Cheniere Energy December 2011
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 relating to the construction or operation of each of our proposed liquefied natural gas, or LNG, terminals or our proposed pipelines or liquefaction facilities, or expansions or extensions thereof, including statements concerning the completion or expansion thereof by certain dates or at all, the costs related thereto and certain characteristics, including amounts of regasification, transportation, liquefaction and storage capacity, the number of storage tanks, LNG trains, docks, pipeline deliverability and the number of pipeline interconnections, if any; statements that we expect to receive an order from the Federal Energy Regulatory Commission, or FERC, authorizing us to construct and operate proposed LNG receiving terminals, liquefaction facilities or proposed pipelines by certain dates, or at all; statements regarding future levels of domestic natural gas production, supply or consumption; future levels of LNG imports into North America; sales of natural gas in North America or other markets; exports of LNG from North America; and the transportation, other infrastructure or prices related to natural gas, LNG or other energy sources or hydrocarbon products; statements regarding any financing or refinancing transactions or arrangements, or ability to enter into such transactions or arrangements, whether on the part of Cheniere Energy, Inc., Cheniere Energy Partners, L.P., or any of their subsidiaries or at the project level; statements regarding any commercial arrangements presently contracted, optioned or marketed, or potential arrangements, to be performed substantially in the future, including any cash distributions and revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, liquefaction or storage capacity that are, or may become, subject to such commercial arrangements; statements regarding the ability of Cheniere Energy Partners, L.P. to pay distributions to its unit holders; statements regarding the expected receipt of cash distributions from Cheniere Energy Partners, L.P. or Sabine Pass LNG, L.P.; statements regarding counterparties to our commercial contracts, construction contracts and other contracts; statements regarding any business strategy, any business plans or any other plans, forecasts, projections or objectives, including potential revenues and capital expenditures, any or all of which are subject to change; statements regarding legislative, governmental, regulatory, administrative or other public body actions, requirements, permits, 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,” and similar terms and phrases. 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. Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2011 and the Cheniere Energy Partners, L.P. Annual Report on Form 10-K/A filed with the SEC on September 12, 2011, 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 we undertake no obligation to publicly update or revise any forward-looking statements. Forward Looking Statements 1
3 Cheniere Cheniere is engaged in the development and operation of LNG terminals and pipelines and marketing of LNG and natural gas – Sabine Pass LNG Terminal became operational in 2008 and cost ~$1.6B, send-out capacity is 4.0 Bcf/d, storage capacity is 16.9 Bcfe – Sabine Pass LNG Terminal is connected to the U.S. natural gas pipeline grid through the Creole Trail pipeline and other interconnecting pipelines – Creole Trail Pipeline also became operational in 2008 and cost ~$560mm, transportation capacity is 2.0 Bcf/d, 42-inch diameter Sabine Pass LNG Creole Trail Pipeline Transco (TRANS) Trunkline (TRUNK) ANR Texas Gas Transco Florida Gas Columbia Gulf Cypress Sabine Pass LNG Terminal Sabine Pass LNG Terminal Henry Hub NGPL (NGPL) Bridgeline (BRGJB) Transco (SWLAT) Tennessee (SWLAT) Florida Gas (SWLAT) Cheniere Creole Trail Pipeline Tennessee Texas Eastern (TETCO) Gulf Coast Markets Northeast Markets Southeast Markets Midwest / Great Lakes Markets Connects with Henry Hub Zone 2 - Future Gulf of Mexico
4 Cheniere Expansion Project: Adding Liquefaction Capabilities at Sabine Pass LNG Terminal Proposed liquefaction project at the Sabine Pass LNG Terminal is being developed in phases, with two liquefaction trains per phase Nominal capacity per train is ~ 4.5 million tonnes per annum (mtpa) –Contracting 3.5 mtpa of production per train (182,500,000 MMBtu per annum) – Estimated available production above contracted quantity is up to 50 Bcf per annum per train LNG value chain: Field Development Liquefaction Shipping Regasification Pipeline End Use Current Operations Expansion Project LNG is natural gas cooled to -260ºF in order to be transported by ship to distant markets Transforming terminal into bi-directional import / export facility
5 LNG Export Service at Sabine Pass will Provide Opportunity to Arbitrage Henry Hub vs. Oil Low High Henry Hub 4.00 $ 6.50 $ Capacity Charge 2.00 3.00 Shipping 1.00 1.00 Fuel/Basis 0.60 0.98 Delivered Cost 7.60 $ 11.48 $ Low High 4.00 $ 6.50 $ 2.00 3.00 2.80 2.80 0.60 0.98 9.40 $ 13.28 $ Europe Asia ($/MMBtu) Cost to deliver gas from Sabine Pass to Europe & Asia = $8 - $13 / MMBtu Worldwide LNG prices predominantly based on oil prices = $11 - $23 / MMBtu Current LNG Market 30 – 40 Bcf/d LNG contracts indexed to oil prices – rule of thumb 11% to 15% of crude oil prices Growth Market 100 Bcf/d Power generators switching from oil to gas – paying $13 to $19 / MMBtu for fuel oil and diesel at $100/bbl 11.00 15.00 at $150/bbl 16.50 22.50 LNG Contract Price Indexation % 11% 15% $ $ $ $
6 Global Petroleum Demand – Stationary Sources Asia 6.9 MM b/d ~41 Bcf/d Europe 2.9 MM b/d ~17 Bcf/d Mid East 2.8 MM b/d ~17 Bcf/d Latin America 2.3 MM b/d ~14 Bcf/d FSU 0.9 MM b/d ~5 Bcf/d Africa 1.2 MM b/d ~7 Bcf/d US & Canada 2.2 MM b/d ~13 Bcf/d • Global oil use totals 19 million b/d (~22%) in stationary sources, such as industrial, power and heating, that could be switched to natural gas • Conversion would create 100+ Bcf/d of natural gas demand Source: PIRA Energy Group, “The Potential for Natural Gas Substitution of Stationary Petroleum Demand”, January 2010
7 Current Facility 853 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) 4.3 Bcf/d peak regasification capacity 5.3 Bcf/d of pipeline interconnection to the U.S. pipeline network Liquefaction Expansion Up to four liquefaction trains designed with ConocoPhillips’ Optimized Cascade® Process technology Six GE LM2500+ G4 gas turbine driven refrigerant compressors per train Gas treating and environmental compliance Modifications to the Creole Trail P/L Sixth tank for fourth liquefaction train Existing operational facility Proposed expansion Proposed Liquefaction Project: Brownfield Development Utilizing Existing Assets
8 DOE export authorization Definitive commercial agreements EPC contract Financing commitments 4Q11/1Q12 FERC construction authorization 2012 Commence construction 2012 Commence operations (train 1/ train 2) 2015/2016 Milestone Target Date Note: Past results not a guarantee of future performance. Significant milestones achieved for the first phase of the project- progress for two liquefaction trains First Phase of the Project: Advancing Towards Making a Final Investment Decision
9 Sale and Purchase Agreements (SPAs): Reached contract target for the first phase of the project Customers pay fixed fee based on annual contract quantity reserved plus 115% of applicable Henry Hub price for LNG delivered (total annual fixed revenues ~ $865MM) Cheniere to procure nature gas, liquefy it and load LNG onto customer’s LNG vessel *Conditions precedent must be satisfied by December 31, 2012 or either party can terminate. CPs include financing, regulatory approvals, positive final investment decision, issuance of notice to proceed and entering into common facilities agreements. Note: Termination clauses include (i) by customer if either export authorization is revoked, withdrawn or expired not as a result of force majeure, (ii) by customer if Sabine Liquefaction fails to make available 7 consecutive cargoes or 20 cargoes in a 12 month period, and (iii) by either customer or Sabine Liquefaction if the other has not paid an amount due in excess of $20 million. BG Gulf Coast LNG Gas Natural Fenosa Annual Contract Quantity 182,500,000 MMBtu (~3.5mtpa) Fees Fixed Sales Charge ($/MMBtu) $2.25 $2.49 Annual Revenue ~$411 MM ~$454 MM Term Guarantor 20 years (extension option up to 10 years)* BG Energy Holdings Limited Gas Natural SDG S.A. Guarantor Credit Rating A2/A Baa2/BBB Fee During Force Majeure Up to 24 months Up to 24 months 20 years (extension option up to 10 – 12 years)* Contract Sales Price 115% of applicable Henry Hub price for LNG delivered 115% of applicable Henry Hub price for LNG delivered Commercial contracts for target annual quantity of 7.0 mtpa 182,500,000 MMBtu (~3.5mtpa)
10 Fixed Fee: $3.00/MMBtu for trains 3 and 4 Fixed sales charge paid for annual contract quantity 115% of NYMEX Henry Hub Contract sales price paid for LNG delivered 15% charge above Henry Hub predominantly to account for fuel consumed in liquefaction process and basis differential Commercial Structure: Estimated Terms of Additional LNG SPA Contracts Cheniere will procure natural gas from pipeline interconnects, liquefy it and load LNG onto the customer’s LNG vessel (purchases are FOB) Customers must pay annual contract quantity and pay 115% of NYMEX Henry Hub for LNG delivered 1 Bcf/d = ~ $1.1B of contracted annual revenues for trains 3 & 4* Summary of Estimated Terms for Additional LNG SPA Contracts: Continuing discussions with interested parties for trains 3 and 4 * 365,000,000 MMBtu x $3/MMBtu
11 EPC Contract Signed for First Phase Total project cost for two trains expected to be $4.5B to $5.0B before financing costs – EPC Contract cost is $3.9B, subject only to change orders – Bechtel has right to submit change orders if, among other things, Bechtel is adversely affected by a delay in construction start beyond March 31, 2012 – Owner’s costs estimated between $600MM and $1B Bechtel incentivized for timely substantial completion of trains 1 & 2 – LNG exports expected to start as early as late 2015 Contract includes provisions for performance and delay liquidated damages and terminations for convenience and default Bechtel is one of the largest contractors in the world and has successfully constructed LNG terminals with the ConocoPhillips Optimized Cascade® technology Bechtel was the EPC contractor for the regasification project at the Sabine Pass LNG Terminal, which was constructed on time and on budget Entered into lump sum, turnkey contract with Bechtel for trains 1 & 2 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” cautions.
12 ConocoPhillips-Bechtel – Global LNG Collaboration Source: ConocoPhillips, Bechtel Note: Past results not a guarantee of future performance. Angola LNG not yet onstream. Not shown: Curtis LNG, Gladstone LNG, Australia Pacific LNG and Wheatstone LNG (all located in Australia) not yet onstream. Proven Designs Collaboration projects onstream ahead of schedule and exceeded expectations 1969 1999 2007 2012 2006
13 • Base site permitted • NEPA pre-filing 7/2010 for expansion • Some agencies already in agreement • Formal application filed 1/31/2011 • Completion of FERC-coordinated process for EA • Estimated approval early 2012 • Filed two applications in 8/2010 & 9/2010 • Approval to export 2 Bcf/d for 30 years to Free Trade nations received 9/2010 • Public comment period to export to non-free trade nations closed 12/13/2010 • Approval to export to non FT nations received 5/2011 Regulatory Process Update FERC: Authorization to Construct DOE: Authorization to Export DOE authorization received, FERC authorization remaining FERC publicly files an environmental assessment (EA) for the project upon finalization of draft and receipt of approval from cooperating agencies Filing may initiate a public comment period Subsequent to the comment period FERC commissioners, in their Order, will rule on the public interest of the project
14 Summary Proposed Financial Structure Cheniere to initiate financial commitment process Sabine Pass LNG, L.P. 86.8% through LP Interest 2% through GP Interest NYSE Amex US Stock Symbol: LNG NYSE Amex US Stock Symbol: CQP 11.2% LP Interest Public Unitholders Sabine Pass Liquefaction, LLC Vaporization assets Storage Berthing capacity Total TUA (1 Bcf/d) Chevron TUA (1 Bcf/d) Liquefaction TUA (2 Bcf/d) 100% Liquefaction assets BG SPA (182.5 million MMBtu per annum) Gas Natural Fenosa SPA (182.5 million MMBtu per annum) Future SPA Agreements Pipeline transport via Creole Trail Pipeline 2 Bcf/d TUA NEW DEBT NEW EQUITY Expecting to fund capital costs with combination of debt and equity
15 Estimated Financial Impact - Liquefaction Project (Annualized) Contracted Capacity Fees (1) Liquefaction Project Economics Impact to CQP(2) Impact to LNG(2) Current $253mm Stable common unit distributions ~1 x coverage supported by 20 year fixed price contracts with AA rated counterparties ~$38mm paid to CEI as mgmt fees & Common/G.P. distributions Trains 1 & 2 $865mm Allows distributions to subordinated unitholders ($230mm needed to meet annualized IQD(3)) after distributions paid to new equity holders May increase distributions to all unitholders Distributions on all units (CQP expects to have cash available to pay distributions on sub units) Receive pipeline fees Trains 3 & 4 $1,095mm Expected to further increase distributions per unit to all unitholders Cash flow to CEI increases including GP IDRs (1) Current includes only monthly reservation fees under the Chevron and Total TUAs. Trains 1&2 includes only fixed fees of $2.25/MMBtu (BG) and $2.49/MMBtu (Gas Natural); Trains 3&4 include only fixed fees estimated at $3.00/MMBtu. (2) Actual net distributable cash flow will depend upon various factors, including debt service payments for amortization and interest, operating expenses, etc. (3) IQD - initial quarterly distribution per unit is $0.425 as defined in the CQP partnership agreement. 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” cautions. Cheniere expected to benefit from distributions received through its CQP ownership and management contracts, and fees paid to Creole Trail Pipeline
CHENIERE ENERGY Financial
17 Customer Annual SPA Pmt BG Gulf Coast LNG $411MM Gas Natural Fenosa $454MM Organizational Structure 11.2% LP Interest 100% Ownership Interest Cheniere Energy Partners, L.P. $205 mm 2.25% Convertible Senior Unsecured Notes due 2012 NYSE Amex US: LNG NYSE Amex US: CQP $298 mm 9.75% Term Loan due 2012 $282 mm 12.0% Senior Secured Loans due 2018 Note: Abridged version of organization structure. Balances as of September 30, 2011. Sabine Pass LNG, L.P. Sabine Pass Liquefaction, LLC Cheniere LNG, Inc. Creole Trail Pipeline Other Pipeline Projects 100% Ownership Interest 86.8% thru LP Interest 2% thru GP Interest $550 mm 7.25% Senior Secured Notes due 2013 $1,666 mm 7.50% Senior Secured Notes due 2016 Public Unitholders 100% Ownership Interest 100% Ownership Interest Cheniere LNG Holding, LLC 100% Ownership Interest Customer Annual TUA Pmt Total $124MM Chevron $129MM Investments $252MM Cheniere Energy Investments, LLC (“Investments”)
18 $ $ Estimated CQP Distributable Cash Flows Annualized estimates pre-Liquefaction Project Receipts* TUAs – Chevron and Total Other Services Total Cash Receipts *Estimates represent a summary of internal forecasts for 2011, 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” cautions. Available for Distributions to Common and G.P. (DCF) * Investments TUA revenue and expense eliminated in consolidated CQP presentation. ** Not included in disbursements above is an estimate of up to $11MM for management services provided by Cheniere to CQP payable on a quarterly basis provided cash is available after common unit distributions are paid and any prudent or necessary reserves are kept. CQP can accrue up to $20MM of fees should cash not be available. 253 16 269 1 53 0 54 55 $ General Partner Common Units Subordinated Units Total Distributions Paid from Available Cash Distributions Paid Based on DCF Costs* Operating, G&A, Maintenance CapEx Debt Service Total Costs 49 165 214 $ Future cash receipts expected from Liquefaction Project ($ in MM) $ 0 – 250 Available for Management Fees(1) & Sub Units Potential Future Cash Flows Regas Capacity (from VCRA) $ 0 – 250
19 CQP Ownership Common Units Subordinated Units General Partner @ 2% 19.0 12.0 135.4 3.4 Public Cheniere Energy, Inc. 19.0 150.8 (in mm) 31.0 135.4 3.4 169.8 Total 88.8% 11.2% 100% Percent of total * CQP Ownership as of September 30, 2011. - - Currently, CQP generates distributable cash flows (DCF) sufficient to pay only the IQD on the common units and applicable 2% to the GP Prior to the development of the liquefaction project, the subordinated units may receive distributions from new business at CQP or from fees received from the VCRA with Cheniere Marketing Upon commencement of DCF being generated from the liquefaction project, CQP expects to have cash available to pay distributions on the subordinated units up to the IQD in accordance with the cash waterfall in the CQP partnership agreement
20 Disbursements G&A, net marketing Pipeline & tug services Other, incl advance tax payments Debt service Receipts Distributions from CQP (Common/GP) Distributions from CQP (Subordinated Units) Management fees from CQP 45 - 55 *Estimates represent a summary of internal forecasts for 2011, 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” cautions. Estimates exclude earnings forecasts from operating activities. **Approximately $11 million is fees for management services provided by Cheniere to CQP payable on a quarterly basis, equal to the lesser of 1) $2.5 million (subject to inflation) or 2) such amount of CQP’s unrestricted cash and cash equivalents as remains after CQP has distributed in respect of each quarter for each common unit then outstanding an amount equal to the IQD and the related GP distribution and adjusting for any cash needed to provide for the proper conduct of the business of CQP, other than Sabine Pass operating cash flows reserved for distributions in respect of the next four quarters. Net cash outflow Marketing activity / subordinated unit dist. ? 21 0 8-19 25 – 35 10 3 – 5 35 $ $ Existing LNG cash receipts (below) expected to increase from CQP Liquefaction Project - unit distributions, management fees and Creole Trail P/L tariffs Estimated LNG Net Cash Flows* Annualized estimates pre-Liquefaction Project **
21 Condensed Balance Sheets As of September 30, 2011 Cheniere Energy Other Cheniere Consolidated Partners, L.P. Energy, Inc. (1) Cheniere Energy, Inc. (2) Unrestricted cash and equivalents $ - 131 $ 131 $ Restricted cash and securities (3) 232 3 235 Property, plant and equipment, net 1,524 596 2,120 Goodwill and other assets 47 114 161 Total assets 1,803 $ 848 $ 2,651 $ Deferred revenue and other liabilities 136 $ - $ 136 $ Current & long-term debt 2,191 771 2,962 Non-Controlling interest - 218 218 Deficit (524) (141) (665) 1,803 $ 848 $ 2,651 $ (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 Reports on Form 10-Q for the period ended September 30, 2011, filed with the SEC. (3) Restricted cash includes debt service reserves as required per Sabine Pass indenture. Cash is presented as restricted at the consolidated level. - Accounts and interest receivable - 4 4 Total liabilities and deficit ($ in MM)
CHENIERE ENERGY U.S. Natural Gas Markets
23 U.S. Natural Gas Consumption vs. Production Source: EIA historical, September 2011 Short-Term Energy Outlook (2011 data) Hot Summer & Cold Winter Since 2005 U.S. production growth ~ 4.9 Tcf vs. demand growth ~ 2.6 Tcf Net imports declined ~1.6 Tcf (-50%) over the period ~ 1 Tcf production added each year since 2006 The U.S. is on pace to be a net gas exporter by mid-decade US Gas Production 18.0 18.5 19.3 20.1 20.6 21.6 22.9 22.0 21.7 23.1 23.2 22.8 24.1 24.6 0 5 10 15 20 25 30 2005 2006 2007 2008 2009 2010 2011E Tcf U.S. Gas Consumption U.S. Gas Production
24 U.S. Proved Non-Producing Reserves Source: EIA, US Crude Oil, Natural Gas and Natural Gas Liquids Proved Reserves, 2009 Non-producing proved U.S. gas reserves +100% since 2003 to 98 Tcf Equivalent to 13 Bcf/d of LNG exports for 20+ years Over 3,000 gas wells drilled but not hooked up representing ~8-10 Bcf/d of latent 1st -year production 49 51 60 67 78 85 98 2003 2004 2005 2006 2007 2008 2009 (Tcf)
25 Emerging shale plays erase “oil” and “gas” drilling distinction Horizontal drilling +750% since 2005; pace of rig construction determines market capacity U.S. Horizontal Rigs Source: Baker Hughes HZ Rigs Barnett Shale HZ Drilling Expands - 200 400 600 800 1,000 1,200 Jan- 91 Jan- 93 Jan- 95 Jan- 97 Jan- 99 Jan- 01 Jan- 03 Jan- 05 Jan- 07 Jan- 09 Jan- 11
26 Oil Production Drives Investment Decisions for Gas Bcf/d MMB/d Source: Advanced Resource Intl; Cheniere Research Expected liquids production from shale plays > 3 million b/d by 2020 Associated natural gas > 7 Bcf/d of “costless” supply 0 1 2 3 4 5 6 7 8 2010 2011E 2012E 2013E 2014E 2015E 2020E 0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Includes Eagle Ford, Bakken Shales; Granite Wash, Piceance & Uinta Tight Sands Liquids Gas Annual Production from Unconventional Reservoirs
27 Venting and Flaring The U.S. vented and flared 165 Bcf of natural gas in 2009 North Dakota’s share amounted to 27 Bcf; +156% increase from 2007 There are “New Bakkens” emerging in liquids-rich shale plays (Eagle Ford, Niobrara, Permian, Granite Wash) Source: EIA 0 20 40 60 80 100 120 140 160 180 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Bcf North Dakota U.S. Total
28 U.S. Natural Gas Resources (Tcf) Source: DOE, Annual Energy Outlook 2009-2011 2008 2009 2010 2011 Other Shale Estimated U.S. reserves increased by 86% in last 3 years to 2,543 Tcf Represents 100+ years of natural gas resources 1,365 1,747 2,119 2,543
CHENIERE ENERGY LNG Fundamentals
30 Global LNG Market A sia E u r o p e South America 2010 Total Global LNG Liquefaction Capacity ~37 Bcf/d N o r th A me r i c a 18 8.6 1.8 1.3 A ust r alia - 3.1 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 Equatorial Guinea – 0.5 Oman - 1.4 U AE - 0.8 USA - 0.2 P e r u - 0.6 2010 Regional LNG Demand – 30 Bcf/d LNG Importers – Price Indexation Oil Products Natural Gas JCC Source: Waterborne, Cheniere Research
31 Q4 Q1 Q1 Q1 Q1 Q1 Q2 Q2 Q1 Q2 Q3 Q2 Q3 Q4 Q2 Q3 Q4 Q2 Q3 Q4 Q2 Q3 Q4 Q3 Q4 Q1 Q3 Q4 Firm Liquefaction Capacity Additions Source: Cheniere Research - 0.5 1.0 1.5 2.0 2.5 3.0 Bcf/d Middle East Gulf Asia Pacific Atlantic Basin Nameplate Liquefaction Capacity ~ 37 Bcf/d by YE 2010 ~ 44 Bcf/d by YE 2015 2009 2010 2011 2012 2013 2014 2015 Angola LNG Skikda Gorgon T1 & Gassi Touil Papua New Guinea Gorgon T2 & Curtis T1 Gorgon T3 & Curtis T2 Gladstone T1 T1 Pluto
32 Market Call for LNG (Bcf/d) Average 2010 LNG demand of 30 Bcf/d at 10-year historical compound average growth rate of 7% per year equates to ~42 Bcf/d of demand in 2015 Next wave of LNG supply expected to come from Australian and U.S. LNG projects 17.8 8.6 1.8 1.3 0.3 Asia Pacific Europe North America South America Middle East 2010 LNG Demand Source: Waterborne, Poten & Partners, Cheniere Research
33 Attractive Oil Linked Market Prices ~ 12% – 15% of Oil Prices Source: PIRA, Platts $3.55 $8.71 $16.64 $12.21 Regional Natural Gas & LNG Prices $/MMBtu NBP IFERC HH Monthly Japan avg LNG European Gas Contract Spread between oil linked and U.S. natural gas prices ~ $9–$13/MMBtu 0 4 8 12 16 20 Ja n-0 4 Ap r-0 4 Ju l-0 4 Oc t-0 4 Ja n-0 5 Ap r-0 5 Ju l-0 5 Oc t-0 5 Ja n-0 6 Ap r-0 6 Ju l-0 6 Oc t-0 6 Ja n-0 7 Ap r-0 7 Ju l-0 7 Oc t-0 7 Ja n-0 8 Ap r-0 8 Ju l-0 8 Oc t-0 8 Ja n-0 9 Ap r-0 9 Ju l-0 9 Oc t-0 9 Ja n-1 0 Ap r-1 0 Ju l-1 0 Oc t-1 0 Ja n-1 1 Ap r-1 1 Ju l-1 1 Oc t-1 1
CHENIERE ENERGY Appendix
35 Everett Cove Point Elba Island Lake Charles Sabine Pass Freeport Golden Pass Cameron Costa Azúl Canaport Altamira Source: Websites of Terminal Owners Terminal Capacity Holder Baseload Sendout (MMcf/d) Canaport 1,000 Repsol Everett - Suez 700 Cove Point 1,800 BP, Statoil, Shell Elba Island 1,800 BG, Marathon, Shell Gulf LNG 1,300 Angola LNG, ENI Lake Charles - BG 1,800 Freeport 1,500 ConocoPhillips, Dow, Mitsui Sabine Pass 4,000 Total, Chevron, Cheniere Cameron 1,500 Sempra, ENI Golden Pass 2,000 ExxonMobil, ConocoPhillips, QP Altamira 700 Shell, Total Costa Azul 1,000 Shell, Sempra, Gazprom Total 19,100 North America Onshore Receiving Terminals Gulf LNG Existing terminals with proposed liquefaction projects
Cheniere Energy Contacts Katie Pipkin, Vice President Finance & Investor Relations (713) 375-5110 – katie.pipkin@cheniere.com Christina Burke, Manager Investor Relations (713) 375-5104 – christina.burke@cheniere.com CHENIERE ENERGY