September, 2014 Cheniere Energy Barclays CEO Energy-Power Conference
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, and Quarterly Reports on Form 10-Q filed with the SEC on July 31, 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 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 (“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 MKT: 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 SPA 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 2014 Q2 Data; Base Case Scenario – includes LNG bunkering demand 21 17 24 2015 2020 2030 2015 2020 2030 4 9 38 2015 2020 2030 2015 2020 2030 Americas Asia Middle East/N. Africa 198 268 383 24 64 95 Global demand is forecast to grow from 236 mtpa (~32 Bcf/d) in 2012 to 541 mtpa (~72 Bcf/d) in 2030 ~4.7% CAGR equivalent to ~17 mtpa average growth per year (~four 4.2 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 Japan spot data sourced from METI post March 2014 @ 12% @ 15% $ $ $ $ $ $ (1) LNG Cost is calculated as 115% of Henry Hub price. Worldwide LNG Prices = 11% to 15% of Crude Oil $4.619 $6.65 $11.80 $9.85 0 2 4 6 8 10 12 14 16 18 20 J a n -1 0 A p r- 1 0 Jul -1 0 O ct -1 0 J a n -1 1 A p r- 1 1 Jul -1 1 O ct -1 1 J a n -1 2 A p r- 1 2 Jul -1 2 O ct -1 2 J a n -1 3 A p r- 1 3 Jul -1 3 O ct -1 3 J a n -1 4 A p r- 1 4 Jul -1 4 $/MMBtu Regional Natural Gas & LNG Prices July 2014 NBP NYMEX European Gas Contract Japan Spot
Cheniere Developments/Strategy Liquefaction: 9 trains - ~40.5 MTPA - ~5.5Bcf/d LNG Exports • Sabine Pass Liquefaction – 6 Train Development – 27 MTPA - ~3.8 Bcf/d in export capacity – Trains 1-4 are under construction; Train 1 on schedule for first LNG in late 2015 – Trains 5-6 are under development; FID expected 2015 • Corpus Christi Liquefaction – 3 Train Development – 13.5 MTPA - ~1.7 Bcf/d in export capacity – FID expected early 2015 Evaluating potential future projects • Horizontal / vertical integration with liquefaction platform; hydrocarbon opportunities – Domestic export infrastructure – Domestic midstream opportunities – International projects 6
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 ~72% complete (as of 7/31/2014) 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 ~39% complete (as of 7/31/2014) Operations estimated 2016/2017 Liquefaction Trains 5 & 6 – T5 Fully Contracted EPC contract under negotiation with Bechtel Permits expected 2014/2015
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 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.
SPL Construction – August 2014 10
SPL Construction – August 2014 11
Corpus Christi Liquefaction Project 12 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 will connect 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 tank, 1 berth SPAs signed covering ~7.7 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
Corpus Christi Liquefaction SPAs 13 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: ~7.65 mtpa “take-or-pay” style commercial agreements ~$1.4B annual fixed fee revenue for 20 years PT Pertamina (Persero) ~$278 MM 20 years BB+/Baa3/BBB- N/A Train 1 / Train2 $3.50 79.36 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 Gas Natural Fenosa 20 years N/A $3.50 115% of HH 20 years Gas Natural SDG, S.A. $3.50 115% of HH Train 1 / Train 2 Train 2 ~$139 MM 39.68 Iberdrola S.A. 78.20 ~$274 MM BBB/Baa2/BBB+ BBB/Baa1/BBB+ (1) 11.5% of the fee is subject to inflation for Pertamina and 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. (4) Conditions precedent must be satisfied by December 31, 2014 (Pertamina – Train 1) or June 30, 2015 (all others) 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, upon approval of the required parties at CQP, Pertamina contract will terminate and Pertamina and Sabine Pass Liquefaction will enter into an SPA with substantially similar terms. contract will transfer to Sabine Pass T6 with identical terms. Woodside Energy Trading 20 years $3.50 115% of HH Train 2 ~$154 MM 44.12 BBB+/Baa1/BBB+ Woodside Petroleum LTD 20 years $3.50 115% of HH Train 2 / Train 3 ~$140 MM 40.00 A+/Aa3/A+ N/A Électricité de France
Regulatory Approvals Needed for 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 • DOE: Non-FTA authorization is pending SPL Trains 5-6 • FERC: Original Scheduling Notice received 5/2014, update pending • DOE: Received FTA authorization • DOE: Non-FTA authorization is pending 14
FERC Applications Filed for Liquefaction Projects Corpus Christi received FERC scheduling notice on February 12, 2014; FERC approval expected 2014/2015 SPL received initial FERC scheduling notice on May 30, 2014; revised notice pending; FERC approval expected 2014/2015 15 LNG Export Projects Pre-filing Date Application Date FERC Scheduling Notice Issued EIS / EA Scheduled Date for EIS or EA Rec’d Approval Sabine Pass Liquefaction T1-4 July 26, 2010 January 31, 2011 EA 4/16/2012 Corpus Christi Liquefaction December 13, 2011 August 31, 2012 February 12, 2014 EIS October 8, 2014 Freeport LNG December 23, 2010 August 31, 2012 January 6, 2014 EIS June 16, 2014 7/30/2014 Cameron LNG April 30, 2012 December 10, 2012 November 21, 2013 EIS April 30, 2014 6/19/2014 Dominion Cove Point LNG June 1, 2012 April 1, 2013 March 12, 2014 EA May 15, 2014 Jordan Cove Energy February 29, 2012 May 22, 2013 July 16, 2014 EIS Feb. 27, 2015 Oregon LNG July 3, 2012 June 7, 2013 EIS Sabine Pass Liquefaction T5-6 February 27, 2013 September 30, 2013 May 30, 2014 EA Excelerate November 5, 2012 February 6, 2014 EIS Southern LNG December 5, 2012 March 10, 2014 EA Lake Charles LNG March 30, 2012 March 25, 2014 EIS Magnolia LNG March 20, 2013 April 30, 2014 EIS Golden Pass LNG May 16, 2013 July 7, 2014 EA 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
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 A Fully Subscribed Lake Charles 2.0 FTA + NonFTA v Fully Subscribed Dominion Cove Point 1.0 FTA + NonFTA Fully Subscribed Cameron LNG 1.7 FTA + NonFTA A Fully Subscribed Jordan Cove 1.2/0.8 FTA + NonFTA Oregon LNG 1.25 FTA + NonFTA v Cheniere Corpus Christi 2.1 FTA Partially Subscribed Cheniere Sabine Pass T5 – T6 1.3 FTA T5 Subscribed Excelerate 1.3 FTA v Southern LNG 0.5 FTA v Fully Subscribed Magnolia LNG 0.5 FTA v Partially Subscribed Golden Pass LNG 2 FTA v Fully Subscribed Freeport LNG Corpus Christi Plus other proposed LNG export projects that have not filed a FERC application. • Application filing = v • FERC scheduling notice issued = • FERC Approved = A Filed FERC Application Proposed Projects Jordan Cove Oregon LNG Cameron LNG Lake Charles Sabine Pass 16 Southern LNG Excelerate LNG
Timeline & Milestones Target Date SPL Corpus SPL Milestone T1-2 T3-4 Christi T5-6 Initiate permitting process (FERC & DOE) Commercial agreements T1-T2 T5 T6: 2014 EPC contract 2015 Financing commitments 2014 2015 Regulatory approvals 2014/15 2014/15 Issue Notice to Proceed 2015 2015 Commence operations (1) 2015/16 2016/17 2018/19 2018/19 17 (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, Santiago, and Singapore SPA with SPL for all LNG volumes not under long-term contract with other parties Chartered three LNG vessels for deliveries in 2015 and 2016 Developing complementary, 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
19 Financial Estimates
$0.3 $0.2 $1.0 $0.3 $0.5 $0.1 $0.1 $0.7 $0.5 $0.7 $1.0 - $1.2 $1.9 - $2.4 $2.6 - $3.2 $3.3 - $4.3 – $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 20 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 22.9 MTPA 28.6 MTPA(1) 29.4 MTPA(1) Short / medium term LNG sales 0 MTPA 1.6 MTPA 3.3 MTPA 5.9 MTPA(1) 8.9 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: Forecast reflects SPA signed, as of July 30, 2014. 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 21 (1) Depending on CMI’s financial performance, CEI is expected to become a corporate tax payer after its NOLs are fully exhausted, which is anticipated in either 2020 or 2021, with a ~20-25% effective tax rate on pre-tax equity cash flow. (2) EBITDA is a non-GAAP measure, and as such 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. (3) The above estimate is based on one potential financing scenario. The company is evaluating multiple scenarios and will consider alternatives in pursuit of obtaining optimal financing for the projects. Cheniere development of ~41 MTPA of US liquefaction capacity (9 trains) is expected to lead to: EBITDA of $3.3 - $4.3 billion(1)(2) (unconsolidated) CEI level debt of ~$4 billion(3) (unconsolidated) CEI share count of 238.1 million as of June 30, 2014
CQP estimated distributable cash flows ($ 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(1) 700 870 Public and BX units 735 1,035 Estimated range of DCF per unit (2) $3.00 - $3.10 $3.80 - $3.90 CQP Forecasted Distributable Cash Flows 22 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 CQH common units and 2% General Partner interest and IDRs held by Cheniere. Distributable cash flow is a non-GAAP measure, and as such 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) Depending on the number of liquefaction trains at SPL, CQH is expected to become a corporate tax payer after its NOLs are fully exhausted, which is anticipated in either 2019 or 2020, with a ~20-25% effective tax rate on pre-tax cash flow. (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 $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 23 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. Distributable cash flow is a non-GAAP measure, and as such 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. 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 ) Equates to 5-year CAGR of ~15%
Financial Strength 24 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 Demonstrated ability to raise capital, multiple options available As of June 30, 2014 CQP Other Cheniere Energy, Inc. Consolidated CEI Unrestricted cash and equivalents $0 $890 $890 Restricted cash and securities 2,515 11 2,526 Current & long-term debt $8,988 $ 0 $8,988
Cheniere’s Debt Summary As of August 2014 25 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 $2,703 Credit Facilities due 2020 (1) $2,000 Notes due 2021 (5.625%) $1,000 Notes due 2022 (6.250%) $1,500 Notes due 2023 (5.625%) $2,000 Notes due 2024 (5.750%) 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 $2,016 million term loan facility, $495 million Republic of Korea (“ROK”) covered facility and $192 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. Cheniere Energy Partners LP Holdings, LLC (NYSE: CQH) No Debt
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27 Appendix
Operating Assets 28 Sabine Pass LNG Terminal (SPLNG) Creole Trail Pipeline
Contracted Capacity at SPLNG Third Party Terminal Use Agreements (TUAs) 29 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 30 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 Contracts with Bechtel Minimize Construction Costs and Risks 31 Hoover Dam Hong Kong Int’l Airport San Francisco Rapid Transit Source: Bechtel. Bechtel was the EPC contractor for the regasification project at the Sabine 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 plant 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 Terminal Corpus Christi LNG Terminal
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 32 Angola – 0.4
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 Firm Liquefaction Capacity Additions (Bcf/d) 33 Asia Pacific Atlantic Basin Bcf/d Nameplate Liquefaction Capacity ~ 38 Bcf/d as of YE 2013 ~ 54 Bcf/d by YE 2019 Source: Cheniere Research QCLNG T1 SPL T1, Gorgon T1, APLNG T1 Gorgon T3, Wheatstone T1, Gladstone T2 Gladstone T1 Wheatstone T2 APLNG T2 SPL T3 Ichtys T1, Prelude FLNG SPL T2, Gorgon T2, Petronas FLNG1 SPL T4 Yamal T3 QCLNG T2 , Gassi Touil, Pacific Rubiales LNG Yamal T1, Ichtys T2, Petronas FLNG2 Yamal T2 Donggi LNG
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
Cheniere Marketing SPA Example Annual Profit from 2 mtpa 35 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) SPA Fee to SPL (312) Vessel Charter Costs (92) Port and Canal Costs (25) Incremental Vessel Charters (37) Financing Costs (7) Gross Profit to CMI ($MM) 395$ Add-back distributions from GP / CQH ($MM) (1) 218$ Total to CEI 613$ (1) Estimate assumes CEI receives approximately ~70% of CQP distributions through direct ownership of the General Partner and indirect ownership through CQH, and that CQP distributions achieve the 50/50 split threshold.
Conversion of Class B and Subordinated Units 36 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 37 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%
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