Cheniere Energy October 2013
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; statements regarding Cheniere Energy Partners, L.P.’s expected receipt of cash distributions from Sabine Pass LNG, L.P., Sabine Pass Liquefaction, LLC or Cheniere Creole Trail Pipeline, L.P.; 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. and Cheniere Energy Partners, L.P. Annual Reports on Form 10-K filed with the SEC on February 22, 2013, each as amended by Amendment No. 1 on Form 10-K/A filed with the SEC on March 1, 2013, and the Cheniere Energy Partners, L.P. Current Report on Form 8-K filed with the SEC on May 29, 2013, 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.
2.0% Interest & Incentive Dist. Rights Cheniere Energy, Inc. (NYSE MKT: LNG) Sabine Pass LNG, L.P. (“SPLNG”) Sabine Pass Liquefaction, LLC (“SPL”) Cheniere Energy Partners, L.P. (NYSE MKT: CQP) Cheniere Creole Trail Pipeline, L.P. (“CTPL”) Corpus Christi Liquefaction, LLC Cheniere Marketing, LLC (“CMI”) Cheniere Energy Partners GP, LLC 55.9% Interest (1) 100% Interest 100% Interest 100% Interest 100% Interest (1) Represents ownership interest before accretion of Class B units. Next Developments Summary Organizational Structure 3 Blackstone 29.0% (1) Public 13.1% (1) 13.5 mtpa LNG production, 3 trains 4.0 Bcf/d of regas 17 Bcf of storage 2 berths 2 mtpa SPL volumes LNG vessel charters 1.5 Bcf/d capacity for SPL 18 mtpa under construction 9 mtpa under development
Projected Global LNG Demand Growth Regional LNG Import Outlook (mtpa)* Source: Wood Mackenzie 20 15 21 2015 2020 2030 2015 2020 2030 6 14 30 2015 2020 2030 2015 2020 2030 Americas Asia Middle East/N. Africa *Base-case scenario 196 254 356 27 70 101 4 From 236 mtpa (~32 Bcf/d) in 2012 to 514 mtpa (~69 Bcf/d) in 2030 – 4.4% CAGR ~ 15 mtpa average growth (~three 4.5 mtpa trains) Europe
0 2 4 6 8 10 12 14 16 18 20 Se p -0 9 Se p -1 0 Se p -1 1 Se p -1 2 Se p -1 3 $/MMBtu Regional Natural Gas & LNG Prices As of September 27, 2013 NBP IFERC HH Monthly Japan Avg LNG European Gas Contract Estimated 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: Cheniere Research estimates Cheniere’s LNG Export Facilities Offer Attractive Pricing for Global LNG Buyers @ 12% @ 15% $ $ $ $ $ $ Worldwide LNG Prices = 11% to 15% of Crude Oil 5 $3.54 $11.00 $15.05 $10.42 (1) LNG Cost is calculated as 115% of Henry Hub price.
Brownfield LNG Export Project Utilizes Existing Assets Trains 1-4 Fully Contracted, Under Construction Significant infrastructure in place including storage, marine and pipeline interconnection facilities; pipeline quality natural gas to be sourced from U.S. pipeline network Liquefaction Trains 3 & 4 LSTK EPC contract w/ Bechtel using ConocoPhillips’ Optimized Cascade® Process Total EPC contract price ~$3.8 billion Contract terms materially same as Trains 1&2 Guaranteed schedule shorter than Trains 1&2 Construction commenced in May 2013 Operations estimated 2016/2017 Liquefaction Expansion - Trains 5 & 6 Bechtel commenced preliminary engineering Permitting initiated February 2013 FERC application filed on Sept. 30, 2013 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 Bcf of storage) 5.3 Bcf/d of pipeline interconnection Liquefaction Trains 1 & 2 LSTK EPC contract w/ Bechtel using ConocoPhillips’ Optimized Cascade® Process Total EPC contract price ~$4.0 billion Overall project 42% complete (as of 8/13) Operations estimated late 2015/2016 Design production capacity is expected to be ~4.5 mtpa per train 6
LNG Sale and Purchase Agreements (SPAs) (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 from Contract Start Date (4) Guarantor 20 years BG Energy Holdings Ltd. Gas Natural SDG S.A. Corporate / Guarantor Credit Rating (5) A/A2 BBB/Baa2 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 ~20 mtpa “take-or-pay” style commercial agreements ~$2.9B annual fixed fee revenue for 20 years N/A Contract Start Date 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 Train 3 $3.00 ~$548 MM Korea Gas Corporation 182,500,000 ~$314 MM 20 years AA/Aa1 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) 7 Train 5 LNG Cost 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH
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 Construction Completion Schedules Trains 1-4 Note: See “Forward Looking Statements” slide. 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 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 8 June 2016 Sept 2017 Assumes start date occurs 6 months after previous train
Aerial View of SPL Construction – September 2013 9 Train 1 Train 2 Compressor Area T1 Air Coolers Compressor Area T2 Propane Condenser Foundations Cold Box Area
Corpus Christi Liquefaction Project Proposed 3 Train Facility >1,000 acres owned and/or controlled 2 berths, 3 LNG storage tanks (~10.1 Bcfe of storage) ConocoPhillips’ Optimized Cascade® Process Key Project Attributes Marine environment conducive to large tankers • 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 • Proximate pipeline interconnections to 4.5 Bcf/d receipt/takeaway capacity Project Update Contract price received from Bechtel Estimated costs, including owner’s cost, ~$800/ton Proceeding with commercialization Anticipating FID toward the end of 2014 First LNG expected 2018 Houston New Orleans Gulf of Mexico Corpus Christi Commenced commercialization, FID estimated 2014 10 Artist’s rendition Design production capacity is expected to be ~4.5 mtpa per train
- 500 1,000 1,500 2,000 * * * * Range of liquefaction project costs: $200 - $2,000+ per ton 1 Bcf/d of capacity = $1.5B to $15.0B+ Corpus Christi liquefaction project estimated costs are ~$800/ton (1) Corpus Christi Liquefaction, LLC Competitive With Other Recent Liquefaction Projects (1) Before financing costs, includes Corpus Christi Pipeline. Cost estimates based on lump-sum-turnkey contract price received from Bechtel for three 4.5 mtpa Trains and company estimates for owner’s costs. Source: Wood Mackenzie; Cheniere Research. Project costs reflect the liquefaction facility’s capex in dollars per ton. Chart includes a representative sample of brownfield and greenfield liquefaction facilities and does not include all liquefaction facilities existing or under construction. Note: Past results not a guarantee of future performance. *ConocoPhillips-Bechtel Cost: $/ton Trains under construction Operating trains – ConocoPhillips-Bechtel Operating trains – Other 11
Regulatory Approvals LNG Export Projects Corpus Christi Trains 1-3: Filed FERC and DOE applications • Completed and filed FERC application in 8/2012 (NEPA pre-filing process initiated in 12/2011) − Corpus Christi is one of seven liquefaction projects with a FERC application on file • Filed for FTA and non-FTA authorizations in 8/2012 to export ~15.0 mtpa • Received FTA authorizations in 10/2012 • Non-FTA authorizations are pending; Corpus Christi is #5 on the DOE “Order of Precedence” SPL Trains 5-6: Filed FERC and DOE applications • Initiated FERC’s NEPA pre-filing in Feb. 27, 2013 • FERC application filed Sept. 30, 2013 • Filed for FTA and non-FTA authorizations for Trains 5-6 • Received FTA authorizations to export LNG under Total and Centrica SPAs in 7/2013 • Non-FTA authorizations are pending DOE export approvals and FERC construction and operation approvals needed for Corpus Christi Liquefaction Trains 1-3 and Sabine Pass Liquefaction Trains 5&6 12
FERC Applications Filed for Liquefaction Projects 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 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 Freeport LNG Dec. 23, 2010 Aug. 31, 2012 May 22, 2013 Cameron LNG May 9, 2012 Dec. 10, 2012 Apr. 4, 2013 Dominion Cove Point LNG June 1, 2012 Apr. 1, 2013 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 DOE issues conditional non-FTA licenses, subject to receiving FERC approval, therefore FERC is the gating regulatory approval Corpus Christi expects to receive FERC scheduling notice soon, placing it as one of the top three liquefaction projects under review at the FERC SPL filed FERC application for Trains 5 and 6 on September 30, 2013 13
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. DOE Applications for LNG Exports* ** Application filed = v, FERC scheduling notice issued = * As of September 30, 2013. 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. 14 Expected Order to be Processed (1) 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 Dominion Cove Point LNG, LP 6/26/2012 1 9/11/2013 v Fully Subscribed 1 Freeport LNG Expansion, L.P. and FLNG Liquefaction 1/5/2011 1.4 T3 2 Cameron LNG, LLC 5/9/2012 1.7 Fully Subscribed 3 Jordan Cove Energy Project, L.P. 3/6/2012 1.2/0.8 v 4 LNG Development Company, LLC (d/b/a Oregon LNG) 7/16/2012 1.25 v 5 Cheniere Marketing, LLC (Corpus Christi) 12/22/2011 2.1 v 6 Excelerate Liquefaction Solutions 11/20/2012 1.38 7 Carib Energy (USA) LLC 0.03/0.01 8 Gulf Coast LNG Export, LLC 2.8 9 Southern LNG Company, L.L.C. 3/1/2013 0.5 10 Gulf LNG Liquefaction Company, LLC 1.5 11 CE FLNG, LLC 4/16/2013 1.07 12 Golden Pass Products LLC 5/30/2013 2.6 13 Pangea LNG (North America) Holdings, LLC 1.09 14 Trunkline LNG Export, LLC 2 15 Freeport-McMoRan Energy, LLC 3.22 16 Sabine Pass Liquefaction, LLC (T5 - Total Contract) 3/8/2013 0.28 v T5 17 Sabine Pass Liquefaction, LLC (T5 - Centrica Contract) 3/8/2013 0.24 v T5 18 Venture Global LNG, LLC 0.67 19 Eos LNG, LLC 1.6 20 Barca LNG, LLC 1.6 21 Sabine Pass Liquefaction, LLC (Remaining T5 Volumes and T6) 3/8/2013 0.86 v
CMI SPA – Excess Volumes from Trains 1-4 at SPL CMI-SPL SPA provides CMI with up to 2 mtpa of LNG delivered FOB Sabine Pass starting with the initial production from Train 1 •Maximum Annual Contract Quantity of up to 104 TBtu/year from first four Trains SPA sharing mechanic incents profit maximization • Sharing based on ranking of the net profit for each cargo, from highest to lowest: – Tranche 1: CMI pays SPL up to $3.00/MMBtu – Tranche 2: CMI pays SPL 20% of profits • Tranche 1 applies to 18 TBtu until Train 3 begins commercial operations; 36 TBtu thereafter •CMI is entitled to recover all operating costs during a year before allocating profit to SPL Initial deliveries anticipated to begin as early as 4Q 2015 CMI entered into three five-year time-charter contracts for LNG carriers • Delivery of first LNG carrier expected in 2015 and two additional LNG carriers to be delivered in 2016 Note: See “Forward Looking Statements” slide. 15
Example Annual Cash Flow on CMI SPA (1) Net margins based on profitability of cargoes, up to $3.00/MMBtu paid to SPL on 36 Bcf of LNG sold in a year (Tranche 1); 20% of net margins paid to SPL on the remaining 68 Bcf of LNG sold in the year (Tranche 2) LNG sold 104 Bcf/year Net profit (after LNG costs, shipping) (MMBtu) $10 Net profit $1,040 Paid to Sabine Pass Liquefaction(1) ($250) Remaining at CMI $790 Distributable to CEI based on CQP units $190 Total cash flow to CEI $980 ($ in millions unless noted) Note: See “Forward Looking Statements” slide. CQP CEI 16
Timeline & Milestones Initiate permitting process (FERC & DOE) Commercial agreements EPC contract Financing commitments Regulatory approvals Issue Notice to Proceed Commence operations (1) Milestone Corpus Christi (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. T3-4 T1-2 Target Date 2015/16 First LNG expected from both SPL Train 5 and Corpus Train 1 in 2018 SPL 17 2016/17 2014 2018/19 2014 2014 2013/14 2014 T5-6 2015 2015 2015 2015 2018 SPL T5: T6:2014
Financial Estimates (includes SPL Trains 1-4 and Trains 1-6)
CQP: SPLNG (Regas) Estimated Cash Flows Total Revenues Total Expenses Total Chevron SPL Other EBITDA (1) 127 133 290 10 560 (65) $ 495 $ SPLNG Distributable cash flow to CQP $ 365 ($ in millions) Interest Expense (2) (130) Annualized (1) 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. (2) Assumes refinancing of the 2016 and 2020 notes at an interest rate comparable to existing SPL senior notes interest rates. Note: The above represents a single financing scenario. Estimates are as of October 2013. Estimates represent a summary of internal forecasts, are pre-tax, 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. 19 Trains 1-4 Trains 1-6 127 133 305 15 580 (75) $ 505 $ $ 375 (130)
CQP: SPL Estimated Cash Flows Trains 1-4 Total Revenues Trains 1-4 (BG, Gas Natural, KOGAS, GAIL) Total Centrica Train 6 Customer (1) CMI (2) Commodity payments, net (3) O&M, gas procurement, & other Maintenance capex SPLNG/Total TUA Pipeline Costs EBITDA (4) 2,285 - - - 145 245 2,675 (175) (85) (320) (140) (720) $ 1,955 $ ($ in millions) Total Expenses (1) Assumes SPA for 3.75 mtpa of LNG volumes at ~$3.50 / MMBtu. (2) Assumes $5.00 net margin / MMBtu and 70% of CMI’s contractual entitlement for T1-4 and 100% for T1-6. (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) 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 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. (5) Assumes interest rate of 5.625% on $3.0B senior notes, an interest rate of 6.25% on $5.4B credit facility and no payments of principal for Trains 1-4. Assumes additional debt at similar rates for Trains 5-6. Note: The above represents a single financing scenario. Estimates are as of October 2013. Estimates represent a summary of internal forecasts, are pre-tax, 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. Expect > 3X EBITDA: Debt Service Coverage And < 5X Debt: EBITDA Trains 1-6 2,285 315 275 685 175 350 4,085 (270) (135) (435) (210) (1,050) $ 3,035 $ Interest Expense (5) (520) Distributable cash flow to CQP $ 1,435 $ 2,205 (830) 20
CQP Forecasted Distributable Cash Flows Trains 1-4 Estimated distributable cash flow to (1) General partner Cheniere common units Public and BX units Estimated range of DCF per unit 370 730 715 $3.00 - $3.20 $ Estimated total distributable cash flow $ 1,815 ($ in millions) SPLNG distributable cash flow SPL distributable cash flow CTPL distributable cash flow CQP expenses $ 365 1,435 30 (15) (1) Assumes conversion of all subordinated units and Class B units to common units and assumes ~228 million of public and Blackstone common units, ~232 million Cheniere common units and 2% general partner interest and IDRs held by Cheniere. Actual number of common units after the completion of Trains 5-6 may be greater. Note: The above represents a single financing scenario. Estimates are as of October 2013. Estimates represent a summary of internal forecasts, are pre-tax, 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. 21 Trains 1-6 760 925 910 $ $ 2,595 $ 375 2,205 30 (15) $3.80 - $4.10
CQP Outlook Visible Future Growth Contracted LNG Export Volumes (SPL) Tbtu/yr CQP Contracted Revenues $MM Forecasted CQP Distributable Cash Flow $ per common unit 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. $4.00 $3.00 $2.00 $1.00 $0.00 Current T1-4 T1-6 $1.70 $3.00 – $3.20 $3.80 – $4.10 - - 333 795 1,046 1,328 0 400 800 1,200 1,600 2014 2015 2016 2017 2018 2019 Cheniere Marketing Train 6 Train 5 Trains 1-4 $255 $256 $1,048 $2,328 $3,010 $3,875 $0 $1,000 $2,000 $3,000 $4,000 2014 2015 2016 2017 2018 2019 Cheniere Marketing T6 T5 T1-4 Regas 22
Cheniere Estimated Steady State Cash Flows ($ in millions) Net Cash Flows Cheniere Energy, Inc. Distributions from CQP (1) Management fees CEI expenses and other 1,100 50 (85) 1,065 $ $ Potential CF generated from CMI SPA (2) $0 - $1,000 (1) Based on distributions from CQP that Includes net profits of $145MM for Trains 1-4 and $175MM for Trains 1-6 paid to SPL on the CMI SPA. See slide 20. (2) Assumes net profit of up to ~$10.00/MMBtu, which includes cost estimates for shipping. Note: The above represents a single financing scenario. Estimates are as of October 2013. Estimates represent a summary of internal forecasts, are pre-tax, 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. Annualized 23 1,685 65 (85) 1,665 $ $ Trains 1-4 Trains 1-6
Summary Organizational Structure Cheniere Energy, Inc. (NYSE MKT: LNG) Cheniere Energy Partners, L.P. (NYSE MKT: CQP) Sabine Pass LNG, L.P. (SPLNG) 58% Cheniere Energy, Inc. (1) 29% Blackstone (1) 13% Public (1) 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 Corpus Christi Liquefaction Trains 1-4 Debt $5,900 Credit Facilities due 2020 (2) $2,000 Notes due 2021 (5.625%) $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) 24 Creole Trail Pipeline (CTPL) SPL Firm Transport (1.5 Bcf/d) $400 Term Loan due 2017 (L+325) CQP GP (& IDRs) (1) Represents ownership interest before accretion of Class B units. (2) Includes $4,400 million term loan facility, $1,080 million Republic of Korea (“ROK”) covered facility and $420 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.
Appendix
Operating Assets Sabine Pass LNG Terminal Creole Trail Pipeline 26
Contracted Capacity at SPLNG Third Party Terminal Use Agreements (TUAs) 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. 27
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 with significant resources ▪ Founded in 1898 and headquarted in San Francisco ▪ 53,000+ employees Industry leading experience and results ▪ Have participated in 23,000 projects in 140 nations and seven continents (average of 200 projects per year) ▪ 2012 revenue of $38 Billion, marking the 6th consecutive record year Leading LNG Construction Contractor ▪ Constructed one third of the world's liquefaction facilities (more than any other contractor) Notable Other Non-LNG Projects ▪ 5 liquefaction projects in the last decade, 4 currently underway, all using ConocoPhillips’ Optimized Cascade® Process Select Credentials ▪ Received 35+ industry awards since 2009 ▪ Named the Top US Construction Contractor for the last 15 consecutive years by Engineering News-Record (ENR) ▪ 80% of projects completed without a lost time accident 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? LSTK EPC Contract with Bechtel Minimize Construction Costs and Risks Hoover Dam Hong Kong Int’l Airport San Francisco Rapid Transit Source: Bechtel. 28
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 expected to commence 4Q2013 Est in-service: 4Q2014 Creole Trail Pipeline 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 29 Potential expansion for Trains 5&6 Modification to reverse flow
2012 Global LNG Supply & Demand 2012 Global LNG Capacity: ~37.3 Bcf/d Natural Gas Oil Products LNG Importers - Price Indexation Japan Crude Cocktail 2012 Global LNG Demand: ~31.5 Bcf/d No r th Ame r ica S outh Ame r ica E u r ope A sia 6.5 1.4 1.1 22 A ust r alia - 3.3 B r unei - 1.0 Indonesia - 4.6 M al a y sia - 3.0 A lge r ia - 2.7 N o r w a y - 0.6 Q a tar – 9.3 R ussia - 1.3 E g ypt - 1.6 Y emen - 1.0 Nige r ia - 2.9 T r inidad & T obago - 2.0 E qua t o r ial G uinea - 0.5 Oman - 1.4 U AE - 0.8 USA - 0.2 P e r u - 0.6 Source: GIIGNL, Wood Mackenzie 30
US Proved Non-Producing Reserves Productive Capacity from Unconventional Reservoirs Tcf Bcf/d MMB/d 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 49 51 60 67 78 85 98 113 0 20 40 60 80 100 120 2003 2004 2005 2006 2007 2008 2009 2010 Source: EIA, US Crude Oil, Natural Gas and Natural Gas Liquids Proved Reserves, 2010. Source: Advanced Resource Intl; Cheniere Research. U.S. Natural Gas Markets 31 Includes Eagle Ford, Barnett Combo, Bakken, Permian, Anadarko, W. Marcellus, Utica, Cotton Valley, Piceance & Uinta US Natural Gas Resources Tcf Source: Potential Gas Committee, 2013; EIA, Natural Gas Proved Reserves, 2010 US Gas Consumptions vs. Production Source: EIA 2012 Natural Gas Annual. Tcf • 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 2,689 2,203 2,081 1,532 18.1 18.5 19.3 20.2 20.6 21.3 22.9 24.0 24.0 22.0 21.7 23.1 23.3 22.9 24.1 24.4 25.5 25.7 0 5 10 15 20 25 30 2005 2006 2007 2008 2009 2010 2011 2012 2013E 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 LNG Haynesville Bossier Granite Wash Williston Basin Bakken Primary Gas Sources for Sabine Pass Liquefaction Conventional Gulf Coast Onshore; Barnett; Haynesville; Bossier; Eagle Ford Sources: EIA (US map graphic, pipelines and LNG terminals placed by Cheniere) Advanced Resources Intl (Lower 48 Unconventional Recoverable Reserves), ARI shale estimates updated April 2010 Depicted Pipelines: Rockies Express, Texas Eastern, Trunkline, Transco, FGT, C/P/SESH/Gulf Crossing (as a single route) Rig Count Production Bcf/d Barnett 31 5.6 Haynesville 36 6.2 Eagle Ford 232 3.2 Granite Wash 106 1.6 Bakken 141 0.8 Marcellus 78 8.8 Source: Lippman Consulting and PIRA, as of May 2013 Uinta Strategically Located – Extensive Market Access to Gas 366 1,904 Lower 48 Recoverable Unconventional Reserves (Tcf) 0 500 1500 1996 2012 Shale CBM Tight Gas Total US Proved Reserves 2000 318 32
Multiple Local Pipeline Interconnections Provide Several Options for Access to Natural Gas Supply 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 33 Source: Cheniere Research
Firm Liquefaction Capacity Additions 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 13Q1 13Q2 13Q3 13Q4 14Q1 14Q2 14Q3 14Q4 15Q1 15Q2 15Q3 15Q4 16Q1 16Q2 16Q3 16Q4 17Q1 17Q2 17Q3 17Q4 18Q1 18Q2 18Q3 18Q4 2013 2014 2015 2016 2017 2018 Asia Pacific Atlantic Basin Bcf/d Skikda & Angola LNG PNG T1 & Pacific Rubiales LNG Gorgon T1, Curtis T1 & Donggi LNG Gassi Touil Curtis T2 & PNG T2 Gorgon T2, APLNG T1, SPL T1 Gladstone T1 Gorgon T3, SPL T2 APLNG T2 Ichtys T1, Wheatstone T1, Gladstone T3, Wheatstone T2, Petronas FLNG Ichtys T2, SPL T4 Prelude FLNG Nameplate Liquefaction Capacity ~ 37 Bcf/d as of YE 2012 ~ 49 Bcf/d by YE 2017 Source: Cheniere Research SPL T3 34
Conversion of Class B and Subordinated Units 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. 35
Pro Forma CQP Ownership 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 $1.5B but excluding accretion of Class B Units. (2) Currently, CQP is paying distributions on the common units and the applicable 2% distribution to the GP. Note: The above represents a summary of internal forecasts, are based on current assumptions and are subject to change. Actual performance may differ materially from, and there is no plan to update, the forecast. See “Forward Looking Statements” slide. 36 (in millions) CEI Blackstone Public Total Common units (1) 12.0 45.1 57.1 Class B units (1) 45.3 100.0 145.3 Subordinated units (1) 135.4 135.4 General Partner @ 2% 6.9 6.9 199.6 100.0 45.1 344.7 Percent of total (as of 6/30/13) 57.9% 29.0% 13.1% 100.0% Pro forma accretion YE2016 241.1 182.9 45.1 469.1 Percent of total (pro forma YE2016) 51.4% 39.0% 9.6% 100.0%
Condensed Balance Sheets As of June 30, 2013 (1) Includes intercompany eliminations and reclassifications. (2) For complete balance sheets, see the Cheniere Energy, Inc., Cheniere Energy Partners, L.P and Sabine Pass LNG, L.P. Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, filed with the SEC on August 2, 2013. (3) Restricted cash includes debt service reserves as required per Sabine Pass LNG indentures. Cash is presented as restricted at the consolidated level. 37 (in millions) Cheniere Energy Partners, L.P. Other Cheniere Energy, Inc. (1) Consolidated Cheniere Energy, Inc. (2) Cash and cash equivalents -$ 397$ 397$ Restricted cash and cash equivalents (3) 2,666 12 2,678 Accounts and interest receivable - 27 27 Property, plant and equipment, net 4,831 63 4,894 Goodwill and other assets 515 71 586 Total assets 8,012$ 570$ 8,582$ Deferred revenue and other liabilities 591$ (21)$ 570$ Long-term debt, net of discount 5,572 - 5,572 Non-controlling interest - 2,068 2,068 Capital (deficit) 1,849 (1,477) 372 Total liabilities and deficit 8,012$ 570$ 8,582$
Nancy Bui: Director, Investor Relations – (713) 375-5280, nancy.bui@cheniere.com Christina Burke: Manager, Investor Relations – (713) 375-5104, christina.burke@cheniere.com Investor Relations Contacts: