December 8, 2015
Cheniere Energy, Inc.
Wells Fargo Energy Symposium
Forward Looking Statements
This presentation contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included or incorporated by reference herein
are “forward-looking statements.” Included among “forward-looking statements” are, among other things:
statements regarding the ability of Cheniere Energy Partners, L.P. to pay distributions to its unitholders or Cheniere Energy Partners LP Holdings, LLC 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 liquefied natural gas (“LNG”) terminals, liquefaction facilities,
pipeline facilities or other projects, or any expansions thereof, by certain dates or at all;
statements that Cheniere Energy, Inc. expects to commence or complete construction of its proposed LNG terminals, liquefaction facilities, pipeline facilities or other
projects by certain dates or at all;
statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North
America and other countries worldwide, or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure, or demand
for and prices related to natural gas, LNG or other hydrocarbon products;
statements regarding any financing transactions or arrangements, or ability to enter into such transactions;
statements relating to the construction of our proposed liquefaction facilities and natural gas liquefaction trains (“Trains”), 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 development and 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 our 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,” “goals,” “opportunities,” “plan,” “potential,” “project,” “propose,” “subject to,” “strategy,” “target,” and similar terms and phrases, or by use of future tense.
Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations
may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Our actual results could
differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in “Risk Factors” in the Cheniere Energy, Inc.,
Cheniere Energy Partners, L.P. and Cheniere Energy Partners LP Holdings, LLC Annual Reports on Form 10-K filed with the SEC on February 20, 2015, 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
Executing on Strategy
2025 Forecast for CEI
Flexible,
Scalable,
industry-
leading
platform
$50B+
~60 mtpa
LNG by
2025
One of the largest
natural gas buyers in
the U.S.
~9 Bcf/d
Supporting over
200,000 indirect jobs
~1,000
permanent
jobs created
One of the largest
exporters of LNG on
a global basis
~14%
of the
total LNG market
in U.S.
infrastructure
Significant investment
in U.S. infrastructure
3
Cheniere’s Key Businesses
Four planned LNG
terminals to be
located along Gulf
of Mexico
~60 mtpa planned
Scalable platform
SPL T1-5 and CCL 1-
2 underpinned by
long-term contracts,
competitive capital
costs
LNG sales, FOB or
DES, provided to
customers on a
short, mid, and
long-term basis
~9 mtpa LNG
volumes expected
from SPL T1-6 and
CCL T1-3
3 chartered LNG
vessels to date
Developing/
investing in
infrastructure to
facilitate
hydrocarbon
revolution in Texas
and beyond
Optimize value of
LNG platform
Identify
opportunities in
related markets
Providing feedstock
for LNG production
Redundant pipeline
capacity ensures
reliable gas
deliverability
Upstream pipeline
capacity provides
access to diverse
supply sources
LNG
PLATFORM
GAS
PROCUREMENT
CHENIERE
MARKETING
FUTURE
DEVELOPMENTS
4
Projected Global LNG Demand 436 mtpa by 2025
22 19 23
2015
2020 2025
2015 2020 2025
6
10 17
2015 2020
2025
2015 2020 2025
Americas
Asia
Middle East/N. Africa
184
260
305
31
78
92
Europe
Source: Wood Mackenzie
Q3 2015 LNG Tool
(1) Assumes 85% utilization of nameplate capacity
Demand forecasted to increase by 193 mtpa to 2025, a 6% CAGR
Average of 23 mtpa of new liquefaction capacity needed each year
(1)
5
U.S. Expected To Become One of the Top Three LNG Suppliers
Projected LNG Liquefaction Capacity
2014 Global LNG Liquefaction Capacity: ~37 Bcf/d
6
United States
77
mtpa
68
mtpa
Qatar
Source: Wood Mackenzie Q3 2015
Cheniere
2014 2025
2014
2025
2014
2025
MEG
MEG
Rest of World
Includes Existing and
Under Construction
Projects
2014: 171 mtpa
2025: 189 mtpa
AB
2014
2025
AB
AP
AP
1.4
mtpa
26
mtpa
81
mtpa
Australia
Cheniere
Sabine Pass T1-6
Corpus Christi T1-5
Parallax
2025
64
mtpa
under
const.
31.5
mtpa
under
const.
94
mtpa
60
mtpa
Cheniere LNG Platform
Sabine Pass
Liquefaction
TX
LA
Creole Trail PL
Sabine Pass Liquefaction
• 6 train development – 27 mtpa
(~3.8 Bcf/d in export capacity)
• Trains 1-5 are under construction;
First LNG expected in late 2015
• Train 6 under development,
FID expected 2015/16
Corpus Christi
Liquefaction
7
Corpus Christi Liquefaction
• 5 train development – 22.5 mtpa
(~3.2 Bcf/d in export capacity)
• Trains 1-2 are under construction; First
LNG expected in late 2018
• Train 3 under development; FID
expected 2015/16
• Trains 4-5 under development;
Permitting process initiated June 2015
Live Oak
LNG
Live Oak LNG
1
• ~5 mtpa development
(~0.8Bcf/d)
• First LNG targeted in late 2021
Louisiana LNG
1
• ~5 mtpa development
(~0.7Bcf/d)
• First LNG targeted in late 2021
Louisiana
LNG
Under Construction
Proposed
(1) Cheniere Energy, Inc. has agreed in principle to partner with Parallax Enterprises, LLC on these projects
Aerial View of SPL Construction – August 2015
Train 1
Train 3
Train 4
Propane Condenser Area
T2 Ethylene Cold Box
T2 Methane Cold Box
Train 2
Air Coolers
T1 Methane Cold Box
T1 Ethylene Cold Box
T3 Ethylene Cold Box
T3 Methane Cold Box
Train 5
T5 Soil Stabilization
Train 6 Under Development
Forecast Cheniere LNG Portfolio Summary
Approximately 87% of LNG volumes for trains under construction are underpinned with LT
SPAs, cash flows support current project debt of $21.5B
20-year LT SPAs with investment-grade counterparties
For the balance of LNG volumes, long-term contracts are no longer required; Cheniere
expects to sell LNG under shorter-term contracts or on a spot basis
9
SPL
Trains 1
-
6
CCL
Trains 1
-
3
Total
CCL
Trains 4
-
5
LO &
LLNG
1
Total
Design Capacity
27.0 13.5 40.5 9.0 ~10 ~59.5
Under Construction
(underpinned by LT SPAs)
22.5
(~88% sold)
9.0
(~85% sold)
31.5
(~87% sold)
In Permitting
In Permitting
31.5
(~87% sold)
LT SPAs Target
(sold to date)
21.25
(19.8 )
10.5
(8.4)
31.75
(28.2)
- -
31.75
(28.2)
Excess Volumes:
Customized
Contracts/CMI
5.75 3.0 8.75 9.0 ~10 ~27.75
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. We have not made any forecast of net income, which would be the most comparable financial measure under GAAP, and we are unable to
reconcile differences between forecasted 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.
(in MTPA)
(1) Cheniere Energy, Inc. has agreed in principle to partner with Parallax Enterprises, LLC on these projects
Cheniere’s LNG Export Projects
Underpinned with Attractive SPA Features
10
Proven record of execution; proven technology
SPAs feature parent guarantees & HH + fixed fee (no price reopeners)
Cheniere LNG SPAs: LNG price tied to Henry Hub, destination flexibility,
upstream gas procurement services, no lifting requirements
$7.7
$9.5
$12.0
$14.0
$14.5
$13.0
$8.4
$11.5
$13.0
$16.0
$17.0
$18.5
$5
$10
$15
$20
Cheniere Gulf Coast West Africa Western Canada Northwest Australia East Africa Southeast Asia
LNG prices ($/MMBtu)
Cheniere Offers Competitive, Low Cost Source of LNG
The U.S. is one of the lowest cost natural gas providers in the world
U.S. liquefaction project costs are also significantly lower due to less project
development needed
The breakeven LNG price for Cheniere LNG export facilities is one of the lowest
compared to other proposed LNG projects
11
Estimated b
reakeven LNG pricing range, Delivered Ex-Ship to Asia
Source: Cheniere Research, Wood Mackenzie, company filings and investor materials.
Note: Breakeven prices derived assuming unlevered after-tax returns of 10% on Canadian projects and 12% on all other projects over construction plus 20 years of operation. Henry Hub at $3.00/MMBtu
($ in billions, except for per share amounts)
Corpus Christi
(CCL T1-2)
Total CEI standalone
CEI cash flow build up (2021 estimated amounts)
Project EBITDA / Deconsolidated for standalone $3.0 $1.3 $4.3 $2.3
Less: Project-level interest expense ($1.0) ($0.5) ($1.5) ($0.5)
Distributable cash flow from project $2.1 $0.8 $2.9 $1.8
% cash flows to CEI (Adjusted for minority interests) 49% 100%
Project cash flows to CEI (Adjusted for minority interests) $1.0 $0.8 $1.8
Total project cash flows to CEI $1.0 $0.8 $1.8
Plus: Management fees to CEI $0.1
Less: CEI G&A ($0.3)
Less: CEI-level interest expense ($0.0)
CEI cash flow $1.6
CEI cash flow per share $6
Current debt outstanding
SPL and CCL project-level debt outstanding
(2)
$13.1 $8.4 $21.5 –
SPLNG and CTPL project-level debt outstanding $2.5 – $2.5 –
CEI-level debt outstanding – – – $0.6
Total debt outstanding $15.6 $8.4 $24.0 $0.6
CQP
(SPL T1-5/SPLNG/CTPL)
(1)
(3)
(3)
(3)
(1)
(1)
7-train CEI cash flow estimate – Current market snapshot
SPL T1-5, CCL T1-2
7
-train CEI cash flow estimate – Current market snapshot | SPL T1-5, CCL T1-2
7 trains currently under construction financed with non-recourse project level debt – SPL T1-5 (CQP) and CCL T1-2 (CEI)
Based on 27.4 MTPA of 20-year SPAs; assumes remaining LNG sold to Europe at current market prices and shipping rates –
NBP price of $6.32/MMBtu, Henry Hub price of $2.54/MMBtu, shipping day rates of $30,000/day
(4)
For scenario shown above, estimated income tax payments of ~15% of CEI pre-tax cash flow projected to start in 2023/24
12
Note: See “Forward Looking Statements” slide. Cash flow build up scenario above assumes refinancing of SPL and CCH credit facilities with non-amortizing project bonds.
SPL, SPLNG, CTPL and CCL-level project debt shown above are non-recourse to CEI.
EBITDA, distributable cash flow, deconsolidated cash flow, cash flow and cash flow per share are non-GAAP measures. 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. We have not made any forecast of net income, which would be the most
comparable financial measure under GAAP, and we are unable to reconcile differences between forecasted non-GAAP measures and net income. Non-GAAP measures have limitations as an analytical tool and
should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and should be evaluated only on a supplementary basis.
(1) ~$2.3 billion of deconsolidated cash flow to CEI calculated as ~$1.0 billion of CQP distributable cash flow (net of minority interest), plus ~$1.3 billion of CCL Trains 1‐2 EBITDA. CEI stand‐alone EBITDA is
estimated to be ~$2.1 billion calculated as ~$2.3 billion of deconsolidated cash flow to CEI, plus $0.1 billion of management fees, less ~$0.3 billion of CEI G&A.
(2) CCL project-level debt issued at Cheniere Corpus Christi Holdings, LLC (CCH) entity.
(3) Assumes ~276 million CEI shares outstanding for 7-train case – assumes conversion of $1.0 billion PIK Convertible Notes due in 2021 at $93.64/share and conversion of $1.0 billion Senior Secured Convertible
Notes due 2025 at $100/share.
(4) Source: Bloomberg, DTN ProphetX and Platts, as of October 13, 2015.
Estimated Market Prices Profitable for Cheniere LNG Projects
13
As shown in sensitivity table above, Cheniere can profitably sell LNG into key demand centers
even in periods of lower market prices
If LNG prices remain at lower levels, we would expect LNG demand to increase, thus signaling
the need for more liquefaction projects. Cheniere positioned as a low-cost supplier
Cheniere can profitably provide LNG to global buyers at attractive prices
Assumes Henry Hub price of $3.00/MMBtu, shipping cost to Europe of $1.00/MMBtu and shipping cost to Asia of $2.25/MMBtu.
Market price sensitivity
Europe LNG
sale price ($/MMBtu)
$7.00
$9.00
$11.00
$13.00
Implied margin
$2.50
$4.50
$6.50
$8.50
Asia LNG
sale price ($/MMBtu
)
$9.00
$11.00
$13.00
$15.00
Implied margin
$3.25
$5.25
$7.25
$9.25
($ in billions, except for per share amounts)
Run-rate scenarios from 2021E to 2025E
7 trains
(2021E)
9 trains
(2021E)
11 trains
(2023E)
11 trains,LO&LLNG
(2025E)
SPL T1-5/6 and SPLNG via GP/IDR and CQH $1.1 $1.3 $1.3 $1.3
Management fees $0.1 $0.1 $0.1 $0.2
Mid-scale LNG – – – $1.2
CCL T1-2/3/5 $1.3 $2.0 $3.4 $3.4
CMI profit share – – – –
Total $2.5 $3.5 $4.8 $6.1
Less: CEI G&A ($0.3) ($0.3) ($0.3) ($0.3)
CEI EBITDA $2.2 $3.2 $4.6 $5.8
CEI EBITDA per share $8 $11 $16 $20
Example CEI EBITDA Build Up – Europe @ $7.50 / Asia @ $8.75
SPL T1-6, CCL T1-3, CCL T4-5, Live Oak/Louisiana LNG
CEI EBITDA build up (deconsolidated)
7 trains currently under construction
7-train case assumes 27.4 MTPA of 20-year SPAs; all other build out cases assume 31.75 MTPA of 20-year SPAs
Assumes remaining LNG all sold to Europe for $7.50/MMBtu or Asia for $8.75/MMBtu
14
Note: See “Forward Looking Statements” Slide.
Cash flow build up scenario above assumes refinancing of SPL and CCH credit facilities with non-amortizing project bonds and early release of SPL cash flows earmarked for construction via public CQP unit issuances.
Cash flow build up scenario above requires either incremental CEI, or project-level financing, or combination of both, to fund project build out. Assumes ~276 million CEI shares outstanding for 7-train case – assumes
conversion of $1.0 billion PIK Convertible Notes due in 2021 at $93.64/share and conversion of $1.0 billion Senior Secured Convertible Notes due 2025 at $100/share. All other cases shown assume ~283 million CEI
shares outstanding – incremental shares related to funding of committed additional $0.5 billion of Senior Secured Convertible Notes due 2025 and conversion at $140/share.
EBITDA and EBITDA per share are non-GAAP measures. 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. We have not made any forecast of net income, which would be the most comparable financial measure under GAAP, and we are unable to reconcile
differences between forecasted EBITDA and net income. EBITDA has limitations as an analytical tool and should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and
should be evaluated only on a supplementary basis.
Estimates based on assessment of current and potential future project development opportunities, which, among other things, would require acceptable commercial and financing arrangements, and may require
regulatory approvals before we make final investment decisions. Actual performance may differ materially from the goals. Assumes future long term contracting of additional ~2.1 MTPA at CCL Train 3 (total of 10.5
MTPA of long term SPAs at CCL Trains 1-3), 1.5 MTPA at SPL Train 6 (total of 21.25 MTPA of long term SPAs at SPL Trains 1-6) at $3.50 per MMBtu. For illustrative purposes; assumes excess volumes sold by CMI at
above prices.
•For 9 train build out, 8.75 MTPA available for CMI portfolio. For 11 train build out, incremental 9.0 MTPA available for CMI.
•With mid-scale LNG projects, incremental 10.4 MTPA available for CMI.
•All scenarios assume 100% utilization of capacity available.
($ in billions, except for per share amounts)
Run-rate scenarios from 2021E to 2025E
7 trains
(2021E)
9 trains
(2021E)
11 trains
(2023E)
11 trains,LO&LLNG
(2025E)
SPL T1-5/6 and SPLNG via GP/IDR and CQH $1.1 $1.3 $1.3 $1.3
Management fees $0.1 $0.1 $0.1 $0.2
Mid-scale LNG – – – $2.3
CCL T1-2/3/5 $1.3 $2.0 $3.4 $3.4
CMI profit share $0.4 $0.9 $1.9 $1.9
Total $2.9 $4.4 $6.7 $9.0
Less: CEI G&A ($0.3) ($0.3) ($0.3) ($0.3)
CEI EBITDA $2.6 $4.1 $6.4 $8.7
CEI EBITDA per share $9 $14 $23 $31
Example CEI EBITDA Build Up – Europe @ $9.50 / Asia @ $10.75
SPL T1-6, CCL T1-3, CCL T4-5, Live Oak/Louisiana LNG
15
7 trains currently under construction
7-train case assumes 27.4 MTPA of 20-year SPAs; all other build out cases assume 31.75 MTPA of 20-year SPAs
Assumes remaining LNG all sold to Europe for $9.50/MMBtu and Asia for $10.75/MMBtu
CEI EBITDA build up (deconsolidated)
15
Note: See “Forward Looking Statements” Slide.
Cash flow build up scenario above assumes refinancing of SPL and CCH credit facilities with non-amortizing project bonds and early release of SPL cash flows earmarked for construction via public CQP unit issuances.
Cash flow build up scenario above requires either incremental CEI, or project-level financing, or combination of both, to fund project build out. Assumes ~276 million CEI shares outstanding for 7-train case – assumes
conversion of $1.0 billion PIK Convertible Notes due in 2021 at $93.64/share and conversion of $1.0 billion Senior Secured Convertible Notes due 2025 at $100/share. All other cases shown assume ~283 million CEI
shares outstanding – incremental shares related to funding of committed additional $0.5 billion of Senior Secured Convertible Notes due 2025 and conversion at $140/share.
EBITDA and EBITDA per share are non-GAAP measures. 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. We have not made any forecast of net income, which would be the most comparable financial measure under GAAP, and we are unable to reconcile
differences between forecasted EBITDA and net income. EBITDA has limitations as an analytical tool and should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and
should be evaluated only on a supplementary basis.
Estimates based on assessment of current and potential future project development opportunities, which, among other things, would require acceptable commercial and financing arrangements, and may require
regulatory approvals before we make final investment decisions. Actual performance may differ materially from the goals. Assumes future long term contracting of additional ~2.1 MTPA at CCL Train 3 (total of 10.5
MTPA of long term SPAs at CCL Trains 1-3), 1.5 MTPA at SPL Train 6 (total of 21.25 MTPA of long term SPAs at SPL Trains 1-6) at $3.50 per MMBtu. For illustrative purposes; assumes excess volumes sold by CMI at
above prices.
•For 9 train build out, 8.75 MTPA available for CMI portfolio. For 11 train build out, incremental 9.0 MTPA available for CMI.
•With mid-scale LNG projects, incremental 10.4 MTPA available for CMI.
•All scenarios assume 100% utilization of capacity available.
($ in billions, except for per share amounts)
Run-rate scenarios from 2021E to 2025E
7 trains
(2021E)
9 trains
(2021E)
11 trains
(2023E)
11 trains,LO&LLNG
(2025E)
SPL T1-5/6 and SPLNG via GP/IDR and CQH $1.1 $1.3 $1.3 $1.3
Management fees $0.1 $0.1 $0.1 $0.2
Mid-scale LNG – – – $3.4
CCL T1-2/3/5 $1.3 $2.0 $3.4 $3.4
CMI profit share $0.9 $1.8 $3.7 $3.7
Total $3.3 $5.3 $8.6 $11.9
Less: CEI G&A ($0.3) ($0.3) ($0.3) ($0.3)
CEI EBITDA $3.0 $5.0 $8.3 $11.6
CEI EBITDA per share $11 $18 $29 $41
Example CEI EBITDA Build Up – Europe @ $11.50 / Asia @ $12.75
SPL T1-6, CCL T1-3, CCL T4-5, Live Oak/Louisiana LNG
16
CEI EBITDA build up (deconsolidated)
7 trains currently under construction
7-train case assumes 27.4 MTPA of 20-year SPAs; all other build out cases assume 31.75 MTPA of 20-year SPAs
Assumes remaining LNG all sold to Europe for $11.50/MMBtu and Asia for $12.75/MMBtu
16
Note: See “Forward Looking Statements” Slide.
Cash flow build up scenario above assumes refinancing of SPL and CCH credit facilities with non-amortizing project bonds and early release of SPL cash flows earmarked for construction via public CQP unit issuances.
Cash flow build up scenario above requires either incremental CEI, or project-level financing, or combination of both, to fund project build out. Assumes ~276 million CEI shares outstanding for 7-train case – assumes
conversion of $1.0 billion PIK Convertible Notes due in 2021 at $93.64/share and conversion of $1.0 billion Senior Secured Convertible Notes due 2025 at $100/share. All other cases shown assume ~283 million CEI
shares outstanding – incremental shares related to funding of committed additional $0.5 billion of Senior Secured Convertible Notes due 2025 and conversion at $140/share.
EBITDA and EBITDA per share are non-GAAP measures. 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. We have not made any forecast of net income, which would be the most comparable financial measure under GAAP, and we are unable to reconcile
differences between forecasted EBITDA and net income. EBITDA has limitations as an analytical tool and should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and
should be evaluated only on a supplementary basis.
Estimates based on assessment of current and potential future project development opportunities, which, among other things, would require acceptable commercial and financing arrangements, and may require
regulatory approvals before we make final investment decisions. Actual performance may differ materially from the goals. Assumes future long term contracting of additional ~2.1 MTPA at CCL Train 3 (total of 10.5
MTPA of long term SPAs at CCL Trains 1-3), 1.5 MTPA at SPL Train 6 (total of 21.25 MTPA of long term SPAs at SPL Trains 1-6) at $3.50 per MMBtu. For illustrative purposes; assumes excess volumes sold by CMI at
above prices.
•For 9 train build out, 8.75 MTPA available for CMI portfolio. For 11 train build out, incremental 9.0 MTPA available for CMI.
•With mid-scale LNG projects, incremental 10.4 MTPA available for CMI.
•All scenarios assume 100% utilization of capacity available.
Gas Procurement
Sabine Pass Terminal
Securing feedstock for LNG
production with balanced
portfolio approach
• To date, have entered into term
gas supply contracts with
producers under 1-7 year
contracts
• Supply contracts cover ~50% of
the required daily load for Trains
1-4 at Sabine Pass
• Pricing averages HH - $0.10
discount
Redundant pipeline capacity helps ensure reliable gas deliverability
• To date, we have secured firm pipeline transportation capacity of
approximately ~4.2 Bcf/d of deliverability into Sabine Pass, or ~160% of the
total load for Trains 1-4
Upstream pipeline capacity provides access to diverse supply sources
• High degree of visibility into our ability to consistently deliver gas to Sabine
Pass on a variable basis at Henry Hub flat
17
Shale Plays
Basins
Source: Lippman Consulting, Baker Hughes and Bentek, as of January 2014
NGPL
Tennessee Gas
HPL
KM Tejas
Oasis
Enterprise
Permian
Basin
Barnett
Granite
Wash
Eagle Ford
Haynesville
Marcellus /
Utica
Corpus Christi
Woodford
Gas Procurement
Corpus Christi Terminal
CCL contracting long-term direct and
upstream pipeline transport capacity
• Tennessee P/L: 0.3 Bcf/d
• KM Tejas P/L: 0.25 Bcf/d
• NGPL P/L: 0.385 Bcf/d
CCL purchasing natural gas from producers
and marketers
18
Cheniere Marketing
Scale up for > 10 mtpa including LNG
purchases from Cheniere terminals and
other places
Buyers & sellers of LNG cargoes
SPAs with SPL and CCL for all LNG
volumes not sold to 3
rd
parties
Chartered 3 LNG vessels for deliveries
in 2015 and 2016 (1
st
vessel received
June 2015)
Developing complementary,
high-value markets through
small-scale asset investments
Professional staff based in London,
Houston, Washington, Santiago, and
Singapore
~340 million MMBtu sold to date
primarily based on 1–2 year terms at
prices linked to HH or TTF
Cheniere platform for LNG sales - short, mid, long-term sales, FOB or DES basis
Singapore
Houston, TX
Santiago, Chile
London, U.K.
Chartered 3 LNG Vessels SPA with SPL SPAs with CCL
Deliveries in 2015 & 2016 First LNG for SPL Expected 2015 First LNG Expected 2018
19
Washington, D.C.
Future Developments
Horizontal / Vertical Integration
Total focus
on cash
flow per
share as
guiding
metric for
future
investments
Announced
brownfield
expansion at
Corpus
Christi and
mid-scale
LNG
investment
Significant
revenue
expected
starting in
2016
Cheniere core competencies, scale, and first-mover advantage
provide industry-leading platform for further asset integration
Developing
additional
assets for
other
hydrocarbon
export
opportunities
20
Appendix
Investing in Cheniere – Summary Organization
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
Note: This organizational chart is provided for illustrative purposes only, is not and does not purport to be a complete organizational chart of Cheniere.
(1) Current ownership interest based solely on ownership of Class B units. As Class B units accrete Blackstone will increase its ownership percentage, and the public and CQH will have reduced
ownership percentages.
(2) Cheniere Energy, Inc. has agreed in principle to partner with Parallax Enterprises, LLC on these projects.
Liquefaction facilities
9 mtpa under
construction
13.5 mtpa under
development
10.1 Bcf of storage
2 berths
Regasification facilities
4.0 Bcf/d of capacity
17.0 Bcf of storage
2 berths
Liquefaction facilities
22.5 mtpa under construction
4.5 mtpa under development
Cheniere Energy Partners
LP Holdings, LLC
(NYSE MKT: CQH)
1.5 Bcf/d capacity for SPL
Provides gas supply for SPL
80.1% Interest
55.9% Interest
(1)
2.0% Interest & Incentive
Dist. Rights
Int’l LNG marketing
SPAs with SPL and CCL
Three 5-year LNG vessel
charters
Blackstone (BX) 29.0%
(1)
Public 13.1%
(1)
Public
19.9%
22
Other Project
Developments
100% Interest
Agreement in
Principle for
Liquefaction
facilities at Live Oak
LNG and Louisiana
LNG
2
~10 mtpa under
development
Other hydrocarbon
export facilities
Cheniere’s Debt Summary
As of October 2015
Cheniere Energy, Inc.
(NYSE MKT: LNG)
Cheniere Energy Partners,
L.P. (NYSE MKT: CQP)
Sabine Pass LNG, L.P.
(SPLNG)
Total TUA (1 Bcf/d)
Chevron TUA (1 Bcf/d)
SPL TUA (2 Bcf/d)
Sr Secured Notes
$1,666 due 2016 (7.50%)
$420 due 2020 (6.50%)
($ in millions)
Cheniere Marketing, LLC
(CMI)
Trains 1-5 Debt
$4,600 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%)
$2,000 Notes due 2025 (5.625%)
$1,200 Working Capital Facility
due 2020
2
Sabine Pass
Liquefaction, LLC
(SPL)
Creole Trail Pipeline
(CTPL)
$400 Term Loan due 2017 (L+325)
CQP GP
(& IDRs)
(1) Includes $2,850 million term loan facility, $1,150 million Republic of Korea (“ROK”)
covered facility and $600 million ROK direct facility. Interest on the term loan facility is
L+175 bps during construction and operation. Under the ROK credit facilities, interest
includes L+175 on the direct portion and L+130 on the covered portion during
construction and operation. In addition, SPL will pay 45 bps for insurance/guarantee
premiums on any drawn amounts under the covered tranches. These credit facilities
mature on the earlier of December 31, 2020 or the second anniversary of Train 5
completion date.
(2) Interest on the working capital facility is L+175.
(3) Interest on the term loan facility is L+225 bps during construction and L+250 bps
during operation. This credit facility matures on the earlier of May 13, 2022 or the second
anniversary of project completion date .
Note: This organizational chart is provided for illustrative purposes only, is not and does
not purport to be a complete organizational chart of Cheniere.
Cheniere Energy Partners
LP Holdings, LLC
(NYSE MKT: CQH)
23
Cheniere CCH
Holdco II, LLC
Convertible Debt
$1,000 PIK Convertible Notes due 2021 (4.875%)
$625 Convertible Notes due 2045 (4.250%)
SPL Firm Transport (1.5 Bcf/d)
BG SPA (286.5 Tbtu / yr)
Gas Natural SPA (182.5 Tbtu / yr)
KOGAS SPA (182.5 Tbtu / yr)
GAIL (182.5 Tbtu / yr)
Total (104.8 Tbtu / yr)
Centrica (91.3 Tbtu / yr)
CMI SPA
Pertamina SPA (79.4 Tbtu / yr)
Endesa SPA (117.3 Tbtu / yr)
Iberdrola SPA (39.7 Tbtu / yr)
Gas Natural (78.2 Tbtu / yr)
Woodside (44.1 Tbtu / yr)
EDF (40.0 Tbtu / yr)
EDP (40.0 Tbtu / yr)
CMI SPA
Cheniere Corpus Christi
Holdings, LLC
(CCH)
Trains 1-2 Equity
$1,000 Senior Secured
Convertible Notes due
2025
Trains 1-2 Debt
~$8,400 Credit Facility due
2022
3
Corpus Christi
Liquefaction, LLC
(CCL)
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.
24
Sabine Pass Liquefaction –– Brownfield LNG Export Project
Utilizes Existing Assets, Trains 1-5 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
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 – 5: Fully Contracted
Lump Sum Turnkey EPC contracts w/ Bechtel
T1 & T2 EPC contract price ~$4.1B
• Overall project ~96% complete (as of 10/2015)
• Operations estimated late 2015/2016
T3 & T4 EPC contract price ~$3.8B
• Overall project ~77% complete (as of 10/2015)
• Operations estimated 2016/2017
T5 EPC contract price ~$3.0B
• Construction commenced June 2015
Liquefaction Train 6
FID upon obtaining commercial contracts
and financing
Artist’s rendition
25
SPL estimated cash flows
($ in billions)
SPL Trains 1-5 SPL Trains 1-6
Long term SPAs $2.9 $3.2
CMI SPA payment
(1)
$0.4 $0.9
Commodity payments, net
(2)
$0.3 $0.4
Total SPL revenues $3.6 $4.4
SPLNG TUA payments
(3)
($0.4) ($0.4)
Plant O&M ($0.3) ($0.3)
Plant maintenance capex
(4)
($0.2) ($0.2)
Pipeline costs (primary plant and upstream pipelines) ($0.2) ($0.2)
Total SPL operating expenses ($1.1) ($1.2)
SPL EBITDA $2.6 $3.3
Less: Project-level interest expense
(5)
($0.8) ($0.9)
SPL distributable cash flow to CQP $1.8 $2.3
SPL Estimated Cash Flows
Trains 1-5 and Trains 1-6
26
Note: EBITDA is a non-GAAP measure. EBITDA is computed as total revenues less non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes. It does
not include depreciation expenses and certain non-operating items. Because we have not forecasted depreciation expense and non-operating items, we have not made any forecast of net
income, which would be the most directly comparable financial measure under generally accepted accounting principles, or GAAP, and we are unable to reconcile differences between
forecasts of EBITDA and net income. EBITDA has limitations as an analytical tool and should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and
should be evaluated only on a supplementary basis.
Assumes future long term contracting of additional 1.5 MTPA at SPL Train 6 (total of 21.25 MTPA of long term SPAs at SPL Trains 1-6) at $3.50 per MMBtu.
(1) CMI SPA payment assumes 100% utilization at $3.00/MMBtu.
(2) Assumes $5.00/MMBtu natural gas price and that off-takers lift 100% of their full contractual entitlement. Amounts are net of estimated natural gas to be used for the liquefaction process.
(3) Includes payments related to reassignment of Total TUA SPLNG capacity and export fees paid to SPLNG.
(4) Majority of costs shown are fixed and covered under multi-year service and supply agreements with equipment and service providers.
(5) Assumes debt at SPL refinanced at 6.00% annual interest rate.
SPL Construction Completion Schedules Trains 1 – 5
Stage 1 (Trains 1&2) overall project progress as of October 2015 is 96.1% complete vs. Target Plan of 98.2%:
Engineering, Procurement, Subcontracts and Construction are 100%, 100%, 84.1% and 93.5% complete against Target Plan of 99.8%,
100%, 88.7% and 98.1% respectively
Bechtel Delivered the Train 1 Commissioning and Start-up Plan in Feb, projecting Fuel Gas introduction in Sep, Feed Gas introduction in
Oct, and Ready for Start-up in Dec; all in support of the current First LNG Target
by year-end 2015, and Target Substantial Completion in Mar 2016
Stage 2 (Trains 3&4) overall project progress as of October 2015 is 76.7% complete vs. Target Plan of 81.8%:
Engineering, Procurement, Subcontracts and Construction are 100%, 99.4%, 50.4% and 48.5% complete against Target Plan of 99.0%,
98.8%, 65.8% and 59.6% respectively
Stage 3 (Trains 5&6) overall project progress:
NTP on Train 5 issued to Bechtel on June 30
th
Soil stabilization civil works are in progress and the current plan estimates Train 5 operational in 52 months from NTP
BG DFCD
GN DFCD
KOGAS DFCD
GAIL DFCD
First LNG
March 2016
April 2017
Jun 2017
Mar 2018
June 2016
Sept 2017
27
Dec 2019
Oct 2019
Early Engineering
TOTAL & CENTRICA DFCD
LNG Sale and Purchase Agreements (SPAs)
Sabine Pass Liquefaction
(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, 11.5% for KOGAS, GAIL (India) Ltd, 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.
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+/Aa3/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.
~$274 MM
20 years
BBB+/Baa1/A-
N/A
N/A
$3.00
91,250,000
Centrica plc
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
28
Corpus Christi Liquefaction Project
29
Proposed 5 Train Facility
>1,000 acres owned and/or controlled
2 berths, 4 LNG storage tanks (~13.5 Bcfe of storage)
Key Project Attributes
45 ft. ship channel 14 miles from coast
Protected berth
Premier Site Conditions
23-mile 48” and 42” parallel pipelines will connect to
several interstate and intrastate pipelines
Liquefaction Trains 1-2: Under Construction
Lump Sum Turnkey EPC contracts w/ Bechtel
T1 & T2 EPC contract price ~$7.1B
• Construction commenced May 2015
• Operations estimated 2018
Liquefaction Train 3: Partially Contracted
0.8 mtpa contracted to date
Targeting additional 2.1 mtpa
Reach FID upon contracting
Liquefaction Trains 4-5: Initiated Development
Permit process started June 2015
Houston
New Orleans
Gulf of Mexico
Corpus Christi
Commenced Construction on Trains 1-2 in May 2015
Artist’s rendition
Design production capacity is expected to be ~4.5 mtpa per train,
using ConocoPhillips’ Optimized Cascade® Process
Under
Construction
Trains 1-2
Train 3
Initiated
Development
Trains 4-5
CCL estimated cash flows
($ in billions)
CCL Trains 1-2 CCL Trains 1-3
Long term SPAs $1.4 $1.9
CMI SPA payment
(1)
$0.2 $0.5
Commodity payments, net
(2)
$0.1 $0.1
Total CCL revenues $1.7 $2.5
Plant O&M ($0.2) ($0.2)
Plant maintenance capex
(3)
($0.1) ($0.1)
Pipeline costs (primary plant and upstream pipelines) ($0.1) ($0.2)
Total CCL operating expenses ($0.4) ($0.5)
CCL EBITDA $1.3 $2.0
Less: Project-level interest expense
(4)
($0.5) ($0.7)
CCL distributable cash flow to CEI $0.8 $1.3
CCL Estimated Cash Flows
Trains 1-2 and Trains 1-3
30
Note: EBITDA is a non-GAAP measure. EBITDA is computed as total revenues less non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes. It does
not include depreciation expenses and certain non-operating items. Because we have not forecasted depreciation expense and non-operating items, we have not made any forecast of net
income, which would be the most directly comparable financial measure under generally accepted accounting principles, or GAAP, and we are unable to reconcile differences between
forecasts of EBITDA and net income. EBITDA has limitations as an analytical tool and should not be considered in isolation or in lieu of an analysis of our results as reported under GAAP, and
should be evaluated only on a supplementary basis.
Assumes future long term contracting of additional ~2.1 MTPA at CCL Train 3 (total of 10.5 MTPA of long term SPAs at CCL Trains 1-3) at $3.50 per MMBtu.
(1) CMI SPA payment assumes 100% utilization at $3.00/MMBtu.
(2) Assumes $5.00/MMBtu natural gas price and that off-takers lift 100% of their full contractual entitlement. Amounts are net of estimated natural gas to be used for the liquefaction process.
(3) Majority of costs shown related to service-based payments to be contracted over a multi-year term.
(4) Assumes debt at CCL refinanced at 6.00% annual interest rate.
Corpus Christi Liquefaction Project Schedule
Stage 1 (Trains 1&2) overall project progress as of October 2015 is ahead of target:
Engineering, Procurement, and Construction has progressed to 90.3%, 34.6%, and 0.8%
compared to a plan of 82.3%, 23.0%, and 1.7% respectively.
NTP issued, construction commenced for Trains 1-2 in May 2015
31
Note: Based on Guaranteed Substantial and Target Completion Dates per EPC contract.
Train 1 Guaranteed
Current Level 3 Schedule
Train 2 Guaranteed
Current Level 3 Schedule
Train 1 DFCD
Train 2 DFCD
Oct-19
Feb-19
Jul-20
Jun-19
PT Pertamina
(Persero)
Endesa S.A.
Iberdrola S.A.
Gas Natural Fenosa
Woodside Energy
Trading
Électricité de
France
EDP Energias de
Portugal S.A.
Annual Contract
Quantity (TBtu)
79.36 117.32 39.68 78.20 44.12 40.00 40.00
Annual Fixed Fees
(1)
~$278 MM ~$411 MM ~$139 MM ~$274 MM ~$154 MM ~$140 MM ~$140 MM
Fixed Fees $/MMBtu
(1)
$3.50 $3.50 $3.50 $3.50 $3.50 $3.50 $3.50
LNG Cost
115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH 115% of HH
Term of Contract
(2)
20 years 20 years 20 years 20 years 20 years 20 years 20 years
Guarantor
N/A N/A N/A
Gas Natural
SDG, S.A.
Woodside
Petroleum, LTD
N/A N/A
Guarantor/Corporate
Credit Rating
(3)
BB+/Baa3/BBB- BBB/Baa2/BBB+ BBB/Baa1/BBB+ BBB/Baa2/BBB+ BBB+/Baa1/BBB+
A+/A1/A BB+/Baa3/BBB-
Contract Start
Train 1 / Train2
Train 1
Train 1 / Train 2
Train 2
Train 2
Train 2
Train 3
Corpus Christi Liquefaction SPAs
SPA progress: ~8.42 mtpa “take-or-pay” style commercial agreements
~$1.5B annual fixed fee revenue for 20 years
(1) 12.75% of the fee is subject to inflation for Pertamina; 11.5% for Woodside; 14% for all others
(2) SPA has a 20 year term with the right to extend up to an additional 10 years.
(3) Ratings are provided by S&P/Moody’s/Fitch and subject to change, suspension or withdrawal at anytime and are not a recommendation to buy, hold or sell any security.
32
Live Oak and Louisiana Liquefaction Projects
1
33
Live Oak LNG Facility Overview
340 acres on the Calcasieu Channel,
just north of Calcasieu Lake
~5 mtpa development
1 berth, 2 LNG storage tanks
Project Update
FERC pre-filing expected in 2015
First LNG expected 2021
Louisiana LNG Facility Overview
400 acres on the Mississippi River,
~40 miles downstream from the
Port of New Orleans
~5 mtpa development
1 berth, 2 LNG storage tanks
Project Update
FERC pre-filing for 6 mtpa in July 2015
First LNG expected 2021
Artist’s rendition for both projects
Mid-scale LNG projects Utilizing Bechtel/Chart Industries Technology
Live Oak
LNG
Louisiana
LNG
(1) Cheniere Energy, Inc. has agreed in principle to partner with Parallax Enterprises, LLC on these projects
Applications Filed with FERC for Liquefaction Projects
Continental U.S.
LNG Export Projects
Quantity
Bcf/d
FERC
Pre-filing
Date
FERC
Application
Date
FERC
Scheduling
Notice Issued
EIS /
EA
Scheduled
Date for EIS
or EA
FERC Approval
DOE
Non FTA
Final
Under
Construction
Sabine Pass Liquefaction T1-4 2.8 7/26/10 1/31/11 12/16/11 EA 4/16/12 8/7/12
Cameron LNG T1-3 1.7 4/30/12 12/10/12 11/21/13 EIS 4/30/14 6/19/14 9/10/14
Freeport LNG
1.4
0.4
12/23/10 8/31/12 1/6/14 EIS 6/16/14 7/30/14 11/14/14
Dominion Cove Point LNG 1.0 6/1/12 4/1/13 3/12/14 EA 5/15/14 9/29/14 5/7/15
Corpus Christi Liquefaction T1-3 2.1 12/13/11 8/31/12 2/12/14 EIS 10/8/14 12/30/14 5/12/15
T1-2:
Sabine Pass Liquefaction T5-6 1.38 2/27/13 9/30/13 11/03/14 EA 12/12/14 4/6/2015
6/26/15
T5:
Jordan Cove Energy 1.2/0.8 2/29/12 5/22/13 7/16/14 EIS 9/30/15
Oregon LNG 1.25 7/3/12 6/7/13 4/17/15 EIS 2/12/16
Lake Charles LNG 2.0 3/30/12 3/25/14 1/26/15 EIS 8/14/15
Magnolia 1.08 3/20/13 4/30/14 4/30/15 EIS 11/16/15
Southern LNG 0.5 12/5/12 3/10/14 EA
Golden Pass 2.6 5/16/13 7/7/14 6/26/15 EA 3/4/16
Gulf LNG 1.3 12/6/12 6/19/15 EIS
Cameron LNG Expansion T4-5 1.4 2/24/15 9/28/15 EIS
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 Fossil Energy, U.S. Department of Energy; U.S. Federal Energy Regulatory Commission; Company releases
6 projects have received FERC approval and final DOE approval for Non FTA
34
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
Fully permitted
Fully
Subscribed
Lake Charles
2.0
FTA +
NonFTA
Fully
Subscribed
Dominion Cove
Point
1.0
Fully permitted
Fully
Subscribed
Cameron LNG T1-3
1.7
Fully permitted
Fully
Subscribed
Jordan Cove
1.2/0.8
FTA +
NonFTA
Oregon LNG
1.25
FTA +
NonFTA
Cheniere Corpus
Christi T1 – T3
2.1
Fully permitted
Partially
Subscribed
Cheniere Sabine
Pass T5 – T6
1.3
Fully permitted
T5
Subscribed
Southern LNG
0.5 FTA
v
Fully
Subscribed
Magnolia LNG
0.5 FTA
Partially
Subscribed
Golden Pass LNG
2 FTA
Fully
Subscribed
Gulf LNG
1.3 FTA
v
Cameron LNG T4-5
1.4 FTA
v
Freeport LNG
Corpus Christi
Plus other proposed LNG export projects that have not filed a FERC application.
Excelerate has requested that FERC put on hold the review its application.
• Application filing = v
• FERC scheduling notice issued =
Filed FERC Application
Jordan Cove
Oregon LNG
Cameron LNG
Lake Charles
Sabine Pass
35
Southern LNG
Gulf LNG
Golden Pass
Magnolia
