holdings, Cheniere Partners, SPLNG, SPL and CTPL during the years ended December 31, 2017, 2016 2015 and 2014,2015, respectively.

On August 2, 2017, Cheniere Partners’ Class B units (“Class B units”) mandatorily converted into common unitunits in accordance with the terms of Cheniere Partners’ partnership agreement. Upon conversion of the Class B units, Cheniere Holdings, Blackstone CQP Holdco LP (“Blackstone CQP Holdco”) and general partner distributions are being funded from accumulated operating surplus. We have not received distributions on ourthe public owned a 48.6%, 40.3% and 9.1% interest in Cheniere Partners, respectively. Cheniere Holdings’ ownership percentage includes its subordinated units with respectand Blackstone CQP Holdco’s ownership percentage excludes any common units that may be deemed 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 SPLNG, SPL, CTPL 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 arewere 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 arewere 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 date of the Class B units, the conversion value of the Class B units increasesincreased 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 CQP Holdco”) was 1.86 and 1.83, respectively, as of December 31, 2016. The Class B units will mandatorily convert into common units on the first business day following the record date of our first distribution after the substantial completion date of Train 3 of the SPL Project, but in any case no earlier than the first business day following the record date of our distribution with respect to the quarter ended June 30, 2017. If the Class B units are not mandatorily converted by July 2019,

The Class B units were issued at a discount to the market price of the Cheniere PartnersPartners’ common units into which they arewere convertible.  This discount, totaling $2,130.0$2,130 million, representsrepresented a beneficial conversion feature.  The beneficial conversion feature iswas similar to a dividend that will bewas distributed with respect to any Class B unit from its issuance date through its conversion date, resultingwhich resulted in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity, including our equity interest in Cheniere Partners. Cheniere Partners amortizesamortized the beneficial conversion feature assuming athrough the mandatory conversion date of August 2017, although actual conversion may occur prior to or after this assumed date.as a non-cash adjustment. Deemed dividends represented by the amortization of the beneficial conversion feature allocated to the Class B units held by Blackstone CQP Holdco arewere included in net lossincome (loss) attributable to non-controlling interest and resultresulted in a reduction of income available to common stockholders. The impact to net lossincome (loss) attributable to non-controlling interest due to the amortization of the beneficial conversion feature was approximately$748 million, $34 million and zero during the yearyears ended December 31, 2017, 2016 and is anticipated to be approximately $747 million for the year ending December 31, 2017 based on the assumed conversion date and ownership interest as of December 31, 2016.2015, respectively.

In February 2016, Cheniere Partners entered into the 2016 CQP Credit Facilities. The 2016 CQP Credit Facilities consist of: (1) a $450.0$450 million CTPL tranche term loan that was used to prepay the $400.0$400 million CTPLterm loan facility (the “CTPL Term LoanLoan”) in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that was used to repay and redeem the approximately $2.1 billion of the 2016senior notes previously issued by SPLNG (the “SPLNG Senior Notes and 2020 SPLNG Senior NotesNotes”) in November 2016, (3) a $125.0$125 million DSR Facilityfacility that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0$115 million revolving credit facility that may be used for general business purposes. In September 2017, Cheniere Partners issued the 2025 CQP Senior Notes and the net proceeds were used to prepay $1.5 billion of the outstanding indebtedness under the 2016 CQP Credit Facilities. As of December 31, 2017 and 2016, Cheniere Partners had $195.0$220 million and $195 million of available commitments, $45.0$20 million and $45 million aggregate amount of issued letters of credit and $1.1 billion and $2.6 billion of outstanding borrowings under the 2016 CQP Credit Facilities.Facilities, respectively.

The 2016 CQP Credit Facilities mature on February 25, 2020, and thewith principal payments due quarterly commencing on March 31, 2019. The outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit Cheniere Partners’ ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the terms of the 2016 CQP Credit Facilities, Cheniere Partners is required to hedge not less than 50% of the variable interest rate exposure on its projected aggregate outstanding balance, maintain a minimum debt service coverage ratio of at least 1.15x at the end of each fiscal quarter beginning March 31, 2019 and have a projected debt service coverage ratio of 1.55x in order to incur additional indebtedness to refinance a portion of the existing obligations.

The 2016 CQP Credit Facilities are unconditionally guaranteed by each subsidiary of Cheniere Partners other than (1) SPL and (2) certain of the subsidiaries of Cheniere Partners owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

TheWe are developing, constructing and operating the SPL 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 6. The following table summarizes the overall project status of the SPL Project as of December 31, 2016:

In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from five to 10 years from the date the order was issued. In addition, weSPL received an order providing for a three-year makeup period with respect to each of the non-FTA orders for LNG volumes we wereSPL was authorized but unable to export during any portion of the initial 20-year export period of such order.

In January 2016,2018, the DOE issued an orderorders authorizing usSPL to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing on January 15, 2016,2018, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports to non-FTA countries under this order, when combined with exports to non-FTA countries under the orders related to Trains 1 through 4 above, may not exceed 1,0061,511 Bcf/yr).

SPL has entered into six fixed price 20-year SPAs with terms of at least 20 years (plus extension rights) with third parties to make available an aggregate amount of LNG that equatesis between approximately 80% to approximately 19.75 mtpa of LNG, which is approximately 88%95% of the expected aggregate adjusted nominal production capacity of Trains 1 through 5. The obligation to make LNG available under the SPAs commences from the date of first commercial delivery for Trains 1 through 5, as specified in each SPA. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.9$1.6 billion annually for Trains 1 through 3, increasing to $2.3 billion upon the date of first commercial delivery of Train 4 and to $2.9 billion upon the date of first commercial delivery of Train 5, with the applicable fixed fees starting from the date of first commercial delivery from the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million forTrain, as specified in each of Trains 1 through 5, respectively.SPA.

In addition, Cheniere Marketing has entered into an SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers.

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing volatility in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of December 31, 2016,2017, SPL has secured up to approximately 1,993.9 million MMBtu2,214 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts.

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 5 of the SPL 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 SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract pricesprice of the EPC contract for Trains 1 and 2, the EPC contract for Trains 3 and 4 and the EPC contract for Train 5 of the SPL Project areis approximately $4.1$3.1 billion $3.9 billion and $3.0 billion, respectively, reflecting amounts incurred under change orders through December 31, 2016.2017. Total expected capital costs for Trains 1 through 5 are estimated to be between $12.5 billion and $13.5 billion before financing costs and between $17.0$17.5 billion and $18.0$18.5 billion after financing costs including, in each case, estimated owner’s costs and contingencies.

We will contemplate making an FID to commence construction of Train 6 of the SPL Project based upon, among other things, entering into an EPC contract, entering into acceptable commercial arrangements and obtaining adequate financing to construct the Train.Train 6.

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 SPLNG’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 SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009. Total S.A. has

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, continuing until at least 20 years after SPL delivers its first commercial cargo at the SPL Project. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 3, SPL will progressively gaingained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement will provideprovides SPL 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

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

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 20272037 SPL Senior Notes, in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior

TheBoth the indenture governing the 2037 SPL Indenture includesSenior Notes (the “2037 SPL Senior Notes Indenture”) and the common indenture governing the remainder of the SPL Senior Notes (the “SPL Indenture”) include restrictive covenants. SPL 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 SPL, including the SPL Senior Notes the 2015 SPL Credit Facilities and the SPL Working Capital Facility. Under the 2037 SPL Senior Notes Indenture and the SPL Indenture, SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025.

In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion. The 2015 SPL Credit Facilities are being usedbillion to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the SPL Project. In February 2017, SPL had $1.6 billionissued the 2037 SPL Senior Notes and $3.8 billiona portion of available commitments and $314.0 million and $845.0 million ofthe net proceeds was used to prepay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities asFacilities. In March 2017, SPL issued the 2028 SPL Senior Notes and SPL terminated the remaining available balance of December 31, 2016 and 2015, respectively.

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“SPL Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“SPL Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the SPL Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the SPL Project, request an incremental increase in commitments of up to an additional $390 million. As of December 31, 2017 and 2016, SPL had $652.8$470 million and $653 million of available commitments, $323.7$730 million and $324 million aggregate amount of issued letters of credit and $223.5zero and $224 million of loans outstanding under the SPL Working Capital Facility. As of December 31, 2015, SPL had $1.1 billion of available commitments, $135.2 million aggregate amount of issued letters of credit and $15.0 million of loans outstanding under the SPL Working Capital Facility.

The SPL Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty upon three business days’ notice. Loans deemed made in connection with a draw upon a letter of credit have a term of up to one year. SPL Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the SPL Working Capital Facility, (2) the date 15 days after such SPL Swing Line Loan is made and (3) the first borrowing date for a SPL Working Capital Loan or SPL Swing Line Loan occurring at least three business days following the date the SPL Swing Line Loan is made. SPL is required to reduce the aggregate outstanding principal amount of all SPL Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The CCL Project is being developed and constructed at the Corpus Christi LNG terminal, on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas.terminal. In December 2014, we received authorization from the FERC to site, construct and operate Stages 1 and 2 of the CCL Project. The following table summarizes the overall project status of Stage 1 of the CCL Project:Project as of December 31, 2017:

Through the CCL Stage III entities, which are separateTrain 3 is being commercialized and has all necessary regulatory approvals in place. Separate from the CCH Group, we are also developing two additional Trains and one LNG storage tank at the Corpus Christi LNG terminalExpansion Project, adjacent to the CCL Project, along with a second natural gas pipeline, and weProject. We commenced the regulatory approval process in June 2015.2015 and recently began the process of amending our regulatory filings with FERC to incorporate a project design change, from two Trains with an expected aggregate nominal production capacity of approximately 9.0 mtpa to up to seven midscale Trains with an expected aggregate nominal production capacity of approximately 9.5 mtpa.

In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from 7 to 10 years from the date the order was issued.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $550 million for Train 1, increasing to $1.4 billion annually for Trains 1 and 2, and $1.5 billion if we make a positive FID with respect to Stageupon the date of first commercial delivery of Train 2 of the CCL Project, with the applicable fixed fees generally starting from the date of first commercial delivery from the applicable Train. These fixed fees equal approximately $550 million, $846 million and $140 million forTrain, as specified in each of Trains 1 through 3, respectively.SPA.

In addition, Cheniere Marketing has entered into SPAsan SPA with CCL to purchase, at Cheniere Marketing’s option, any LNG produced by CCL in excess of that is not required for other customers.

To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing volatility in natural gas needs for the CCL Project. CCL has also entered into enabling agreements and long-term natural gas supply contracts with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the CCL Project. We expectAs of December 31, 2017, CCL has secured up to enter intoapproximately 2,024 TBtu of natural gas feedstock through long-term natural gas supply contracts, under these enabling agreements asa portion of which is subject to the achievement of certain project milestones and when required for the CCL Project.other conditions precedent.

CCL entered into separate lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Stages 1 and 2 of the CCL 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 CCL to enter into a change order, or CCL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Stage 1, which does not include the Corpus Christi Pipeline, is approximately $7.7$7.8 billion, reflecting amounts incurred under change orders through December 31, 2016.2017. Total expected capital costs for Stage 1 and the Corpus Christi Pipeline are estimated to be between $9.0 billion and $10.0 billion before financing costs, and between $11.0 billion and $12.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies.contingencies and total expected capital costs for the Corpus Christi Pipeline of between $350 million and $400 million. The total contract price of the EPC contract for Stage 2, which was amended and restated in December 2017, is approximately $2.4 billion.

In December 2014, the FERC issued a certificate of public convenience and necessity under Section 7(c) of the Natural Gas Act of 1938, as amended, authorizing CCP to construct and operate the Corpus Christi Pipeline. The Corpus Christi Pipeline is designed to transport 2.25 Bcf/d of natural gas feedstock required by the CCL Project from the existing regional natural gas pipeline grid. The construction of the Corpus Christi Pipeline commenced in January 2017.2017 and is nearing completion.

We will contemplate making an FID to commence construction of Stage 2 of the CCL Project based upon, among other things, entering into acceptable commercial arrangements and obtaining adequate financing to construct the facility.

In May 2015, CCH HoldCo II issued $1.0 billion aggregate principal amount of 11% Convertible Senior Secured Notes due 2025 (the “2025 CCH HoldCo II Convertible Senior Notes”) on a private placement basis. The 2025 CCH HoldCo II Convertible Senior Notes are convertible at the option of CCH HoldCo II or the holders, provided that various conditions are met. CCH HoldCo II is restricted from making distributions to Cheniere under agreements governing its indebtedness generally until, among other requirements, Trains 1 and 2 of the CCL Project are in commercial operation and a historical debt service coverage ratio and a projected fixed debt service coverage ratio of 1.20:1.00 are achieved.

In May and December 2016,2017, CCH issued an aggregate principal amountsamount of $1.25$1.5 billion of the 2027 CCH Senior Notes, in addition to the existing 2024 CCH Senior Notes and $1.5 billion of the 2025 CCH Senior Notes, respectively.Notes. The CCH Senior Notes are jointly and severally guaranteed by its subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (“CCP GP”, and collectively with CCL and CCP, the(the “CCH Guarantors”).

The indenture governing the CCH Senior Notes (the “CCH Indenture”) contains customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of CCH and its restricted subsidiaries taken as a whole; or permit any CCH Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets.

At any time prior to six months before the respective dates of maturity for each series of the CCH Senior Notes, CCH may redeem all or part of such series of the CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the CCH Indenture, plus accrued and unpaid interest, if any, to the date of redemption. CCH also may at any time within six months of the respective dates of maturity for each series of the CCH Senior Notes, redeem all or part of such series of the CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

In May 2015, CCH entered into the 2015 CCH Credit Facility. The obligations of CCH under the 2015 CCH Credit Facility are secured by a first priority lien on substantially all of the assets of CCH and its subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in CCH. As of December 31, 2017 and 2016, CCH had $2.1 billion and $3.6 billion of available commitments and $2.5 billion and $2.4 billion of outstanding borrowings under the 2015 CCH Credit Facility.Facility, respectively.

The principal of the loans made under the 2015 CCH Credit Facility must be repaid in quarterly installments, commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following project completion and (2) a set date determined by reference to the date under which a certain LNG buyer linked to Train 2 of the CCL Project is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the project completion and designed to achieve a minimum projected fixed debt service coverage ratio of 1.55:1.

In December 2016, CCH entered into the $350 million CCH Working Capital Facility, which is intended to be used for loans to CCH (“CCH Working Capital Loans”), the issuance of letters of credit on behalf of CCH, as well as for swing line loans to CCH (“CCH Swing Line Loans”) for certain working capital requirements related to developing and placing into operation the CCL Project. Loans under the CCH Working Capital Facility are guaranteed by the CCH Guarantors. CCH may, from time to time, request increases in the commitments under the CCH Working Capital Facility of up to the maximum allowed under the Common Terms Agreement that was entered ininto concurrently with the 2015 CCH Credit Facility. As of December 31, 2016, CCH did not have any amounts outstanding under the CCH Working Capital Facility.Facility as of both December 31, 2017 and 2016, and CCH had $164 million and zero aggregate amount of issued letters of credit as of December 31, 2017 and 2016, respectively.

The CCH Working Capital Facility matures on December 14, 2021, and CCH may prepay the CCH Working Capital Loans, CCH Swing Line Loans and loans made in connection with a draw upon any letter of credit (“CCH LC Loans”) at any time without premium or penalty upon three business days’ notice and may re-borrow at any time. CCH LC Loans have a term of up to one year. CCH Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the CCH Working Capital Facility, (2) the date that is 15 days after such CCH Swing Line Loan is made and (3) the first borrowing date for a CCH Working Capital Loan or CCH Swing Line Loan occurring at least four business days following the date the CCH Swing Line Loan is made. CCH is required to reduce the aggregate outstanding principal amount of all CCH Working Capital Loans to zero for a period of five consecutive business days at least once each year.

We market and Natural Gas Marketing Business

We are required to maintain corporate and general and administrative functions to serve our business activities described above.  We are also in various stages of developing other projects, including liquefaction projects and other infrastructure projects in support of natural gas supply and LNG demand, which, among other things, will require acceptable commercial and financing arrangements before we make an FID. We are exploring the developmenthave made an equity investment of a midscale liquefaction project using electric drive modular Trains, with an expected aggregate nominal production capacity of approximately 9.5 mtpa of LNG. We have proposed the development of$55 million in Midship Pipeline, which is developing a pipeline with expected capacity of up to 1.4 Bcf/d connecting1.44 million Dekatherms per day that will connect new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the SPL Project and the CCL Project. We recently commenced

Effective January 1, 2017, we adopted ASU 2016-09 which requires excess tax benefits or deficiencies for share-based payments to be recognized as income tax expense or benefit in the regulatory pre-filing process and expect to file formal applicationsperiod shares vest rather than within equity. The adoption of ASU 2016-09 will result in future volatility of our income tax expense (as the future tax effects of share-based awards will be dependent on the price of our common stock at the time of settlement).  Excess tax benefits reduced our effective tax rate by 6% for the required regulatory permitsperiod ending December 31, 2017.

The following table (in thousands) summarizes the sources and uses of our cash, cash equivalents and restricted cash for the years ended December 31, 2017, 2016 and 2015 and 2014.(in millions). 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. 

OperatingOur operating cash outflowsflows during the years ended December 31, 2017, 2016 and 2015 and 2014 were $403.8 million, $482.5an inflow of $1.2 billion, an outflow of $404 million and $262.8an outflow of $483 million, respectively. The $1.6 billion increase in operating cash inflows in 2017 compared to 2016 was primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the of additional Trains that were operating at the SPL Project in 2017. During the year ended December 31, 2017, Trains 1 and 2 were operating for twelve months and Train 3 and Train 4 were operating for nine and three months, respectively, whereas in 2016, Train 1 was operating for seven months and Train 2 was operating for less than four months. The decrease in operating cash outflows in 2016 compared to 2015 was primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the commencement of operations of Trains 1 and 2 of the SPL Project in May and September 2016, respectively, and increased cash payout for phantom unit awards.

Investing cash outflows during the years ended December 31, 2017 and 2016 2015 and 2014 were $3.4 billion, $4.4 billion $7.0 billion and $2.9$7.0 billion, respectively, and arewere primarily used to fund the construction costs for Trains 1 through 5 of the SPL Project and Trains 1 and 2 of the CCL Project. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally,In addition to cash outflows for construction costs for the SPL Project and the CCL Project, during the year ended December 31, 2017, we invested $41 million in our equity method investment Midship Holdings and made payments of $19 million primarily for infrastructure to support the CCL Project and other capital projects. Partially offsetting these cash outflows was a $36 million receipt during the year ended December 31, 2017 from the return of collateral payments previously paid for the CCL Project. During the years ended December 31, 2016 2015 and 2014,2015, we used $57.8 million, $131.1$57 million and $66.9131 million, respectively, primarily for collateral payments for the CCL Project, payments to pay municipal water districts for water system enhancements that will increase potable water supply to our export terminals, payments made for capital assets purchased pursuant to information technology services agreements collateral payments for the CCL Project and for investments made in unconsolidated entities.

We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations (in thousands) in place as of December 31, 2016:2017 (in millions):

Our consolidated net loss attributable to common stockholders was $610.0$393 million, or $1.68 per share (basic and diluted), in the year ended December 31, 2017, compared to a net loss attributable to common stockholders of $610 million, or $2.67 per share (basic and diluted), in the year ended December 31, 2016, compared2016. This $217 million decrease in net loss in 2017 was primarily a result of increased income from operations, which were partially offset by increased allocation of net income to non-controlling interest and increased interest expense, net of amounts capitalized.

In August 2017, Hurricane Harvey struck the Texas and Louisiana coasts, and the Sabine Pass LNG terminal experienced a temporary suspension in construction and LNG loading operations. Construction on the Corpus Christi LNG terminal was also suspended. Neither terminal sustained significant damage, and the effects of Hurricane Harvey did not have a material impact on our Consolidated Financial Statements.

Our consolidated net loss attributable to common stockholders of $975.1was $975 million, or $4.30 per share (basic and diluted), in the year ended December 31, 2015. This $365.1$365 million decrease in net loss in 2016 compared to 2015 was primarily a result of decreased loss from operations and decreased derivative loss, net, which were partially offset by increased interest expense, net of amounts capitalized.