1 CHENIERE ENERGY, INC. CORPORATE PRESENTATION | June 2017

2 Safe Harbor Statements Forward-Looking Statements This presentation contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical or present facts or conditions, included or incorporated by reference herein are “forward-looking statements.” Included among “forward-looking statements” are, among other things: • statements regarding the ability of Cheniere Energy Partners, L.P. to pay distributions to its unitholders or Cheniere Energy Partners LP Holdings, LLC or Cheniere Energy, Inc. to pay dividends to its shareholders or participate in share or unit buybacks; • statements regarding Cheniere Energy, Inc.’s, Cheniere Energy Partners LP Holdings, LLC’s or Cheniere Energy Partners, L.P.’s expected receipt of cash distributions from their respective subsidiaries; • statements that Cheniere Energy Partners, L.P. expects to commence or complete construction of its proposed liquefied natural gas (“LNG”) terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, by certain dates or at all; • statements that Cheniere Energy, Inc. expects to commence or complete construction of its proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions then of, by certain dates or at all; • statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide, or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure, or demand for and prices related to natural gas, LNG or other hydrocarbon products; • statements regarding any financing transactions or arrangements, or ability to enter into such transactions; • statements relating to the construction of our proposed liquefaction facilities and natural gas liquefaction trains (“Trains”) and the construction of the Corpus Christi Pipeline, including statements concerning the engagement of any engineering, procurement and construction ("EPC") contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto; • statements regarding any agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas, liquefaction or storage capacities that are, or may become, subject to contracts; • statements regarding counterparties to our commercial contracts, construction contracts and other contracts; • statements regarding our planned development and construction of additional Trains or pipelines, including the financing of such Trains or pipelines; • statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities; • statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs, run-rate SG&A estimates, cash flows, EBITDA, Adjusted EBITDA, run-rate EBITDA, distributable cash flow, and distributable cash flow per share and unit, any or all of which are subject to change; • statements regarding projections of revenues, expenses, earnings or losses, working capital or other financial items; • statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions; • statements regarding our anticipated LNG and natural gas marketing activities; and • any other statements that relate to non-historical or future information. These forward-looking statements are often identified by the use of terms and phrases such as “achieve,” “anticipate,” “believe,” “contemplate,” “develop,” “estimate,” “example,” “expect,” “forecast,” “goals,” ”guidance,” “opportunities,” “plan,” “potential,” “project,” “propose,” “subject to,” “strategy,” “target,” and similar terms and phrases, or by use of future tense. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in “Risk Factors” in the Cheniere Energy, Inc., Cheniere Energy Partners, L.P. and Cheniere Energy Partners LP Holdings, LLC Annual Reports on Form 10-K filed with the SEC on February 24, 2017, which are incorporated by reference into this presentation. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these ”Risk Factors.” These forward-looking statements are made as of the date of this presentation, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise. Reconciliation to U.S. GAAP Financial Information The following presentation includes certain “non-GAAP financial measures” as defined in Regulation G under the Securities Exchange Act of 1934, as amended. Schedules are included in the appendix hereto that reconcile the non-GAAP financial measures included in the following presentation to the most directly comparable financial measures calculated and presented in accordance with U.S. GAAP.

3 CHENIERE OVERVIEW

4 Cheniere Investment Thesis  Full-service LNG offering, including gas procurement, transportation, liquefaction, and shipping enables flexible solutions tailored to customer needs  Positioned as premier LNG provider, with a proven track record and low-cost advantage through capacity expansion at existing sites  7 train platform offers excellent visibility for long-term cash flows • 20-year “take-or-pay” style commercial agreements with investment grade off-takers for approximately 87% of the expected aggregate nominal production capacity under construction or completed • Competitive cost of production, with approximately 100 years of natural gas reserves in U.S. and 800 Tcf of North American natural gas producible below $3.00/MMBtu  Supply/demand fundamentals support continued LNG demand growth worldwide • Approximately 30% increase in global natural gas demand forecast by 2030 • Global LNG trade grew 7.5% in 2016 to 263.6 mtpa with 39 countries importing LNG in 2016 (4 new market entrants) • Estimated LNG demand growth of more than 200 mtpa to 470 mtpa in 2030  Opportunities for future cash flow growth at attractive return hurdles • Uncontracted incremental production available to Cheniere Marketing • Construction of additional LNG trains • Two trains fully permitted (Corpus Christi T3, Sabine Pass T6), with one partially commercialized (Corpus Christi T3) • Significant expansion opportunities at both sites leveraging infrastructure and expertise  Investments in additional infrastructure along the LNG value chain Source: Cheniere Research, EIA, Cheniere interpretation of Wood Mackenzie data (Q1 2017), IHS, GIIGNL

5 Cheniere LNG Cargo Destinations Cheniere Office Cheniere LNG Facility Portugal Kuwait, UAE, Pakistan India, Thailand Brazil Argentina Houston, TX Santiago, Chile Washington, DC London, U.K. Singapore Cargo Delivery Destination China Spain Mexico Dominican Republic Italy, Malta, Egypt, Turkey, Jordan Japan, South Korea More than 100 Cargoes (~400 TBtu) Exported and Delivered to 20 Countries Across the Globe Chile Tokyo, Japan Note: As of April 30, 2017.

6  At current 3-train run rate, Cheniere is the largest physical natural gas consumer in the U.S.  7-train platform forecast to make Cheniere 2 to 3 times the next largest consumer  Cheniere holds capacity on most Gulf Coast interstate pipelines • Largest shipper on CTPL, Transco, KMLP  Projected to load almost 200 vessels in 2017  Top 10 LNG shipping capacity holder • More than 30 vessels chartered to date • Up to 12 vessels on the water simultaneously  Cheniere Marketing’s portfolio would make it a top 15 LNG market player stand-alone  Global footprint with offices in 5 countries  Advanced engagement with multiple counterparties in core market segments: portfolio, end user, and market development  Team has executed almost 30 mtpa of term offtake commitments  Enhance and support integrated LNG value chain  Downstream / Market Development • Chile: El Campesino  Upstream / Supply • SCOOP & STACK: Midship pipeline Market Leading Position Along the Value Chain Gas Supply Optimize and monetize excess cargoes; deliver to foundation customers Deliver term contracts to underwrite new capacity Invest along LNG value chain upstream and downstream of liquefaction Gas Supply Ensure reliable gas delivery to LNG facilities Commercial Operations & Asset Optimization Origination Business Development

7 Cheniere Corporate Structure Cheniere Energy, Inc. (CEI) (NYSE MKT: LNG) Cheniere Energy Partners, L.P. (NYSE MKT: CQP) Sabine Pass LNG, L.P. (SPLNG) Total TUA (1 Bcf/d) Chevron TUA (1 Bcf/d) SPL TUA (2 Bcf/d) Sabine Pass Liquefaction, LLC (SPL) Creole Trail Pipeline, L.P. (CTPL) Cheniere Energy Partners LP Holdings, LLC (NYSE MKT: CQH) Cheniere CCH Holdco II, LLC SPL Firm Transport (1.5 Bcf/d) BG SPA (286.5 Tbtu / yr) Gas Natural SPA (182.5 Tbtu / yr) KOGAS SPA (182.5 Tbtu / yr) GAIL (182.5 Tbtu / yr) Total (104.8 Tbtu / yr) Centrica (91.3 Tbtu / yr) CMI SPA Pertamina SPA (79.4 Tbtu / yr) Endesa SPA (117.3 Tbtu / yr) Iberdrola SPA (39.7 Tbtu / yr) Gas Natural (78.2 Tbtu / yr) Woodside (44.1 Tbtu / yr) EDF (40.0 Tbtu / yr) CMI SPA Cheniere CCH Holdco I, LLC Corpus Christi Liquefaction, LLC (CCL)(1) Cheniere Corpus Christi Holdings, LLC (CCH) CCL Firm Transport (2.25 Bcf/day) Cheniere Corpus Christi Pipeline, L.P. / GP, LLC (CCPL) CQP GP (& IDRs) Cheniere Marketing, LLC (CMI) Note: This organizational chart is provided for illustrative purposes only, is not and does not purport to be a complete organizational chart of Cheniere (1) EDP Train 3 SPA of ~0.77 mtpa not shown

8 BUSINESS UPDATE

9 Sabine Pass Liquefaction Project (SPL) Expansive Site with Significant Infrastructure  Located in Cameron Parish, LA  40 ft. ship channel 3.7 miles from coast  2 berths; 4 dedicated tugs  5 LNG storage tanks (~17 Bcfe of storage)  5.3 Bcf/d of pipeline interconnection Liquefaction Trains 1 – 5: Fully Contracted  Lump Sum Turnkey EPC contracts w/ Bechtel  Trains 1 & 2 EPC contract price ~$4.1B  Trains complete and in operation  Trains 3 & 4 EPC contract price ~$3.9B  Train 3 – Complete and in operation  Train 4 – Commissioning, operations expected 2H 2017  Train 5 EPC contract price ~$3.0B  65.4% Complete as of April 30, 2017  Operations estimated 2H 2019 Liquefaction Train 6: Permitted  FID upon obtaining commercial contracts, EPC contract, and financing Continued commitment to completing liquefaction trains on time and within budget Adjusted nominal capacity is expected to be 4.3-4.6 mtpa per train, using ConocoPhillips’ Optimized Cascade® Process. Please see the appendix for more detail on the adjusted nominal capacity. Trains 1, 2 & 3 In Operation Train 4 Commissioning Train 6 Fully Permitted Existing Operational Facility Train 5 Under Construction Note: EPC contract price as of March 31, 2017.

10 Sabine Pass Liquefaction Construction Progress Trains 1, 2, and 3 in Operation, Train 4 Expected 2H 2017, Train 5 Expected 2019 Note: Based on Guaranteed Substantial Completion Dates per EPC contract. Construction percentages complete as of April 30, 2017. DFCD Window Current Completion Schedule Progress Guaranteed Schedule Nov 2017 S ab in e P as s 2020 Aug 2019 2018 2019 2012 2013 2014 2015 2016 2017 Train 1 Train 2 Train 3 Train 4 Train 5  Stage 1 (Trains 1 & 2) complete with trains operational • First two trains completed 6 and 12 months ahead of guaranteed schedule, respectively  Stage 2 (Trains 3 & 4) 97.3% complete overall • Train 3 substantial completion occurred March 28, and Train 4 commissioning began in March • Engineering and procurement 100% complete, construction 97.4% complete  Stage 3 (Train 5) 65.4% complete overall • Soil improvement and piling completed 3 months ahead of schedule • Engineering 99.4% complete, procurement 95.3% complete, construction 22.3% complete Substantial Completion DFCD

11 Sabine Pass Liquefaction Project Execution – April 2017 Trains 1, 2 & 3 Operational Train 4 Commissioning Train 5 Under Construction Train 6 Fully Permitted

12 Corpus Christi LNG Terminal Attractive Land Position  >1,000 acres owned and/or controlled  2 berths, 4 LNG storage tanks (~13.5 Bcfe of storage) Key Project Attributes  45 ft. ship channel 14 miles from coast  Protected berth  Premier site conditions  23-mile pipeline will connect to several interstate and intrastate pipelines Liquefaction Trains 1-2: Under Construction  Lump Sum Turnkey EPC contracts w/ Bechtel  Trains 1 & 2 EPC contract price ~$7.8B  Operations estimated 2019  61.7% Complete as of April 30, 2017 Liquefaction Train 3: Fully Permitted  0.8 mtpa contracted to date  FID upon obtaining commercial contracts and financing, and finalizing EPC contract Liquefaction Trains 4-5: Initiated Regulatory Approval Process Artist’s rendition Under Construction Trains 1-2 Fully Permitted Train 3 Initiated Development Trains 4-5 Adjusted nominal capacity is expected to be 4.3-4.6 mtpa per train, using ConocoPhillips’ Optimized Cascade® Process. Please see the appendix for more detail on the adjusted nominal capacity. Note: EPC contract price as of March 31, 2017.

13 Corpus Christi Liquefaction Construction Progress Trains 1 & 2 Expected Completion 2019  Stage 1 (Trains 1 & 2) 61.7% complete overall • Engineering 100% complete, procurement 81.4% complete, construction 33.7% complete • Target substantial completion mid-2019, several months ahead of guaranteed completion dates and DFCD windows  Stage 2 (Train 3) fully permitted Note: Based on Guaranteed Substantial Completion Dates per EPC contract. Construction percentages complete as of April 30. 2017. (1) DFCD first window period varies by SPA. DFCD Window Opens(1) Current Completion Schedule Progress Guaranteed Schedule 2020 1H 2019 C or pu s C hr is ti 2H 2019 2018 2019 2012 2013 2014 2015 2016 2017 Train 1 Train 2

14 Corpus Christi Liquefaction Project Execution – April 2017 Stage 1: Trains 1& 2, Tanks A & C, Marine Berths Under Construction Stage 2 Train 3, Tank B Fully Permitted

15 LNG Operations  Transition the trains from construction management to operations management safely, efficiently, and effectively  Identify and incorporate lessons learned • Cross-functional team working to identify lessons learned • Implement improvements and optimize processes across trains and locations  Build operational best practices to increase LNG production reliability and efficiency • Identify bottlenecks and areas of opportunity to maintain maximum performance • Execute on efficiencies to maximize production • Develop longer-term capital investment strategy to alleviate bottlenecks  Adjusted nominal capacity expected to range between 4.3 and 4.6 mtpa per train • Preliminary overdesign assessment in progress; require warm weather data • Low end of range is driven by years with major planned maintenance  Performance to date has averaged ~110% of Henry Hub compared to allocated 115% • Based on early results, facility is expected to average ~9% to 9.5% • Supply is expected to average ~1% to 1.7%, not including price advantages

16 Sabine Pass Facility Sabine Pass Liquefaction Gas Supply Transportation into SPL (TBtu/day) Pipeline Contracted Capacity Total Capacity CTPL 1.530 1.530 NGPL 0.550 0.750 Transco 1.200 1.500 KMLP 0.600 1.200 Total 3.880 4.980  Diverse and redundant pipeline network has allowed SPL to reach into almost every North American supply basin  SPL has transacted at 36 different locations on 13 different pipelines  SPL’s redundancy on pipeline deliverability to the terminal provides the ability to adapt to changing market conditions and manage upstream interruptions  Delivered over 450 TBtu to the terminal with 99.9% scheduling efficiency  Assets in place enable effective management of changing day-to-day plant consumption related to commercial operations and commissioning; supply volumes have experienced day-over-day volatility of 250,000+ Dth/day  Storage assets and relationships with infrastructure partners have been key to managing dynamic volume requirements  Outperformed delivered supply cost target of 105% of Henry Hub

17 Corpus Christi Liquefaction Pipeline Infrastructure Secured  Sufficient firm pipeline capacity for Train 1 and Train 2 operations secured  Once CCPL is completed by end of 2017, Gas Supply ready to commission pipeline and compression needed for CCL commissioning in 2018  CCL has built out a geographically diverse infrastructure portfolio that reaches back to multiple supply sources  Building multiple supply paths into CCPL  Prepared for execution of additional commitments when commercialization of Train 3 is reached  CCPL Construction Update: • Project is ahead of schedule and within budget • Commissioning scheduled to begin in Q4 2017 NGPL Tennessee Gas HPL KM Tejas Transco Potential Supply Points

18 Marketing and Origination Singapore Houston, TX Santiago, Chile London, U.K. Washington, D.C. Chartered LNG Vessels SPAs with SPL and CCL Pre-Sold Volumes Expansive LNG Portfolio Available for Short, Mid, or Long-Term Sales on FOB or DES Basis  Firm volumes are used to structure term deals that require rapid time to market and increased flexibility in the initial stage of a term commitment  Excess volumes have seasonality with incremental volume available during the premium Northern Hemisphere winter – potential for marketing seasonal strips of cargoes  Capacity retained for optimization and operational flexibility  Build relationships and reputation of reliability and execution Tokyo, Japan

19 LNG MARKET OUTLOOK

20 Existing Capacity Newly Operational Under Construction 0 50 100 150 200 250 300 350 400 450 500 2016 2018 2020 2022 2024 2026 2028 2030 LNG Demand vs. Supply (mtpa) Pacific Basin SPAs Atlantic Basin SPAs 0 50 100 150 200 250 300 350 400 450 500 2016 2018 2020 2022 2024 2026 2028 2030 Global LNG Demand vs. SPAs (mtpa) Global LNG Demand Estimate Market tightening New Supply (127 mtpa) Source: Cheniere Research, Global Data, World Bank, Wood Mackenzie Global LNG market needs competitive new supplies to fill the approaching supply gap Expiration of contracts will result in significant portfolio gaps ~90 mtpa of recontracting demand in addition to underlying market growth LNG Fundamentals are Supportive of Long-Term Growth  Projects under construction not sufficient to satisfy growth and ensure stability of prices  Expiring contracts create incremental opportunity, especially in Asia Total Uncommitted Demand (214 mtpa)

21 - 50 100 150 200 250 300 350 400 450 500 2000 2005 2010 2015 2020 2025 2030 mtpa Demand Forecast to Grow More than 200 mtpa by 2030 Driven by Supplemental & Growth Markets LNG Market Segmentation Traditional Flex Growth Supplemental Type Characteristics Locations Demand Growth (mtpa) Supplemental Countries with maturing indigenous resource bases require new sources of gas Indonesia Malaysia Egypt Pakistan Thailand Bahrain Southeast Europe... +85 Growth Growing economies seeking cleaner and more diverse fuel mix China India +84 Flex Seasonal / weather influenced and price sensitive demand Northwest Europe Brazil Argentina… +13 Displacement Diversifying energy mix away from oil / coal Caribbean countries Kuwait South Africa +20 Bunkering Adopting cleaner ship fuels due to stricter emission standards Singapore Gibraltar Tenerife… +8 Traditional Legacy importers with flat to declining demand Japan Korea Taiwan +12 Source: Cheniere Research Note: Projected demand growth between 2015 and 2030

22 U.S. LNG Expected to be Key in Satisfying Robust Global Gas Growth Source: Cheniere Research, Global Data, World Bank, Wood Mackenzie Note: Conversion from GW to Bcf/d assumes thermal efficiency of 61% (1) China plans to grow share of gas to 15% by 2030; India in the next few years 0% 1% 2% 3% 4% 5% 6% Emerging Asia Africa Central Asia MENA Canada & US Latam & Caribbean Europe Asia Forecast GDP Growth Levels by Region 2015-2020 2021-2025 Emerging economies drive global growth and gas demand China and India plan to grow gas share from 6% to 15% in energy mix(1) Creative LNG contracting structures, competitive supplies & technology solutions alleviate risks and cost burden 0.0 1.3 2.7 4.0 5.4 6.7 8.0 9.4 10.7 - 10 20 30 40 50 60 70 80 2017 2018 2019 2020 2021 2022 2023 2024 2025 B cf /d G W Projected Gas-Fired Capacity Additions by Region 2017-2025 Africa Asia Europe Latam & Caribbean MENA

23 STRATEGIC ADVANTAGES AND GROWTH

24 $7.5 $8.6 $11.4 $12.2 $10.4 $8.5 $9.6 $12.2 $13.2 $13.2 $5 $10 $15 $20 Cheniere Gulf Coast Southeast Asia Western Canada Northwest Australia East Africa LN G P ri ce s ($ /M M B tu )  U.S. natural gas is abundant and cost competitive with other sources of global supply  U.S. Gulf Coast liquefaction project costs are also significantly lower due to less project development needed and access to affordable and skilled labor  Estimated delivered LNG cost to Asia from Cheniere expansion trains is competitive compared to other proposed new build LNG projects in Asia, Canada, Australia and Africa Representative onshore projects; estimated breakeven LNG pricing range, delivered at terminal in Asia Source: Cheniere interpretation of Wood Mackenzie data, company filings and investor materials. Note: Breakeven prices derived assuming unlevered after-tax returns of 8% for U.S. projects and 10% on all other projects over construction plus 20 years of operation at 90% utilization. Henry Hub at $3.00/MMBtu and shipping charter cost at $80,000 / day Cheniere Offers Low Cost Incremental LNG Liquefaction Capacity Greenfield Projects Expansion Projects Estimated New Build LNG Project Breakeven Supply Cost

25 Leveraging Infrastructure and Expertise: A Key Competitive Advantage Leverage Existing Infrastructure to Enable Competitive, Incremental Liquefaction Capacity  Able to leverage existing network to supply incremental gas to feed additional trains • Significant investment in infrastructure – one of largest firm pipeline transportation capacity holders in U.S. with more than 5 Bcf/d of firm capacity on 8 pipeline systems • Early mover advantage – difficult and costly to replicate  Control of significant gas infrastructure • Supply diversity through access to key basins • Procurement redundancy to ensure plant reliability • Access to gas storage to manage varying production levels and unplanned outages  Premier LNG provider with proven track record and economies of scale • ~$30 billion of project capital raised • Project execution ahead of schedule and within budget • Experienced workforce  Uniquely able to leverage existing infrastructure and add incremental liquefaction capacity • Site • Utilities • Marine Facilities • Pipeline • O&M Infrastructure

26 Cheniere Full Service a Structural Competitive Advantage Liquefaction Shipping/DES Sales LNG to Power U.S. Pipeline, Storage and Gas Supply  One of largest pipeline capacity holders in U.S.: more than 5 Bcf/d  More than $400 million in annual capacity payments  Manage intra-month volume variance and price exposure  3 trains in operation, 1 train in commissioning, and 3 trains under construction  All trains to date completed on time and within budget  Growing operational efficiency allows for seamless expansion of already permitted capacity  Cheniere Marketing delivered approximately 50 cargoes from Sabine Pass by end of Q1 2017  Chartered over 30 LNG tankers since startup  Cheniere Marketing has excess volumes ready to sell FOB or DES  Global origination team targeting LNG-to- power projects  Advantaged to provide full service LNG supply model  Opportunities along the LNG value chain to improve and optimize core LNG platform Feed Gas FOB sales DES sales

27 -10 0 10 20 30 40 50 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 mtpa LNG Capacity FID Incremental LNG Supply Forecast Source: Cheniere interpretation of Wood Mackenzie data (Q1 2017)  LNG projects have long lead times from sanction to first LNG – generally 4-6 years  Long lead time to new supply means once the market is tight it will take 4+ years for supply to adjust Elevated Rate of FIDs Low Rate of FIDs Low Rate of FIDs? Elevated Rate of FIDs FID slowdown started in 2014 - setting up a tightening cycle post- 2020 Cheniere Has Speed To Market Advantage as Balance Tightens Cheniere ideally positioned with two fully-permitted trains (~9 mtpa)

28 Additional Land for Potential Expansion Stage 3 In Development Stage 2: Train 3 Fully Permitted Stage 1: Trains 1 & 2 Under Construction Corpus Christi Expansion Corpus Christi Property Allows for Major Expansion of Cheniere’s Existing Footprint Stage 2  Train 3 fully permitted, partially commercialized  Brownfield economics with significant infrastructure already installed Stage 3  Trains 4 and 5 permitting process initiated Potential Expansion  Recently acquired rights to additional ~500 acres of upland and waterfront property adjacent to Corpus Christi site  Space to approximately double existing capacity

29 Sabine Pass Expansion Sabine Pass Property Allows for Major Expansion of Cheniere’s Existing Footprint Train 6  Fully permitted  Attractive expansion economics Potential Expansion  Rights to additional 524 acres of land east of Sabine Pass site  Existing footprint allows third LNG berth  Space to approximately double existing capacity Trains 1, 2 & 3 In Operation Train 4 Commissioning Additional Land for Potential Expansion Train 6 Fully Permitted Existing Operational Facility Train 5 Under Construction

30 Midscale Liquefaction Project – Cost Analysis in Process  Began Midscale project evaluation in early 2016  Reviewed 18 proposals from potential contractors  KBR/Siemens/Chart Consortium approved to continue with full FEED and EPC proposal to be completed September 2017  Initial capital cost estimates are competitive with Corpus Train 3; full lifecycle cost analysis is in process  Midscale Project encompasses up to 7 LNG trains that could leverage existing sites and infrastructure  Modular design would provide 1.4 mtpa of expected LNG production capacity per train, for a total potential expected capacity of 9.8 mtpa if all 7 trains were built, with an expected footprint comparable to 2 large liquefaction trains Artist Rendition 7 Midscale Trains

31 Cheniere’s Existing LNG Platform Creates Advantages for Growth Construction Operations  Significant infrastructure investment at Corpus Christi and Sabine Pass sites • Site preparation • Utilities • Storage • Shipping  Additional expansion at very competitive investment: ~$500-600/ton(1)  Positioning both sites for future growth  Ability to scale quickly and effectively  Scale helps reduce operating expense –  Operating expense associated with expansion trains ~30% of initial train • $60 - $70mm/year of savings moving from T1 to each incremental train  Leverage existing gas procurement infrastructure and early mover advantage Finance Commercial  Expected excess Cheniere Marketing capacity across platform allows LNG deliveries now  Conditions precedent flexibility – portfolio sales  Tenor flexibility – short, medium, long term  Counterparty credit flexibility based on price & payment terms  Lower capitalized financing costs • Initial Interest during Construction and Financing Fees are ~$200/ton; not required for initial expansion • Funding construction from DCF significantly reduces these costs and reduces leverage metrics  Highly visible and significant cash flows provide financing flexibility (1) Includes EPC and owner’s cost

32 FINANCIAL UPDATE

33 Cheniere Debt Summary – June 2017 Cheniere Energy, Inc. (CEI) (NYSE MKT: LNG) Cheniere Energy Partners, L.P. (NYSE MKT: CQP) Sabine Pass LNG, L.P. (SPLNG) Total TUA (1 Bcf/d) Chevron TUA (1 Bcf/d) SPL TUA (2 Bcf/d) Trains 1 - 5 Debt  $2.0B Notes due 2021 (5.625%)  $1.0B Notes due 2022 (6.250%)  $1.5B Notes due 2023 (5.625%)  $2.0B Notes due 2024 (5.750%)  $2.0B Notes due 2025 (5.625%)  $1.5B Notes due 2026 (5.875%)  $1.5B Notes due 2027 (5.000%)  $1.35B Notes due 2028 (4.200%)  $0.8B Notes due 2037 (5.000%)  $1.2B Working Capital Facility due 2020 Sabine Pass Liquefaction, LLC (SPL) Creole Trail Pipeline (CTPL) Cheniere Energy Partners LP Holdings, LLC (NYSE MKT: CQH) Cheniere CCH Holdco II, LLC CEI Revolver  $0.75B senior secured revolving credit facility due 2021 Convertible Debt  $1.0B PIK Convertible Notes due 2021 (4.875%)  $0.6B Convertible Notes due 2045 (4.250%) SPL Firm Transport (1.5 Bcf/d) BG SPA (286.5 Tbtu / yr) Gas Natural SPA (182.5 Tbtu / yr) KOGAS SPA (182.5 Tbtu / yr) GAIL (182.5 Tbtu / yr) Total (104.8 Tbtu / yr) Centrica (91.3 Tbtu / yr) CMI SPA Pertamina SPA (79.4 Tbtu / yr) Endesa SPA (117.3 Tbtu / yr) Iberdrola SPA (39.7 Tbtu / yr) Gas Natural (78.2 Tbtu / yr) Woodside (44.1 Tbtu / yr) EDF (40.0 Tbtu / yr) CMI SPA Cheniere CCH Holdco I, LLC Trains 1 - 2 Equity  $1.0B Senior Secured Convertible Notes due 2025 Trains 1 - 2 Debt  $4.6B Credit Facility due 2022(2)  $1.3B Notes due 2024 (7.000%)  $1.5B Notes due 2025 (5.875%)  $1.5B Notes due 2027 (5.125%)  $0.35B Working Capital Facility due 2021 Corpus Christi Liquefaction, LLC (CCL)(3) Sr Secured Credit Facilities  $2.8B Credit Facilities due 2020 CEI Cash Balance: ~$0.9B(1) Cheniere Corpus Christi Holdings, LLC (CCH) CCL Firm Transport (2.25 Bcf/day) Cheniere Corpus Christi Pipeline, L.P. / GP, LLC (CCPL) Note: This organizational chart is provided for illustrative purposes only, is not and does not purport to be a complete organizational chart of Cheniere. (1) As of March 31, 2017 (2) Credit Facility due on the earlier of two years after Project Completion or 2022. (3) EDP Train 3 SPA of ~0.77 mtpa not shown. CQP GP (& IDRs) Cheniere Marketing, LLC (CMI)

34 Financial Priorities: Past and Present Prior Goals (Last 2 Years) Evolve Capital Structure and Execute Achieve Investment Grade (“IG”) Ratings at Sabine Pass Liquefaction, LLC • S&P, Fitch, and Moody’s all upgraded SPL senior secured debt to investment grade Term out remainder of 2020 SPL Credit Facilities and launch inaugural Cheniere Corpus Christi Holdings, LLC bond offering • ~$10B of bonds issued at SPL and CCH in last ~2 years • SPL Credit Facilities terminated Enhance and ensure fortress liquidity across Cheniere complex • ~$0.9B of unrestricted CEI cash as of 3/31/17 • Fully termed out 2020 SPL credit facility, expected to permit distributions of excess cash flow at SPL by end of 2017 • $1.2B SPL working capital facility closed in September 2015 • $115MM Cheniere Energy Partners, L.P. revolver secured in February 2016 • $350MM CCH working capital facility closed in December 2016 for gas procurement credit support • $750MM CEI revolver closed in March 2017 Enhance financial transparency • Quarterly earnings calls, Analyst Day, and financial guidance Present Goals Reinvest and Return Capital Reinvest and return capital while maintaining long term sustainable balance sheet • Fortress liquidity and sustainable leverage priority #1 • Projected returns via share or unit repurchases will be benchmark against which capital allocation decisions measured Analyze opportunities to reduce complexity of corporate structure • Acquired additional 2.6% ownership of CQH from reverse inquiries after termination of CQH buy-in efforts Opportunistically spread out debt maturities to better match annual cash flows • Plan to reduce CQP and CCH bank debt maturity towers opportunistically and free up bank capital for future growth    

35 AA- to AA+ Rated 20.2% A- to A+ Rated 20.3% BBB- to BBB+ Rated 59.5% Balance Sheet Underpinned by Strong Counterparty Credits Cheniere Counterparty Exposure SPA Customers Sabine Pass Liquefaction Corpus Christi Liquefaction Cheniere 11 External SPA Customers(1) (BBB / Baa2 / BBB+) (NR / Baa3 / BBB-) ( AA- / Aa2 / AA-) (A+ / Aa3 / AA-) (BBB+ / Baa1 / A-) (A / WR / A+) (BBB / Baa2 / BBB+) (BBB+ / Baa1 / BBB+) (BBB / WR / BBB+) (BBB+ / Baa1 / BBB+) (A- / A3 / A-) (BBB-/ Baa3 / BBB-)  All 20-year “take or pay” style SPAs with investment grade (“IG”) counterparties  Average portfolio rating of A / A3 / A and BBB / Baa2 / BBB+ for SPL and CCL, respectively  100% of ~$4.3B(2) of annual fixed fees comes from counterparties rated IG by at least two of the three major agencies (S&P, Moody’s, Fitch) Note: Ratings denote S&P, Moody’s, Fitch (1) Shown as percent of annual fixed fees (2) Annual third-party fixed fees from SPA customers of both Sabine Pass Liquefaction and Corpus Christi Liquefaction

36 Long-term Capital Structure Plan  Utilize leverage capacity at CQP and CEI (the corporate levels) to delever SPL and CCH (the project levels) over the next 5-10 years  Debt incurrence test will force the deleveraging of SPL and CCH over time at 1.5x/1.4x DSCR  By migrating project debt up to CQP and CEI (subject to ≤ 5.0x decon. debt / EBITDA constraint), project level debt amortization requirements can be pushed out to the mid to late 2020s  Plan maximizes value to equity holders while adhering to indenture amortization requirements at the project levels  Investment grade ratings at the project levels and strong high yield ratings (BB / Ba) at the corporate levels can be achieved and maintained  This framework provides CEI significant free cash flow to invest and grow which can further defer substantial debt pay down, while at the same time returning capital to shareholders via share repurchases and/or dividends By taking advantage of leverage capacity at the corporate levels, project level debt amortization not required until the mid to late 2020s, even with no growth beyond 7 trains

37 $8 .4 – $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 CCH - Credit Facilities $1 .2 5 $1 .5 $1 .5 $4 .6 – $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 $9.0 CCH - Credit Facilities CCH - Senior Notes $1 .7 $0.4 $0.4 $4 .6 $5 .0 $2 .0 $1 .0 $1 .5 $2 .0 $2 .0 – $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 SPLNG - Senior Notes CTPL - Term Loan SPL - Credit Facilities SPL - Senior Notes $2.8 $2 .0 $1 .0 $1 .5 $2 .0 $2 .0 $1 .5 $1 .5 $1 .3 5 $0 .8 – $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 CQP - Credit Facilities SPL - Senior Notes Where We’ve Been: Maturity Profile Progression CQP / SPL Debt Maturity Profile Progression: H1 2016 to Today Today Successfully refinanced SPL, SPLNG and CTPL in full and began CCH refinancing; no maturities until 2020 H1 2016 Today CCH Debt Maturity Profile Progression: H1 2016 to Today H1 2016 Projected SPL Run-Rate Adjusted EBITDA Projected CQP Run-Rate Cons. Adjusted EBITDA Projected CCH Run-Rate Adjusted EBITDA Note: $ in billions. Adjusted EBITDA is a non-GAAP measure. A definition of Adjusted EBITDA is included in the financial appendix. We have not made any forecast of net income on a run-rate basis, which would be the most directly comparable financial measure under GAAP, and we are unable to reconcile differences between forecasts of run-rate Adjusted EBITDA and net income. (1) Credit Facility due on the earlier of two years after Project Completion or 2022. (1) (1)

38 7 Trains ($bn, except per share amounts or unless otherwise noted) SPL T1-5, CCH T1-2 CEI Consolidated Adjusted EBITDA $3.8 - $4.1 Less: CQP/CQH Minority Interest ($0.9) - ($0.9) Less: CQP/SPL Interest Expense ($0.9) Less: CEI Interest Expense/Other ($0.0) Less: CCH Interest Expense ($0.5) CEI Distributable Cash Flow $1.5 - $1.7 CEI Distributable Cash Flow per Share(1) $5.40 - $6.30 CQP Distributable Cash Flow per Unit $3.00 - $3.20 CQH Distributable Cash Flow per Share $2.60 - $2.60 Run Rate Guidance: 7 Train Case Run rate start date assumed to be first full year of SPAs for all trains (early 2020s) Note: Range driven by production. CMI margin assumed at $2.50/MMBtu, before 80/20 profit-sharing tariff with SPL/CCH. Interest rates at SPL and CCH for refinancings assumed to be 5.50% and 5.75%, respectively. Refer to appendix for additional detail on forecasting assumptions. Interest expense as shown above is cash interest expense for each entity on a deconsolidated basis. Adjusted EBITDA, Distributable Cash Flow and Distributable Cash Flow per Share and Unit are non-GAAP measures. Definitions of these non-GAAP measures are included in the financial appendix. We have not made any forecast of net income on a run-rate basis, which would be the most directly comparable financial measure under GAAP, and we are unable to reconcile differences between these run rate forecasts and net income. (1) Assumed share count of ~273mm shares; see Forecasting Points slide in financial appendix for conversion assumptions

39 APPENDIX

40 Sabine Pass Liquefaction Project Corpus Christi Liquefaction Project 22.5 9.0 Trains 1 – 3: Operating Train 4: Commissioning Train 5: Under Construction (2H 2019) Trains 1-2: Under Construction (2019) Creole Trail NGPL Transco Kinder Morgan LA Corpus Christi Pipeline Tennessee NGPL Transco KM Tejas Cheniere Liquefaction Projects at a Glance Liquefaction Technology EPC Contractor Financial Partner Investment Grade SPA Counterparties Maintenance Contract Servicer Total mtpa under construction or operating Firm Pipeline Capacity Project Completion

41 Sabine Pass Liquefaction SPAs BG Gulf Coast LNG Gas Natural Fenosa Korea Gas Corporation GAIL (India) Limited Total Gas & Power N.A. Centrica plc Annual Contract Quantity (MMbtu) 286,500,000 (1) 182,500,000 182,500,000 182,500,000 104,750,000 (1) 91,250,000 Annual Fixed Fees (2) ~$723 MM (3) ~$454 MM ~$548 MM ~$548 MM ~$314 MM ~$274 MM Fixed Fees $/MMBtu(2) $2.25 - $3.00 $2.49 $3.00 $3.00 $3.00 $3.00 LNG Cost 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH Term of Contract (4) 20 years 20 years 20 years 20 years 20 years 20 years Guarantor BG Energy Holdings Ltd. Gas Natural SDG S.A N/A N/A Total S.A. N/A Guarantor/Corporate Credit Rating (5) A/WR/A+ BBB/Baa2/BBB+ AA-/Aa2/AA- NR/Baa3/BBB- A+/Aaa3/AA- BBB+/Baa1/A- Fee During Force Majeure Up to 24 months Up to 24 months N/A N/A N/A N/A Contract Start Train 1 + additional volumes with Trains 2,3,4 Train 2 Train 3 Train 4 Train 5 Train 5 (1) BG has agreed to purchase 182,500,000 MMBtu, 36,500,000 MMBtu, 34,000,000 MMBtu and 33,500,000 MMBtu of LNG volumes annually upon the commencement of operations of Trains 1, 2, 3 and 4, respectively. Total has agreed to purchase 91,250,000 MMBtu of LNG volumes annually plus 13,400,000 MMBtu of seasonal LNG volumes upon the commencement of Train 5 operations. (2) A portion of the fee is subject to inflation, approximately 15% for BG Group, 13.6% for Gas Natural Fenosa, 15% for KOGAS and GAIL (India) Ltd and 11.5% for Total and Centrica. (3) Following commercial in service date of Train 4. BG will provide annual fixed fees of approximately $520 million during Trains 1-2 operations and an additional $203 million once Trains 3-4 are operational. (4) SPAs have a 20 year term with the right to extend up to an additional 10 years. Gas Natural Fenosa has an extension right up to an additional 12 years in certain circumstances. (5) Ratings are provided by S&P/Moody’s/Fitch and subject to change, suspension or withdrawal at anytime and are not a recommendation to buy, hold or sell any security. ~20 mtpa “take-or-pay” style commercial agreements ~$2.9B annual fixed fee revenue for 20 years

42 Corpus Christi Liquefaction SPAs PT Pertamina (Persero) Endesa S.A. Iberdrola S.A. Gas Natural Fenosa Woodside Energy Trading Électricité de France EDP Energias de Portugal S.A. Annual Contract Quantity (TBtu) 79.36 117.32 39.68 78.20 44.12 40.00 40.00 Annual Fixed Fees (1) ~$278 MM ~$411 MM ~$139 MM ~$274 MM ~$154 MM ~$140 MM ~$140 MM Fixed Fees $/MMBtu (1) $3.50 $3.50 $3.50 $3.50 $3.50 $3.50 $3.50 LNG Cost 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH Term of Contract (2) 20 years 20 years 20 years 20 years 20 years 20 years 20 years Guarantor N/A N/A N/A Gas Natural SDG, S.A. Woodside Petroleum, LTD N/A N/A Guarantor/Corporate Credit Rating (3) BBB-/Baa3/BBB- BBB/WR/BBB+ BBB+/Baa1/BBB+ BBB/Baa2/BBB+ BBB+/Baa1/BBB+ A-/A3/A- BB+/Baa3/BBB- Contract Start Train 1 / Train2 Train 1 Train 1 / Train 2 Train 2 Train 2 Train 2 Train 3 SPA progress: ~8.42 mtpa “take-or-pay” style commercial agreements ~$1.5B annual fixed fee revenue for 20 years (1) 12.75% of the fee is subject to inflation for Pertamina; 11.5% for Woodside; 14% for all others (2) SPA has a 20 year term with the right to extend up to an additional 10 years. (3) Ratings are provided by S&P/Moody’s/Fitch and subject to change, suspension or withdrawal at anytime and are not a recommendation to buy, hold or sell any security.

43 Liquefaction Capacity 4.5 mtpa Maintenance Adjustments Reliability Adjustments 4.3 mtpa 4.6 mtpa Planned Maintenance Unplanned Maintenance Nominal Capacity Adjusted Capacity What adjusted capacity can be expected from Cheniere’s 7 trains?  Adjusted nominal capacity is expected to range between 4.3 and 4.6 mtpa in run-rate years • Preliminary overdesign assessment in progress; require warm weather data • Low end is driven by years with major planned maintenance • Debottlenecking opportunities have been identified from Sabine Pass operating trains Debottleneck Overdesign Process Conditions

44 FINANCIAL APPENDIX

45 Consolidated vs. Deconsolidated CEI CCH Consolidated Deconsolidated SPL CQP and CQH SPLNG CTPL CMI CCPL CCL Minority Interest

46 Note: Assumes approximately 4.5 mtpa/train production case (1) Assumes current implied gross margin by CMI through 2019 and $2.50 gross margin thereafter, before 80/20 profit-sharing tariff with SPL/CCH $2.3 $0.6 $1.1 $1.2 $0.8 $1.3 $0.9 $0.8 $4.0 – $2.0 $4.0 $6.0 $8.0 Sources Uses $bn CEI Deconsolidated Five Year Sources and Uses Projected Available Cash Generation: 2017 – 2021 CEI G&A/Other/Interest Expense Management Fees Available Cash  Grow (CCH T3, etc.)  Buy back Stock  Pay Dividend CCH Distributions Sources: ~$6.5 billion CQP GP / IDR Distributions CMI Cash Flow(1) CEI Beginning Cash on Hand CQH Dividends and Tax Sharing Payments CCH Equity Contribution Agreement Uses: ~$6.5 billion ~$4.0 billion of cash available for distribution over the 5-year planning horizon

47 7 Trains utilizing Corporate Debt Capacity CCH T3 Utilizing Corporate Debt Capacity CCH Debt Amortization Start at CCH Mid 2020s Late 2020s Migrated Debt to CEI ($bn) ~$2.0 - $2.5 ~$2.3 - $3.3 Debt at CCH(2) ~$6.5 - $7.5 ~$7.5 - $9.0 Debt at CEI(3) ~$2.6 - $3.1 ~$2.9 - $3.9 7 Trains 8 Trains ($bn, except per share amounts or unless otherwise noted) SPL T1-5, CCH T1-2 SPL T-5, CCH T1-3 CEI Consolidated Adjusted EBITDA $3.8 - $4.1 $0.4 - $0.6 $4.2 - $4.7 Less: CQP/CQH Minority Interest ($0.9) - ($0.9) $0.0 ($0.9) - ($0.9) Less: CQP/SPL Interest Expense ($0.9) $0.0 ($0.9) Less: CEI Interest Expense / Other ($0.0) $0.0 ($0.0) Less: CCH Interest Expense ($0.5) ($0.1) ($0.7) CEI Distributable Cash Flow $1.5 - $1.7 $0.3 - $0.5 $1.8 - $2.2 CEI Distributable Cash Flow per Share $5.40 - $6.30 $1.00 - $1.70 $6.40 - $8.00 CCH T3 (1) Run Rate Guidance: Impact of Additional Train at CCH Additional Run-Rate Distributable Cash Flow Run rate start date assumed to be first full year of operations for all trains (early 2020s) Additional Debt Capacity Note: For CCH T3, range driven by % of train contracted, SPA price and production. CMI margin at $2.50/MMBtu, before 80/20 profit-sharing tariff with CCH. Run rate CEI share count ~273MM shares. Adjusted EBITDA, Distributable Cash Flow and Distributable Cash Flow per Share are non-GAAP measures. Definitions of these non-GAAP measures are included in the financial appendix. We have not made any forecast of net income on a run-rate basis, which would be the most directly comparable financial measure under GAAP, and we are unable to reconcile differences between these run rate forecasts and net income. Interest expense as shown above is cash interest expense for each entity on a deconsolidated basis. (1) Assumes 60/40 debt/equity funding (2) Includes projected future bonds to term out remaining CCH credit facility (3) Assumes EIG Notes and RRJ Notes are converted into LNG equity during debt migration time period. See Forecasting Points slide already in financial appendix for conversion assumptions

48 ($bn) 7 Trains without utilizing Corporate Debt Capacity 7 Trains utilizing Corporate Debt Capacity SPL Debt Amortization Start at SPL (1.5x DSCR) Early 2020s Mid-Late 2020s Migrated Debt to CQP (5.0x debt / EBITDA) – ~$3.0 - $4.0 Debt at SPL (project) $13.7 ~$9.7 - $10.7 Debt at CQP (corporate) $2.8 ~$5.8 - $6.8 CCH Debt Amortization Start at CCH (1.4x DSCR) Early 2020s Mid 2020s Migrated Debt to CEI (5.0x debt / EBITDA) – ~$2.0 - $2.5 Debt at CCH(1) (project) ~$9.0 - $9.5 ~$6.5 - $7.5 Debt at CEI(2) (corporate) $0.5 ~$2.6 - $3.1 Summary Projected Amortization Requirements at Project Levels Debt migration from the projects to corporates provides runway before amortization must commence at project levels; expansion trains can further defer amortization requirements Current plan until FID is reached on expansion trains Note: Amortization does not include CQP credit facility amortization. (1) Includes projected future bonds to term out remaining CCH credit facility (2) Assumes EIG Notes and RRJ Notes are converted into LNG equity during debt migration time period. See Forecasting Points slide already in financial appendix for conversion assumptions

49 Forecasting Points EIG Notes Conversion  CCH Holdco II Notes (EIG Notes) convert into ~20mm LNG shares in 2020 at estimated $94 / share (ultimate principal balance of ~$1.7B) • Conversion at a 10% discount to LNG’s share price • Only 50% of the EIG Notes can be converted at initial conversion and subsequent conversions cannot occur for 90 days after conversion date RRJ Notes Conversion  CEI Convertible Unsecured Notes (RRJ Notes) convert into ~15mm LNG shares in 2020 at estimated $94 / share (ultimate principal balance of ~$1.4B) Class B Conversion  CQP Class B units owned by Blackstone convert to ~200mm common units in Q3 2017  CQP Class B units owned by CEI/CQH convert to ~90mm common units in Q3 2017  As of December 31, 2016, CEI’s and CQH’s federal NOL carryforwards are equal to $3.8 billion and $1.7 billion, respectively  CQH tax sharing payments to CEI occur prior to CEI-level taxes • CQH’s NOL will be exhausted before CEI’s NOL which causes incremental free cash flow to CEI General Assumptions CEI Cash Tax Payments Begin Late 2020s CQH Tax Sharing Payments Begin Early 2020s 2020 - 2040 Tax Rate Percentage of Pre-Tax Cash Flow CEI High Teens CQH Mid 20%s

50 Reconciliation to Non-GAAP Measures Regulation G Reconciliations In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying news release contains non-GAAP financial measures. Adjusted EBITDA, Distributable Cash Flow and Distributable Cash Flow per Share are non-GAAP financial measures that we use to facilitate comparisons of operating performance across periods. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated. Adjusted EBITDA represents net income (loss) attributable to Cheniere before net income (loss) attributable to the non-controlling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash items, other non- operating income or expense items, and other items not otherwise predictive or indicative of ongoing operating performance, as detailed in the following reconciliation. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP and is not necessarily comparable to similarly titled measures reported by other companies. We believe Adjusted EBITDA provides relevant and useful information to management, investors and other users of our financial information in evaluating the effectiveness of our operating performance in a manner that is consistent with management’s evaluation of business performance. We believe Adjusted EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization which vary substantially from company to company depending on capital structure, the method by which assets were acquired and depreciation policies. Further, the exclusion of certain non-cash items, other non- operating income or expense items, and items not otherwise predictive or indicative of ongoing operating performance enables comparability to prior period performance and trend analysis. Adjusted EBITDA is calculated by taking net income (loss) attributable to common stockholders before net income (loss) attributable to non-controlling interest, interest expense, net of capitalized interest, changes in the fair value and settlement of our interest rate derivatives, taxes, depreciation and amortization, and adjusting for the effects of certain non-cash items, other non-operating income or expense items, and other items not otherwise predictive or indicative of ongoing operating performance, including the effects of modification or extinguishment of debt, impairment expense, changes in the fair value of our commodity and foreign exchange currency (“FX”) derivatives and non-cash compensation expense. We believe the exclusion of these items enables investors and other users of our financial information to assess our sequential and year-over-year performance and operating trends on a more comparable basis and is consistent with management’s own evaluation of performance. Distributable Cash Flow is defined as cash received, or expected to be received, from its ownership and interests in CQP, CQH and Cheniere Corpus Christi Holdings, LLC, cash received (used) by its integrated marketing function (other than cash for capital expenditures) less interest, taxes and maintenance capital expenditures associated with Cheniere and not the underlying entities. Management uses this measure and believes it provides users of our financial statements a useful measure reflective of our business’s ability to generate cash earnings to supplement the comparable GAAP measure. Distributable Cash Flow per Share is calculated by dividing Distributable Cash Flow by the weighted average number of common shares outstanding. We believe Distributable Cash Flow is a useful performance measure for management, investors and other users of our financial information to evaluate our performance and to measure and estimate the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. Management uses this measure and believes it provides users of our financial statements a useful measure reflective of our business’s ability to generate cash earnings to supplement the comparable GAAP measure. Distributable Cash Flow is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP and is not necessarily comparable to similarly titled measures reported by other companies. Non-GAAP measures have limitations as an analytical tool and should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and should be evaluated only on a supplementary basis. Adjusted EBITDA The following table reconciles our Adjusted EBITDA to U.S. GAAP results for the three months ended March 31, 2017 and 2016 (in millions): Three Months Ended March 31, 2017 2016 Net income (loss) attributable to common stockholders $ 54 $ (321 ) Net income (loss) attributable to non-controlling interest 118 (28 ) Income tax provision — 1 Interest expense, net of capitalized interest 165 76 Loss on early extinguishment of debt 42 1 Derivative loss (gain), net (1 ) 181 Other income (2 ) (1 ) Income (loss) from operations $ 376 $ (91 ) Adjustments to reconcile income (loss) from operations to Consolidated Adjusted EBITDA: Depreciation and amortization expense 70 24 Loss from changes in fair value of commodity and FX derivatives, net 33 — Total non-cash compensation expense 4 12 Impairment expense — 10 CEI Adjusted EBITDA $ 483 $ (45 )

51 CHENIERE ENERGY, INC. INVESTOR RELATIONS CONTACTS Randy Bhatia Vice President, Investor Relations – (713) 375-5479, randy.bhatia@cheniere.com Megan Light Manager, Investor Relations – (713) 375-5492, megan.light@cheniere.com