April 2014 Cheniere Energy

Forward Looking Statements 2 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 facts, included 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 to pay dividends to its shareholders;  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 liquefaction facilities, or any expansions thereof, by certain dates or at all;  statements that Cheniere Energy, Inc. expects to commence or complete construction of its proposed liquefaction facilities or other projects by certain dates or at all;  statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of liquefied natural gas (“LNG”) imports into or exports from North America and other countries worldwide, regardless of the source of such information, or the transportation or demand for and prices related to natural gas, LNG or other hydrocarbon products;  statements regarding any financing transactions or arrangements, or ability to enter into such transactions;  statements relating to the construction of our natural gas liquefaction trains (“Trains”), or modifications to the Creole Trail 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, liquefaction or storage capacities that are, or may become, subject to contracts;  statements regarding counterparties to our commercial contracts, construction contracts and other contracts;  statements regarding our planned construction of additional Trains, including the financing of such Trains;  statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;  statements regarding any business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections or objectives, including anticipated revenues and capital expenditures and EBITDA, 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,” “opportunities,” “plan,” “potential,” “project,” “propose,” “subject to,” “strategy,” 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 21, 2014, 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 under the securities laws, we undertake no obligation to publicly update or revise any forward- looking statements.

Summary Organizational Structure 3 Cheniere Energy, Inc. (NYSE: LNG) Sabine Pass LNG, L.P. (“SPLNG”) Sabine Pass Liquefaction, LLC (“SPL”) Cheniere Energy Partners, L.P. (NYSE: CQP) Cheniere Creole Trail Pipeline, L.P. (“CTPL”) Corpus Christi Liquefaction, LLC (“CCL”) Cheniere Marketing, LLC (“CMI”) Cheniere Energy Partners GP, LLC 100% Interest 100% Interest 100% Interest 100% Interest (1) Current ownership interest. As Class B units accrete Blackstone will increase its ownership percentage, and the public and CQH will have reduced ownership percentages. See Slide 37.  Liquefaction facilities  13.5 mtpa under development  Regasification facilities  4.0 Bcf/d of capacity  17.0 Bcf of storage  2 berths  Liquefaction facilities  18 mtpa under construction  9 mtpa under development Cheniere Energy Partners LP Holdings, LLC (NYSE: CQH)  1.5 Bcf/d capacity for SPL  Provides gas supply for SPL 84.5% Interest 55.9% Interest (1) 2.0% Interest & Incentive Dist. Rights  Int’l LNG marketing  2 mtpa contract with SPL  Three 5-year LNG vessel charters  Blackstone (BX) 29.0% (1)  Public 13.1% (1) Public 15.5% Next Developments

Projected Global LNG Demand Growth 4 Regional LNG Import Outlook (mtpa) Source: Wood Mackenzie 2013 Q4 Data 20 16 19 2015 2020 2030 2015 2020 2030 6 10 38 2015 2020 2030 2015 2020 2030 Americas Asia Middle East/N. Africa 200 256 377 28 60 98 Global demand is forecast to grow from 236 mtpa (~32 Bcf/d) in 2012 to 532 mtpa (~71 Bcf/d) in 2030 ~4.6% CAGR equivalent to ~16 mtpa average growth per year (~three 5 mtpa trains) Europe

Cheniere’s LNG Export Facilities Offer Attractive Pricing for Global LNG Buyers 5 Example Prices Henry Hub: $4.00 / MMBtu Brent Crude: $100 / Barrel ($/MMBtu) Americas Europe Asia LNG Cost (1) 4.60 $ 4.60 4.60 Shipping 0.50 1.00 3.00 $ 8.60 9.10 11.10 3.90 LNG Price (% Crude) @ 15% 15.00 12.00 15.00 Net Difference 6.40 $ 2.90 Liquefaction Fee 3.50 3.50 3.50 Delivered Cost Source: Pira, Cheniere Research estimates @ 12% @ 15% $ $ $ $ $ $ (1) LNG Cost is calculated as 115% of Henry Hub price. Worldwide LNG Prices = 11% to 15% of Crude Oil $4.03 $9.50 $16.18 $10.44 0 2 4 6 8 10 12 14 16 18 20 J a n -1 0 M a r- 1 0 M a y-1 0 Jul -1 0 S ep -1 0 N o v- 1 0 J a n -1 1 M a r- 1 1 M a y-1 1 Jul -1 1 S ep -1 1 N o v- 1 1 J a n -1 2 M a r- 1 2 M a y-1 2 Jul -1 2 S ep -1 2 N o v- 1 2 J a n -1 3 M a r- 1 3 M a y-1 3 Jul -1 3 S ep -1 3 N o v- 1 3 J a n -1 4 MMBtu Regional Natural Gas & LNG Prices March 2014 NBP NYMEX European Gas Contract Japan Spot

Cheniere Liquefaction Projects 6 Sabine Pass T1-4 Corpus Christi T1-2 Sabine Pass T5-6 Corpus Christi T3 Estimated Cost(1) $12B $10B $6B $3B Volume (MTPA) 18.0 9.0 9.0 4.5 3rd Party Contracts to date (MTPA) 16.0 3.0 3.75 - Development Stage Under Construction FID Expected 1Q 2015 Permitting/ Commercializing Permitting/ Commercializing First LNG 2015 2018/19 2018/19 2019 9 Trains, ~$31B investment, ~40.5 MTPA LNG Exports (~5.5Bcf/d) (1) Includes financing cost estimates

Brownfield LNG Export Project: Sabine Pass Liquefaction Utilizes Existing Assets, Trains 1-4 Fully Contracted, Under Construction 7 Significant infrastructure in place including storage, marine and pipeline interconnection facilities; pipeline quality natural gas to be sourced from U.S. pipeline network Design production capacity is expected to be ~4.5 mtpa per train, using ConocoPhillips’ Optimized Cascade® Process Current Facility  ~1,000 acres 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 & 2 – Fully Contracted  Lump Sum Turnkey EPC contract w/ Bechtel  Total EPC contract price ~$4.0 billion  Overall project ~63% complete (as of 3/31/2014)  Operations estimated late 2015/2016 Liquefaction Trains 3 & 4 – Fully Contracted  Lump Sum Turnkey EPC contract w/ Bechtel  Total EPC contract price ~$3.8 billion  Construction commenced in May 2013  Overall project ~27% complete (as of 3/31/2014)  Operations estimated 2016/2017 Liquefaction Expansion - Trains 5 & 6  Bechtel commenced preliminary engineering  Permitting initiated February 2013  FERC application submitted September 30, 2013

LNG Sale and Purchase Agreements (SPAs) Sabine Pass Liquefaction 8 (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. (6) Conditions precedent must be satisfied by June 30, 2015 or either party can terminate. CPs include financing, regulatory approvals and positive final investment decision. BG Gulf Coast LNG Gas Natural Fenosa Annual Contract Quantity (MMBtu) 286,500,000 (1) Fixed Fees $/MMBtu (2) Annual Fixed Fees (2) ~$723 MM (3) ~$454 MM Term of Contract (4) Guarantor 20 years BG Energy Holdings Ltd. Gas Natural SDG S.A. Corporate / Guarantor Credit Rating (5) A-/A2/A- BBB/Baa2/BBB+ Fee During Force Majeure Up to 24 months Up to 24 months 20 years GAIL (India) Limited ~$548 MM 20 years NR/Baa2/BBB- N/A N/A Contract Start Train 1 + additional volumes with Trains 2,3,4 Train 2 Train 4 $2.25 - $3.00 $2.49 $3.00 182,500,000 182,500,000 20 years N/A N/A A+/A1/AA- Train 3 $3.00 ~$548 MM Korea Gas Corporation 182,500,000 ~$314 MM 20 years AA-/Aa1/AA N/A Total S.A. Train 5 $3.00 104,750,000 (1) Total Gas & Power N.A. (6) ~$274 MM 20 years A-/A3/A- N/A N/A $3.00 91,250,000 Centrica plc (6) Train 5 LNG Cost 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH ~20 mtpa “take-or-pay” style commercial agreements ~$2.9B annual fixed fee revenue for 20 years

SPL Construction Completion Schedules Trains 1-4  Current plan estimates Train 1 operational in 40 months from NTP • Bechtel schedule bonus provides incentive for early delivery • Bechtel’s record delivery was Egyptian LNG train 1, delivered in 36 months from NTP  Notice to Proceed for Trains 3&4 issued to Bechtel in May 2013  Trains expected to come on-line on a 6-9 month staggered basis 9 2012 2013 2014 2015 2016 2017 2018 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 Guaranteed Current Level 3 Schedule Guaranteed Current Level 3 Schedule Early Engineering Guaranteed Current Level 3 Schedule Guaranteed Current Level 3 Schedule BG DFCD GN DFCD KOGAS DFCD GAIL DFCD Record First LNG – Egyptian LNG T1 First LNG Train 1 Train 2 Train 3 Train 4 Feb 2016 April 2017 Jun 2017 Mar 2018 June 2016 Sept 2017 Assumes start date occurs 6 months after previous train Note: See “Forward Looking Statements” slide.

Aerial View of SPL Construction – February 2014 10 Train 2 Train 1 Train 3 Train 4 Propane Condenser Area Compressor Area Air Coolers Compressor Area Cold Box Area Propane Condenser Area Cold Box Area Train 4 Pile driving Train 3 Condenser Foundation

Corpus Christi Liquefaction Project 11 Proposed 3 Train Facility  >1,000 acres owned and/or controlled  2 berths, 3 LNG storage tanks (~10.1 Bcfe of storage) Key Project Attributes  45 ft. ship channel 13.7 miles from coast  Protected berth  Premier Site Conditions • Established industrial zone • Elevated site protects from storm surge • Soils do not require piles • Local labor, infrastructure & utilities • 23-mile 48” pipeline interconnected to several inter- and intrastate pipelines Project Update  Lump Sum Turnkey contracts signed with Bechtel • Stage 1: ~$7.1B includes 2 Trains, 2 tanks, 1 berth • Stage 2: ~$2.4B includes 1 Train, 1 tanks, 1 berth  SPAs signed with Pertamina and Endesa covering ~3.0 mtpa at a fixed fee of $3.50/MMBtu  Anticipate FID on Stage 1 in early 2015  First LNG expected 2018 Houston New Orleans Gulf of Mexico Corpus Christi Advanced commercialization Artist’s rendition Design production capacity is expected to be ~4.5 mtpa per train, using ConocoPhillips’ Optimized Cascade® Process

12 Annual Contract Quantity (TBtu) Fixed Fees $/MMBtu (1) Annual Fixed Fees (1) Term of Contract (2) Guarantor Guarantor/Corporate Credit Rating (3) Contract Start(4)(5) SPA progress: ~3 mtpa “take-or-pay” style commercial agreements ~$550MM annual fixed fee revenue for 20 years PT Pertamina (Persero) ~$139 MM 20 years BB+/Baa3/BBB- N/A Train 1 $3.50 39.68 (1) 11.5% of the fee is subject to inflation for Pertamina; 14% for Endesa (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. (4) Conditions precedent must be satisfied by December 31, 2014 (Pertamina) or June 30, 2015 (Endesa) or either party can terminate. CPs include financing, regulatory approvals and positive final investment decision. (5) If FID is reached on Sabine Pass T6 prior to Corpus Christi T1, Pertamina contract will transfer to Sabine Pass T6 with identical terms. LNG Cost 115% of HH Endesa S.A. 117.32 ~$411 MM 20 years BBB/Baa2/BBB+ N/A Train 1 $3.50 115% of HH LNG Sale and Purchase Agreements (SPAs) Corpus Christi Liquefaction

Regulatory Approvals – Corpus Christi and SPL Trains 5-6  Corpus Christi Trains 1-3 • FERC: Scheduling Notice received 2/2014, final EIS expected October 8, 2014, 90-day federal authorization decision deadline January 6, 2015 • DOE: Received FTA authorization in 10/2012 • DOE: Non-FTA authorization is pending; Corpus Christi is #2 on the DOE “Order of Precedence”  SPL Trains 5-6 • FERC: Application filed Sept. 30, 2013, expecting Scheduling Notice in 2014 • DOE: Received FTA authorization for Total and Centrica SPAs in 7/2013, received FTA authorization for Train 6 in 1/2014 • DOE: Non-FTA authorization is pending; Total volume is #13, Centrica volume is #14, Train 6 and remaining Train 5 volumes are #18 on the “Order of Precedence” 13 DOE export approvals and FERC construction and operation approvals needed for Corpus Christi Liquefaction Trains 1-3 and Sabine Pass Liquefaction Trains 5&6

FERC Applications Filed for Liquefaction Projects  DOE issues conditional non-FTA licenses, subject to receiving FERC approval, therefore FERC is the gating regulatory approval  Corpus Christi received FERC scheduling notice on February 12, 2014; FERC approval expected 2014/2015  SPL filed FERC application for Trains 5 and 6 on September 30, 2013 14 LNG Export Projects Pre-filing Date Application Date FERC Scheduling Notice Issued Rec’d Approval Sabine Pass Liquefaction T1-4 July 26, 2010 Jan. 31, 2011 Corpus Christi Liquefaction Dec. 13, 2011 Aug. 31, 2012 Feb 12, 2014 Freeport LNG Dec. 23, 2010 Aug. 31, 2012 Jan 6, 2014 Cameron LNG April 30, 2012 Dec. 10, 2012 Nov 21, 2013 Dominion Cove Point LNG June 1, 2012 Apr. 1, 2013 March 12, 2014 Jordan Cove Energy Feb. 29, 2012 May 22, 2013 Oregon LNG July 3, 2012 June 7, 2013 Sabine Pass Liquefaction T5-6 February 27, 2013 Sep. 30, 2013 Excelerate November 5, 2012 February 6, 2014 Southern LNG December 5, 2012 March 10, 2014 Lake Charles LNG March 30, 2012 March 25, 2014  Note: National Environmental Policy Act (NEPA) empowers FERC as the lead Federal agency to prepare an Environmental Impact Statement in cooperation with other state and federal agencies

U.S. DOE Applications for LNG Exports* 15 Source: Office of Fossil Energy, U.S. Department of Energy; U.S. Federal Energy Regulatory Commission; Company releases ** Application filed = v, FERC scheduling notice issued =  * As of March 31, 2014. Note additional companies have filed for their DOE license; however, not all have initiated their FERC filing process. (1) “Order of Precedence” (2) Orders are conditional on applicant completing the environmental review process as part of the FERC licensing process, and other conditions such as submitting all relevant long-term commercial agreements. (3) Application was filed for 1.4 Bcf/d; 0.4 Bcf/d was approved Expected Order to be Processed (1)2 Company Date Applicant Received FERC Approval to Begin Pre-Filing Process Quantity (Bcf/d) Date Non FTA Received FERC** Contracts Conditional (2) Final Cheniere Sabine Pass T1-T4 8/4/2010 2.8 5/20/2011 8/7/2012  Fully Subscribed Freeport LNG Expansion, L.P. and FLNG Liquefaction 1/5/2011 1.4 5/17/2013  Fully Subscribed Lake Charles Exports, LLC 4/6/2012 2 8/7/2013 v Fully Subscribed Dominion Cove Point LNG, LP 6/26/2012 1 9/11/2013  Fully Subscribed Freeport LNG Expansion, L.P. and FLNG Liquefaction 1/5/2011 0.4(3) 11/15/2013  Fully Subscribed Cameron LNG, LLC 5/9/2012 1.7 2/11/2014  Fully Subscribed Jordan Cove Energy Project, L.P. 3/6/2012 1.2/0.8 3/24/2014 v 1 LNG Development Company, LLC (d/b/a Oregon LNG) 7/16/2012 1.25 v 2 Cheniere Marketing, LLC (Corpus Christi) 12/22/2011 2.1  T1 Partially Subscribed 3 Excelerate Liquefaction Solutions 11/20/2012 1.38 v 4 Carib Energy (USA) LLC 0.03/0.01 5 Gulf Coast LNG Export, LLC 2.8 6 Southern LNG Company, L.L.C. 3/1/2013 0.5 v Fully Subscribed 7 Gulf LNG Liquefaction Company, LLC 1.5 8 CE FLNG, LLC 4/16/2013 1.07 9 Golden Pass Products LLC 5/30/2013 2.6 10 Pangea LNG (North America) Holdings, LLC 1.09 11 Trunkline LNG Export, LLC 2 12 Freeport-McMoRan Energy, LLC 3.22 13 Sabine Pass Liquefaction, LLC (T5 - Total Contract) 3/8/2013 0.28 v T5 Fully Subscribed 14 Sabine Pass Liquefaction, LLC (T5 - Centrica Contract) 3/8/2013 0.24 v T5 Fully Subscribed 15 Venture Global LNG, LLC 0.67 16 Eos LNG, LLC 1.6 17 Barca LNG, LLC 1.6 18 Sabine Pass Liquefaction, LLC (Remaining T5 Volumes and T6) 3/8/2013 0.86 v 19 Magnolia LNG, LLC 3/20/2013 1.08 20 Delfin LNG, LLC 1.8 21 Waller LNG Services, LLC 0.19 22 Gasfin Development 0.2 23 Texas LNG 0.27 24 Louisiana LNG 0.28

Timeline & Milestones Target Date SPL Corpus SPL Milestone T1-2 T3-4 Christi T5-6  Initiate permitting process (FERC & DOE)      Commercial agreements   T1 3.0 mtpa 2014 T5  T6: 2014  EPC contract    2015  Financing commitments   2014 2015  Regulatory approvals   2014/15 2015  Issue Notice to Proceed   2015 2015  Commence operations (1) 2015/16 2016/17 2018/19 2018/19 16 (1) Each Train of the respective projects is expected to commence operations approximately six to nine months after the previous train. Note: See “Forward Looking Statements” slide.

Cheniere Marketing  International LNG marketing operation  Professional staff based in London, Houston and Santiago  SPA with SPL for 2 mtpa LNG volumes (equivalent of 104,000,000 MMBtu)  Chartered three LNG vessels for deliveries in 2015 and 2016  Developing complimentary, high-value markets through small-scale asset investments  Scale up for > 5 mtpa including LNG purchases from Cheniere terminals and other places  Staffing, systems, and processes are underway and on schedule Cheniere developing platform for LNG sale opportunities to international markets

18 Financial Estimates

$0.3 $0.2 $0.9 $0.4 $0.5 $0.1 $0.1 $0.7 $0.6 $0.7 $1.0 - $1.2 $1.9 - $2.5 $2.6 - $3.3 $3.3 - $4.5 – $1.0 $2.0 $3.0 $4.0 $5.0 CEI EBIT DA ($ in bill ions ) Estimated CEI EBITDA Build Up SPL Trains 1-6 and CCL Trains 1-3 19 SPL Sales (T1-4) SPL CMI Sales CCL Sales (T1-2) SPL Sales (T5-6) CCL Sales (T3) Number of trains 4 trains 4 trains 6 trains 8 trains 9 trains Nameplate capacity 18.0 MTPA 18.0 MTPA 27.0 MTPA 36.0 MTPA 40.5 MTPA Long term SPA volumes 16.0 MTPA 16.0 MTPA 22.0 MTPA 27.8 MTPA(1) 27.8 MTPA(1) Short / medium term LNG sales 0 MTPA 1.6 MTPA 4.0 MTPA 6.6 MTPA(1) 10.2 MTPA(1) Assumed LNG gross margin NA $4.00 - $7.00/MMBtu CEI debt balance (unconsolidated) No debt No debt ~$2 billion ~$2 billion ~$4 billion Note: EBITDA is a non-GAAP measure. EBITDA is computed as total revenues less non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes. It does not include depreciation expenses and certain non-operating items. Because we have not forecasted depreciation expense and non-operating items, we have not made any forecast of net income, which would be the most directly comparable financial measure under generally accepted accounting principles, or GAAP, and we are unable to reconcile differences between forecasts of EBITDA and net income. EBITDA has 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. (1) Assumes 4.0 MTPA sold at $3.50/MMBtu on Train 6 and split evenly across long term and short / medium term sales. Cumulative build up

Potential Financial Profile of CEI 20 (1) As of January 2014, 238.1 million shares outstanding, plus 30 million CEI shares under proposed 2014 - 2018 management compensation plan. Cheniere development of ~41 MTPA of US liquefaction capacity (9 trains) leads to  EBITDA of $3.3 - $4.5 billion (unconsolidated)  CEI level debt of ~$4 billion (unconsolidated)  CEI share count of 268 million(1)

CQP estimated distributable cash flows ($ in millions) Trains 1-4 Trains 1-6 SPLNG distributable cash flow $370 $380 SPL distributable cash flow 1,400 2,260 CTPL distributable cash flow 30 30 CQP expenses (15) (15) Estimated total distributable cash flow $1,785 $2,655 Estimated distributable cash flow to General Partner $350 $750 CQH 700 870 Public and BX units 735 1,035 Estimated range of DCF per unit (1) $3.00 - $3.10 $3.80 - $3.90 CQP Forecasted Distributable Cash Flows 21 Note: Assumes conversion of all subordinated units and early conversion of Class B units at Trains 2 COD to common units and assumes ~269 million of public and Blackstone common units, ~227 million common units held by CQH and 2% General Partner interest and IDRs held by Cheniere. Estimates represent a summary of internal forecasts, are based on current assumptions and are subject to change. Actual performance may differ materially from, and there is no plan to update, the forecast. See “Forward Looking Statements” slide. (1) Assumes CMI sells 2.2 MTPA (SPL Trains 1-4: 80% of 2 MTPA, plus SPL Train 5: 80% of 0.75 MTPA) on SPL Trains 1-5 at $4.00 - $7.00/MMBtu margin, net of expenses including shipping.

$0.3 $1.2 $2.6 $2.9 $3.2 $4.4 – $0.5 $1.0 $1.5 $2.0 $2.5 $3.0 $3.5 $4.0 $4.5 2015E 2016E 2017E 2018E 2019E 2020E ($ in bil lio ns ) SPLNG SPL T1-4 SPL T5 SPL T6 SPL commodity pmts CMI share – 347 823 939 1,046 1,378 (100) 100 300 500 700 900 1,100 1,300 1,500 2015E 2016E 2017E 2018E 2019E 2020E (TB tu pe r y ea r) SPL T1-4 SPL T5 SPL T6 CMI CQP Outlook – Visible Future Growth 22 Note: Estimates represent a summary of internal forecasts, are based on current assumptions and are subject to change. Actual performance may differ materially from, and there is no plan to update, the forecast. See “Forward Looking Statements” slide. Estimated LNG export volumes Estimated CQP revenues Estimated CQP distributable cash flow per unit $1.70 $3.00 - $3.10 $3.80 - $3.90 – $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 Current SPL Trains 1-4 SPL Trains 1-6 Di str ibu ta ble cas h f low pe r u nit ($ pe r u nit )

Financial Strength 23  Since 2010, Cheniere has executed $15B+ in corporate and project level financings • ~$5.0B in equity capital • ~$10.5B in debt capital  Multiple sources of capital available • CQH • Bond markets • Bank markets Demonstrated ability to raise capital, multiple options available As of December 31, 2013 CQP Other Cheniere Energy, Inc. Consolidated CEI Unrestricted cash and equivalents $ 0 $961 $ 961 Restricted cash and securities 1,604 26 1,630 Current & long-term debt $6,576 $ 0 $6,576

Cheniere’s Debt Summary As of March 2014 24 Cheniere Energy, Inc. (NYSE: LNG) Cheniere Energy Partners, L.P. (NYSE: CQP) Sabine Pass LNG, L.P. (SPLNG) BG SPA (286.5 million MMBtu / yr) Gas Natural SPA (182.5 million MMBtu / yr) KOGAS SPA (182.5 million MMBtu / yr) GAIL SPA (182.5 million MMBtu / yr) Total TUA (1 Bcf/d) Chevron TUA (1 Bcf/d) SPL TUA (2 Bcf/d) Sr Secured Notes  $1,666 due 2016 (7.50%)  $420 due 2020 (6.50%) ($ in millions) No Debt Cheniere Marketing, LLC Corpus Christi Liquefaction, LLC Trains 1-4 Debt  $5,015 Credit Facilities due 2020 (1)  $2,000 Notes due 2021 (5.625%)  $1,000 Notes due 2022 (6.250%)  $1,000 Notes due 2023 (5.625%) CMI SPA (up to 104 million MMBtu / yr) Total SPA (104.8 million MMBtu / yr) Sabine Pass Liquefaction, LLC (SPL) Centrica SPA (91.3 million MMBtu / yr) Creole Trail Pipeline (CTPL) SPL Firm Transport (1.5 Bcf/d) $400 Term Loan due 2017 (L+325) CQP GP (& IDRs) (1) Includes $3,740 million term loan facility, $918 million Republic of Korea (“ROK”) covered facility and $357 million ROK direct facility. Interest on the term loan facility is L+300 during construction and steps up to L+325 during operation. Under the ROK credit facilities, interest includes L+300 on the direct portion and L+230 on the covered portion during construction and operation. In addition, SPL will pay 100 bps for insurance/guarantee premiums on any drawn amounts under the covered tranches. These Credit Facilities mature on the earlier of May 28, 2020 or the second anniversary of Train 4 completion date. $100 million has been drawn to date. Cheniere Energy Partners LP Holdings, LLC (NYSE: CQH) No Debt

25 Appendix

Operating Assets 26 Sabine Pass LNG Terminal Creole Trail Pipeline

Contracted Capacity at SPLNG Third Party Terminal Use Agreements (TUAs) 27 Long-term, 20 year “take-or-pay” style commercial contracts ~$253MM annual fixed fee revenue Total Gas & Power N.A. Chevron U.S.A. Inc. Capacity 1.0 Bcf/d 1.0 Bcf/d Fees (1) Reservation Fee (2) $0.28/MMBTU $0.28/MMBTU Opex Fee (3) $0.04/MMBTU $0.04/MMBTU Full-Year Payments $124 million $129 million Term 20 years 20 years Guarantor Total S.A. Chevron Corp. Guarantor Credit Rating ** Aa1/AA Aa1/AA Payment Start Date April 1, 2009 July 1, 2009 (1) Fees do not vary with the actual quantity of LNG processed; tax reimbursement not included in the fees. (2) No inflation adjustments. (3) Subject to annual inflation adjustment. Note: Termination Conditions – (a) force majeure of 18 months or (b) unable to satisfy customer delivery requirements of ~192MMbtu in a 12-month period, 15 cargoes over 90 days or 50 cargoes in a 12-month period. In the case of force majeure, the customers are required to pay their capacity reservation fees for the initial 18 months. **Ratings may be changed, suspended or withdrawn at anytime and are not a recommendation to buy, hold or sell any security.

Creole Trail Pipeline Current Facility  Receipt capacity from SPLNG: 2.0 Bcf/d  Diameter: 42-inch; Length: 94 miles  Delivery Points: NGPL, Transco, TGPL, FGT, Bridgeline, Tetco, Trunkline  No compression Pipeline Modifications  Delivery capacity to SPLNG: 1.5 Bcf/d  Receipt points: TETCO, Trunkline, Transco  One new compressor station with four new units  Two new meter stations  Modify existing meter stations  Est ~$100MM capital cost  Design and procurement near completion (>95%)  Modifications commenced 4Q2013  Est in-service: 4Q2014 28  In May 2013, Cheniere Partners acquired CTPL from Cheniere Energy, Inc. for $480MM, and following the sale CTPL secured a $400 million senior secured term loan facility  CTPL is fully contracted with expected annual revenue of ~$80MM expected to commence with Train 1 operations Potential expansion for Trains 5&6 Modification to reverse flow

LSTK EPC Contract with Bechtel Minimize Construction Costs and Risks 29 Hoover Dam Hong Kong Int’l Airport San Francisco Rapid Transit Source: Bechtel. Bechtel was the EPC contractor for the regasification project at the Pass LNG terminal, which was constructed on time and on budget Proven construction contractor • Founded in 1898 and headquarted in San Francisco • Received 35+ industry awards since 2009 • Named the Top US Construction Contractor for the last 15 consecutive years by Engineering News Record Industry leading experience and results • Have participated in 23,000 projects in 140 nations and seven continents (average of 200 projects per year) • Built ConocoPhillips Petroleum Kenai liquefaction plan in 1969 Leading LNG Construction Contractor Notable Other Non-LNG Projects Key Competitive and Cost Advantages • Existing SPLNG infrastructure provides significant cost advantages (jetty, pipeline, control room, ~17 Bcf storage tanks, etc.) • Economies of scale from building multiple trains • Easy access to the Gulf Coast labor pool where we have strong labor relations • Established marine and road access provide easy delivery of materials • Duplicating Sabine Pass LNG Train Design at Corpus Christi Why Bechtel? • Constructed one third of the world's liquefaction facilities (more than any other contractor) • Designed and/or constructed LNG facilities using ConocoPhillips’ Optimized Cascade® technology in Angola, Australia, Egypt, Equitorial Guinea and Trinidad • 5 liquefaction projects in the last decade, 4 currently underway all using the ConocoPhillips’ Optimized Cascade® Process Sabine Pass LNG Corpus Christi LNG

Global LNG Supply & Demand 2013 Global LNG Capacity: ~38 Bcf/d Natural Gas Oil Products LNG Importers - Price Indexation Japan Crude Cocktail 2013 Global LNG Demand: ~31 Bcf/d No r th Ame r ica S outh Ame r ica E u r ope A sia 4.7 1.3 1.4 24 A ust r alia - 3.4 B r unei - 1.0 Indonesia - 4.2 M al a y sia - 3.4 A lge r ia - 2.7 N o r w a y - 0.5 Q a tar – 10.1 Russia - 1.4 Egypt - 1 Y emen - 0.9 Nigeria – 2.9 T r inidad & T obago - 2.0 Equatorial Guinea - 0.5 Oman - 1.4 U AE - 0.7 USA - 0.2 P e r u - 0.6 Source: Wood Mackenzie 30 Angola – 0.4

Firm Liquefaction Capacity Additions (Bcf/d) 31 0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2.75 3.00 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2014 2015 2016 2017 2018 2019 Asia Pacific Atlantic Basin Bcf/d Nameplate Liquefaction Capacity ~ 39 Bcf/d as of YE 2013 ~ 53 Bcf/d by YE 2019 Source: Cheniere Research QCLNG T1, PNG T1, Pacific Rubiales LNG SPL T1, Gorgon T1, APLNG T1 Gassi Touil PNG T2 Gorgon T3, Wheatstone T1, Gladstone T2 Gladstone T1 Wheatstone T2 APLNG T2 SPL T3 Yamal T1, Ichtys T2 Ichtys T1, Prelude FLNG Yamal T2 QCLNG T2, Donggi LNG SPL T2, Gorgon T2, Petronas FLNG SPL T4 Yamal T3

US Proved Non-Producing Reserves Productive Capacity from Unconventional Reservoirs Tcf  Current market fundamentals in the U.S. – increased production, increased natural gas reserves and lackluster increase in natural gas demand – have created an opportunity to expand into exports – benefitting U.S. economy, creating jobs and reducing balance of trade deficit Source: EIA, US Crude Oil, Natural Gas and Natural Gas Liquids Proved Reserves, 2012. Source: Advanced Resource Intl; Cheniere Research. U.S. Natural Gas Markets 32 US Natural Gas Resources Tcf Source: Potential Gas Committee, 2013; EIA, Natural Gas Proved Reserves, 2010 US Gas Consumptions vs. Production Source: EIA Apr 2014 STEO • U.S. resources increased by 75% since 2006 • Represents over 100 years of supply at current demand 0 500 1000 1500 2000 2500 3000 2006 2008 2010 2012 Shale Other 2,718 2,203 2,081 1,532 67 78 86 98 113 118 110 0 20 40 60 80 100 120 2006 2007 2008 2009 2010 2011 2012 - 3 6 9 12 0 4 8 12 16 2012 2015 2020 2025 Productive Capacity from Unconventional Reservoirs Oil NGLs Natural Gas Bcf/d MMB/d Includes Eagle Ford, Barnett Combo, Bakken, Permian, Anadarko, Wet Marcellus, Utica, Cotton Valley, Piceance, Uinta 49.6 50.7 52.9 55.3 56.4 58.4 62.7 66.0 66.8 60.3 54.5 63.3 63.8 62.7 66 67.1 69.9 70.7 40 50 60 70 80 2005 2006 2007 2008 2009 2010 2011 2012 2013 Bcf/d US Gas Production US Gas Consumption

Montana Thrust Belt Cody Gammon Hilliard Baxter- Mancos Greater Green River Basin Forest City Basin Pierre Illinois Basin Piceance Basin Lewis San Juan Basin Raton Basin Anadarko Basin PaloDuro Basin Permian Basin Barnett Woodford Pearsall Eagle Ford Rio Grande Embayment Barnett Woodford Michigan Basin Antrim New Albany Chattanooga Texas Louisiana Mississippi Salt Basin Fayetteville Ft. Worth Basin Arkoma Basin Conasauga Black Warrior Basin Marfa Basin Paradox Basin Maverick Sub-Basin Hermosa Mancos Cherokee Platform Excello- Mulky Appalachian Basin Marcellus/Utica Shale Plays Basins Sabine Pass Haynesville Bossier Granite Wash Williston Basin Bakken Primary Gas Sources for Sabine Pass and Corpus Christi Liquefaction Conventional Gulf Coast Onshore: Barnett, Haynesville, Bossier, Eagle Ford, Fayetteville, Permian Basin, Anadarko Basin Source: EIA, April 2014; Advanced Resources Intl (Lower 48 Unconventional Recoverable Reserves), ARI shale estimates updated October 2013 Rig Count Production Bcf/d Barnett 24 5.2 Haynesville 42 4.6 Eagle Ford 220 4.9 Granite Wash 61 1.2 Bakken 185 1.1 Marcellus 79 12.5 Source: Lippman Consulting and PIRA, as of April 2014 Uinta Strategically Located – Extensive Market Access to Gas 366 2,241 Lower 48 Recoverable Unconventional Reserves (Tcf) 0 1000 2000 1996 2011 Shale CBM Tight Gas Total US Proved Reserves 3000 323 Corpus Christi

Multiple Local Pipeline Interconnections Provide Several Options for Access to Natural Gas Supply 34 Targa Columbia Gulf Tennessee Cheniere Creole Trail Pipeline Trunkline Kinder Morgan Louisiana Pipeline NGPL Texas to Louisiana (bi-directional) Transco TETCO Tennessee FGT ) Existing Pipeline Grid Transco Z3 Sabine Pine Prairie Energy Center Egan Storage Jefferson Island Storage Pine Prairie Texas Gas ANR Florida Gas Z2 Tennessee Trunkline Columbia NGPL Transco Florida Gas Z1 Tennessee Bridgeline . NGPL Texas Eastern Trunkline Transco Z3 Source: Cheniere Research

Source: Office of Oil and Gas Global Security and Supply, Office of Fossil Energy, U.S. Department of Energy; U.S. Federal Energy Regulatory Commission; Company releases U.S. LNG Export Projects Dominion Cove Point Under Construction Company Quantity (Bcf/d) DOE FERC* Contracts Cheniere Sabine Pass T1 – T4 2.2 Fully permitted Fully Subscribed Freeport 1.8 FTA + NonFTA  T1-T3 Lake Charles 2.0 FTA + NonFTA v Fully Subscribed Dominion Cove Point 1.0 FTA + NonFTA v Fully Subscribed Cameron LNG 1.7 FTA + NonFTA  Fully Subscribed Jordan Cove 1.2/0.8 FTA + NonFTA v Oregon LNG 1.25 FTA v Cheniere Corpus Christi 2.1 FTA  Partially Subscribed Cheniere Sabine Pass T5 – T6 1.3 FTA v T5 Subscribed Excelerate 1.3 FTA v Southern LNG 0.5 FTA v Freeport LNG Corpus Christi Plus other proposed LNG export projects that have not filed a FERC application. • Application filing = v • FERC scheduling notice issued =  Filed FERC Application Proposed Projects Jordan Cove Oregon LNG Cameron LNG Lake Charles Sabine Pass 35 Southern LNG

SPLNG estimated cash flows ($ in millions) Trains 1-4 Trains 1-6 Total $130 $130 Chevron 135 135 SPL (1) 295 305 Other 10 15 Total revenues $570 $585 Total expenses (70) (75) EBITDA $500 $510 Interest expense(2) (130) (130) SPLNG distributable cash flow to CQP $370 $380 CQP: SPLNG (Regas) Estimated Cash Flows 36 Note: EBITDA is a non-GAAP measure. EBITDA is computed as total revenues less non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes. It does not include depreciation expenses and certain non-operating items. Because we have not forecasted depreciation expense and non-operating items, we have not made any forecast of net income, which would be the most directly comparable financial measure under generally accepted accounting principles, or GAAP, and we are unable to reconcile differences between forecasts of EBITDA and net income. EBITDA has 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. Estimates represent a summary of internal forecasts, are based on current assumptions and are subject to change. Actual performance may differ materially from, and there is no plan to update, the forecast. See “Forward Looking Statements” slide. (1) Includes export fees. (2) Assumes $2.1 billion of debt outstanding at a weighted average interest rate of 6.3%.

SPL estimated cash flows ($ in millions) Trains 1-4 Trains 1-6 Trains 1-4 (BG, Gas Natural, KOGAS, GAIL) $2,300 $2,300 Train 5 (Total, Centrica) – 590 Train 6 customer (1) – 730 CMI (2) 170 220 Commodity payments, net (3) 250 360 Total revenues $2,720 $4,200 O&M and Management fees (170) (270) Maintenance capex (90) (140) SPLNG / Total TUA (330) (440) Pipeline costs (160) (230) Total expenses ($750) ($1,080) EBITDA $1,970 $3,120 Interest expense (4) (570) (860) SPL distributable cash flow to CQP $1,400 $2,260 CQP: SPL Estimated Cash Flows 37 Note: EBITDA is a non-GAAP measure. EBITDA is computed as total revenues less non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes. It does not include depreciation expenses and certain non-operating items. Because we have not forecasted depreciation expense and non-operating items, we have not made any forecast of net income, which would be the most directly comparable financial measure under generally accepted accounting principles, or GAAP, and we are unable to reconcile differences between forecasts of EBITDA and net income. EBITDA has 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. Estimates represent a summary of internal forecasts, are based on current assumptions and are subject to change. Actual performance may differ materially from, and there is no plan to update, the forecast. See “Forward Looking Statements” slide. (1) Assumes 4.0 MTPA sold at $3.50/MMBtu on Train 6. (2) Assumes CMI sells 2.2 MTPA (SPL Trains 1-4: 80% of 2 MTPA, plus SPL Train 5: 80% of 0.75 MTPA) on SPL Trains 1-5 at $7.00/MMBtu margin, net of expenses including shipping. (3) Assumes $5.00/MMBtu natural gas price and that Offtakers lift 100% of their full contractual entitlement. Amounts are net of estimated natural gas to be used for the liquefaction process. (4) SPL Trains 1-4 assume consolidated debt of ~$11.9 billion with weighted average interest rate of ~6.2%. SPL Trains 1-6 assume consolidated debt of ~$16.5 billion with weighted average interest rate of ~6.2%.

CCL estimated cash flows CMI impact ($ in millions) CCL Trains 1-2 CCL Trains 1-3 Long term SPAs $1,110 $1,110 Short / medium term LNG sales (1) 500 - 880 1,250 - 2,190 Commodity payments, net (2) 160 230 Total CCL revenues $2,150 $3,530 Plant O&M (250) (320) Plant maintenance capex (70) (100) Pipeline costs (primary plant and upstream pipelines) (130) (180) Total CCL expenses ($450) ($600) CCL EBITDA $1,320 - $1,700 $2,000 - $2,930 Less: Project-level interest expense (3) (380) (380) CCL distributable cash flow to CEI $940 - $1,320 $1,620 - $2,550 CCL Estimated Cash Flows Trains 1-3 38 Note: EBITDA is a non-GAAP measure. EBITDA is computed as total revenues less non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes. It does not include depreciation expenses and certain non-operating items. Because we have not forecasted depreciation expense and non-operating items, we have not made any forecast of net income, which would be the most directly comparable financial measure under generally accepted accounting principles, or GAAP, and we are unable to reconcile differences between forecasts of EBITDA and net income. EBITDA has 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. (1) Assumes CCL sells 2.4 MTPA (80% of 3.0 MTPA) on Trains 1-2 and 3.6 MTPA (80% of 4.5 MTPA) on Train 3 at $4.00 - $7.00/MMBtu margin, net of expenses including shipping, in the short / medium term market. (2) Assumes $5.00/MMBtu natural gas price and that Offtakers lift 100% of their full contractual entitlement. Amounts are net of estimated natural gas to be used for the liquefaction process. (3) Assumes debt at CCL of $6 billion at 6.25%.

Cheniere Marketing SPA Estimated Annual Gross Profit from 2 mtpa 39 Assumptions  $5 Henry Hub Price  $15 LNG sales price, delivered at terminal  6% loss of gas on the vessel  Cheniere vessels: $84,000 per day average charter rate  Port / Canal costs: $900,000 per voyage  1 incremental vessel needed at $100,000 per day  Financing costs: $250,000 per cargo for LCs at L+250 Volumes LNG Loaded Sabine Pass (Tbtu) 104 LNG Delivered DES (Tbtu) 98 Cash Flows Sales Total Revenue ($MM) 1,466$ Expenses LNG purchase from Sabine (598) Vessel Charter Costs (92) Port and Canal Costs (25) Incremental Vessel Charters (37) Financing Costs (7) Gross Profit ($MM) 707$ Gross Profit ($/MMBtu) 6.80$

40 Observations  The intrinsic value of 104 million MMBtu of LNG from Sabine Pass is ~$700 million  Trading activity could add an additional 10-25% extrinsic value  A 10% change in the LNG sales price causes a 21% change in the gross margin  A 10% change in the Henry Hub Price causes an 8% change in the gross margin $MM Gross Profit at Varying Prices LNG Sales Price, $/MMBtu $10.00 $15.00 $20.00 $4.00 $338 $827 $1,316 $5.00 $219 $707 $1,196 $6. 0 $99 $588 $1,077 Henry Hub Price, $/MMBtu Gross Profit per MBtu at Varying Prices LNG Sales Price, $/MMBtu $10.00 $15.00 $20.00 $4.00 $3.25 $7.95 $12.65 $5.00 $2.10 $6.80 $11.50 $6.00 $0.95 $5.65 $10.35 Henry Hub Price, $/MMBtu Cheniere Marketing SPA Estimated Annual Gross Profit from 2 mtpa - Sensitivities

Conversion of Class B and Subordinated Units 41  Mandatory conversion: within 90 days of the substantial completion of Train 3  Optional conversion by a Class B unitholder may occur at any of the following times: • After 83 months from issuance of EPC notice to proceed • Prior to the record date for a quarter in which sufficient cash from operating surplus is generated to distribute $0.425 to all outstanding common units and the common units to be issued upon conversion • Thirty (30) days prior to the mandatory conversion date • Within a 30-day period prior to a significant event or a dissolution  Subordinated units will convert into common units on a one-for-one basis, provided that there are no cumulative common unit arrearages, and either of the below distribution hurdles is met: • For three consecutive, non-overlapping four-quarter periods, the distribution paid from “Adjusted Operating Surplus”(1) to all outstanding units(2) equals or exceeds $0.425 per quarter • For four consecutive quarters, the distribution paid from “Contracted Adjusted Operating Surplus”(1) to all outstanding units(2) equals or exceeds $0.638 per quarter Class B Units: Subordinated Units: (1) As defined in CQP’s partnership agreement. (2) Includes all outstanding common units (assuming conversion of all Class B units ), subordinated units and any other outstanding units that are senior or equal in right of distribution to the subordinated units.

Pro Forma CQP Ownership 42  Current common unit annualized distribution expected to be $1.70/unit (2)  Class B units accrete 3.5% quarterly until converted into common units (1) Unit amounts are current units outstanding, including Blackstone’s total investment of $1.5B but excluding accretion of Class B Units. (2) Currently, CQP is paying distributions on the common units and the applicable 2% distribution to the GP. (3) CQH is a subsidiary of Cheniere, of which Cheniere owns ~84.5%. Note: The above represents a summary of internal forecasts, are based on current assumptions and are subject to change. Actual performance may differ materially from, and there is no plan to update, the forecast. See “Forward Looking Statements” slide. (in millions) CEI CQH(3) Blackstone Public Total Common units (1) 12.0 45.1 57.1 Class B units (1) 45.3 100.0 145.3 Subordinated units (1) 135.4 135.4 General Partner @ 2% 6.9 6.9 6.9 192.7 100.0 45.1 344.7 Percent of total (as of 12/31/13) 2% 55.9% 29.0% 13.1% 100.0% Pro forma accretion YE2016 9.4 231.7 182.9 45.1 469.1 Percent of total (pro forma YE2016) 2% 49.4% 39.0% 9.6% 100.0%

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Randy Bhatia: Director, Finance and Investor Relations – (713) 375-5479, randy.bhatia@cheniere.com Christina Burke: Manager, Investor Relations – (713) 375-5104, christina.burke@cheniere.com Investor Relations Contacts