|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware
|
001-33366
|
20-5913059
|
(State or other jurisdiction of incorporation or organization)
|
(Commission File Number)
|
(I.R.S. Employer Identification No.)
|
|
|
|
700 Milam Street, Suite 1900
Houston, Texas
|
|
77002
|
(Address of principal executive offices)
|
|
(Zip code)
|
|
|
|
|
|
Large accelerated filer
x
|
Accelerated filer
o
|
Non-accelerated filer
o
(Do not check if a smaller reporting company)
|
Smaller reporting company
o
|
|
Emerging growth company
o
|
|
|
|
|
|
|
||
|
||
|
||
|
||
|
||
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bcf
|
|
billion cubic feet
|
Bcf/d
|
|
billion cubic feet per day
|
Bcf/yr
|
|
billion cubic feet per year
|
Bcfe
|
|
billion cubic feet equivalent
|
DOE
|
|
U.S. Department of Energy
|
EPC
|
|
engineering, procurement and construction
|
FERC
|
|
Federal Energy Regulatory Commission
|
FTA countries
|
|
countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
|
GAAP
|
|
generally accepted accounting principles in the United States
|
Henry Hub
|
|
the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
|
LIBOR
|
|
London Interbank Offered Rate
|
LNG
|
|
liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
|
MMBtu
|
|
million British thermal units, an energy unit
|
mtpa
|
|
million tonnes per annum
|
non-FTA countries
|
|
countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
|
SEC
|
|
U.S. Securities and Exchange Commission
|
SPA
|
|
LNG sale and purchase agreement
|
TBtu
|
|
trillion British thermal units, an energy unit
|
Train
|
|
an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
|
TUA
|
|
terminal use agreement
|
PART I.
|
FINANCIAL INFORMATION
|
ITEM 1.
|
CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
March 31,
|
|
December 31,
|
||||
|
|
2018
|
|
2017
|
||||
ASSETS
|
|
(unaudited)
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
—
|
|
|
$
|
—
|
|
Restricted cash
|
|
1,477
|
|
|
1,589
|
|
||
Accounts and other receivables
|
|
240
|
|
|
191
|
|
||
Accounts receivable—affiliate
|
|
114
|
|
|
163
|
|
||
Advances to affiliate
|
|
97
|
|
|
36
|
|
||
Inventory
|
|
83
|
|
|
95
|
|
||
Other current assets
|
|
54
|
|
|
65
|
|
||
Total current assets
|
|
2,065
|
|
|
2,139
|
|
||
|
|
|
|
|
||||
Property, plant and equipment, net
|
|
15,145
|
|
|
15,139
|
|
||
Debt issuance costs, net
|
|
34
|
|
|
38
|
|
||
Non-current derivative assets
|
|
24
|
|
|
31
|
|
||
Other non-current assets, net
|
|
197
|
|
|
206
|
|
||
Total assets
|
|
$
|
17,465
|
|
|
$
|
17,553
|
|
|
|
|
|
|
||||
LIABILITIES AND PARTNERS’ EQUITY
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts payable
|
|
$
|
11
|
|
|
$
|
12
|
|
Accrued liabilities
|
|
509
|
|
|
637
|
|
||
Due to affiliates
|
|
30
|
|
|
68
|
|
||
Deferred revenue
|
|
95
|
|
|
111
|
|
||
Deferred revenue—affiliate
|
|
—
|
|
|
1
|
|
||
Derivative liabilities
|
|
4
|
|
|
—
|
|
||
Total current liabilities
|
|
649
|
|
|
829
|
|
||
|
|
|
|
|
||||
Long-term debt, net
|
|
16,052
|
|
|
16,046
|
|
||
Non-current deferred revenue
|
|
—
|
|
|
1
|
|
||
Non-current derivative liabilities
|
|
3
|
|
|
3
|
|
||
Other non-current liabilities
|
|
11
|
|
|
10
|
|
||
Other non-current liabilities—affiliate
|
|
25
|
|
|
25
|
|
||
|
|
|
|
|
||||
Partners’ equity
|
|
|
|
|
||||
Common unitholders’ interest (348.6 million units issued and outstanding at March 31, 2018 and December 31, 2017)
|
|
1,731
|
|
|
1,670
|
|
||
Subordinated unitholders’ interest (135.4 million units issued and outstanding at March 31, 2018 and December 31, 2017)
|
|
(1,019
|
)
|
|
(1,043
|
)
|
||
General partner’s interest (2% interest with 9.9 million units issued and outstanding at March 31, 2018 and December 31, 2017)
|
|
13
|
|
|
12
|
|
||
Total partners’ equity
|
|
725
|
|
|
639
|
|
||
Total liabilities and partners’ equity
|
|
$
|
17,465
|
|
|
$
|
17,553
|
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
Revenues
|
|
|
|
||||
LNG revenues
|
$
|
1,015
|
|
|
$
|
492
|
|
LNG revenues—affiliate
|
503
|
|
|
331
|
|
||
Regasification revenues
|
65
|
|
|
65
|
|
||
Other revenues
|
10
|
|
|
2
|
|
||
Other revenues—affiliate
|
—
|
|
|
1
|
|
||
Total revenues
|
1,593
|
|
|
891
|
|
||
|
|
|
|
||||
Operating costs and expenses
|
|
|
|
||||
Cost of sales (excluding depreciation and amortization expense shown separately below)
|
837
|
|
|
513
|
|
||
Operating and maintenance expense
|
95
|
|
|
50
|
|
||
Operating and maintenance expense—affiliate
|
26
|
|
|
18
|
|
||
General and administrative expense
|
4
|
|
|
3
|
|
||
General and administrative expense—affiliate
|
18
|
|
|
22
|
|
||
Depreciation and amortization expense
|
105
|
|
|
66
|
|
||
Total operating costs and expenses
|
1,085
|
|
|
672
|
|
||
|
|
|
|
||||
Income from operations
|
508
|
|
|
219
|
|
||
|
|
|
|
||||
Other income (expense)
|
|
|
|
||||
Interest expense, net of capitalized interest
|
(185
|
)
|
|
(130
|
)
|
||
Loss on early extinguishment of debt
|
—
|
|
|
(42
|
)
|
||
Derivative gain, net
|
8
|
|
|
—
|
|
||
Other income
|
4
|
|
|
—
|
|
||
Total other expense
|
(173
|
)
|
|
(172
|
)
|
||
|
|
|
|
||||
Net income
|
$
|
335
|
|
|
$
|
47
|
|
|
|
|
|
||||
Basic and diluted net income (loss) per common unit
|
$
|
0.67
|
|
|
$
|
(0.80
|
)
|
|
|
|
|
||||
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation
|
348.6
|
|
|
57.1
|
|
|
Common Unitholders’ Interest
|
|
Subordinated Unitholder’s Interest
|
|
General Partner’s Interest
|
|
Total Partners’ Equity
|
|||||||||||||||||
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
Units
|
|
Amount
|
|
||||||||||||
Balance at December 31, 2017
|
348.6
|
|
|
$
|
1,670
|
|
|
135.4
|
|
|
$
|
(1,043
|
)
|
|
9.9
|
|
|
$
|
12
|
|
|
$
|
639
|
|
Net income
|
—
|
|
|
236
|
|
|
—
|
|
|
92
|
|
|
—
|
|
|
7
|
|
|
335
|
|
||||
Distributions
|
—
|
|
|
(175
|
)
|
|
—
|
|
|
(68
|
)
|
|
—
|
|
|
(6
|
)
|
|
(249
|
)
|
||||
Balance at March 31, 2018
|
348.6
|
|
|
$
|
1,731
|
|
|
135.4
|
|
|
$
|
(1,019
|
)
|
|
9.9
|
|
|
$
|
13
|
|
|
$
|
725
|
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
Cash flows from operating activities
|
|
|
|
||||
Net income
|
$
|
335
|
|
|
$
|
47
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
||||
Depreciation and amortization expense
|
105
|
|
|
66
|
|
||
Amortization of debt issuance costs, deferred commitment fees, premium and discount
|
8
|
|
|
10
|
|
||
Loss on early extinguishment of debt
|
—
|
|
|
42
|
|
||
Total losses on derivatives, net
|
42
|
|
|
39
|
|
||
Net cash used for settlement of derivative instruments
|
(3
|
)
|
|
(13
|
)
|
||
Other
|
2
|
|
|
—
|
|
||
Changes in operating assets and liabilities:
|
|
|
|
||||
Accounts and other receivables
|
(50
|
)
|
|
(11
|
)
|
||
Accounts receivable—affiliate
|
48
|
|
|
59
|
|
||
Advances to affiliate
|
(56
|
)
|
|
(41
|
)
|
||
Inventory
|
12
|
|
|
17
|
|
||
Accounts payable and accrued liabilities
|
(69
|
)
|
|
(38
|
)
|
||
Due to affiliates
|
(25
|
)
|
|
(68
|
)
|
||
Deferred revenue
|
(18
|
)
|
|
(11
|
)
|
||
Other, net
|
—
|
|
|
1
|
|
||
Other, net—affiliate
|
—
|
|
|
16
|
|
||
Net cash provided by operating activities
|
331
|
|
|
115
|
|
||
|
|
|
|
||||
Cash flows from investing activities
|
|
|
|
|
|
||
Property, plant and equipment, net
|
(194
|
)
|
|
(524
|
)
|
||
Net cash used in investing activities
|
(194
|
)
|
|
(524
|
)
|
||
|
|
|
|
||||
Cash flows from financing activities
|
|
|
|
|
|
||
Proceeds from issuances of debt
|
—
|
|
|
2,314
|
|
||
Repayments of debt
|
—
|
|
|
(703
|
)
|
||
Debt issuance and deferred financing costs
|
—
|
|
|
(26
|
)
|
||
Distributions to owners
|
(249
|
)
|
|
(25
|
)
|
||
Net cash provided by (used in) financing activities
|
(249
|
)
|
|
1,560
|
|
||
|
|
|
|
||||
Net increase (decrease) in cash, cash equivalents and restricted cash
|
(112
|
)
|
|
1,151
|
|
||
Cash, cash equivalents and restricted cash—beginning of period
|
1,589
|
|
|
605
|
|
||
Cash, cash equivalents and restricted cash—end of period
|
$
|
1,477
|
|
|
$
|
1,756
|
|
|
March 31,
|
||
|
2018
|
||
Cash and cash equivalents
|
$
|
—
|
|
Restricted cash
|
1,477
|
|
|
Total cash, cash equivalents and restricted cash
|
$
|
1,477
|
|
|
|
March 31,
|
|
December 31,
|
||||
|
|
2018
|
|
2017
|
||||
Current restricted cash
|
|
|
|
|
||||
Liquefaction Project
|
|
$
|
561
|
|
|
$
|
544
|
|
CQP and cash held by guarantor subsidiaries
|
|
916
|
|
|
1,045
|
|
||
Total current restricted cash
|
|
$
|
1,477
|
|
|
$
|
1,589
|
|
|
|
March 31,
|
|
December 31,
|
||||
|
|
2018
|
|
2017
|
||||
SPL trade receivable
|
|
$
|
232
|
|
|
$
|
185
|
|
Other accounts receivable
|
|
8
|
|
|
6
|
|
||
Total accounts and other receivables
|
|
$
|
240
|
|
|
$
|
191
|
|
|
|
March 31,
|
|
December 31,
|
||||
|
|
2018
|
|
2017
|
||||
Natural gas
|
|
$
|
16
|
|
|
$
|
17
|
|
LNG
|
|
14
|
|
|
26
|
|
||
Materials and other
|
|
53
|
|
|
52
|
|
||
Total inventory
|
|
$
|
83
|
|
|
$
|
95
|
|
|
|
March 31,
|
|
December 31,
|
||||
|
|
2018
|
|
2017
|
||||
LNG terminal costs
|
|
|
|
|
||||
LNG terminal
|
|
$
|
12,690
|
|
|
$
|
12,703
|
|
LNG terminal construction-in-process
|
|
3,431
|
|
|
3,310
|
|
||
Accumulated depreciation
|
|
(982
|
)
|
|
(880
|
)
|
||
Total LNG terminal costs, net
|
|
15,139
|
|
|
15,133
|
|
||
Fixed assets
|
|
|
|
|
|
|
||
Fixed assets
|
|
23
|
|
|
23
|
|
||
Accumulated depreciation
|
|
(17
|
)
|
|
(17
|
)
|
||
Total fixed assets, net
|
|
6
|
|
|
6
|
|
||
Property, plant and equipment, net
|
|
$
|
15,145
|
|
|
$
|
15,139
|
|
•
|
interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under certain credit facilities
(“Interest Rate Derivatives”)
and
|
•
|
commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the
Liquefaction Project
(“Physical Liquefaction Supply Derivatives”)
and associated economic hedges
(collectively, the “Liquefaction Supply Derivatives”)
.
|
|
Fair Value Measurements as of
|
||||||||||||||||||||||||||||||
|
March 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||||||||||
|
Quoted Prices in Active Markets
(Level 1)
|
|
Significant Other Observable Inputs
(Level 2)
|
|
Significant Unobservable Inputs
(Level 3)
|
|
Total
|
|
Quoted Prices in Active Markets
(Level 1)
|
|
Significant Other Observable Inputs
(Level 2)
|
|
Significant Unobservable Inputs
(Level 3)
|
|
Total
|
||||||||||||||||
CQP Interest Rate Derivatives asset
|
$
|
—
|
|
|
$
|
27
|
|
|
$
|
—
|
|
|
$
|
27
|
|
|
$
|
—
|
|
|
$
|
21
|
|
|
$
|
—
|
|
|
$
|
21
|
|
Liquefaction Supply Derivatives asset
|
—
|
|
|
—
|
|
|
10
|
|
|
10
|
|
|
2
|
|
|
10
|
|
|
43
|
|
|
55
|
|
|
|
Net Fair Value Asset
(in millions)
|
|
Valuation Approach
|
|
Significant Unobservable Input
|
|
Significant Unobservable Inputs Range
|
Physical Liquefaction Supply Derivatives
|
|
$10
|
|
Market approach incorporating present value techniques
|
|
Basis Spread
|
|
$(0.515) - $0.095
|
|
|
Three Months Ended March 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Balance, beginning of period
|
|
$
|
43
|
|
|
$
|
79
|
|
Realized and mark-to-market losses:
|
|
|
|
|
||||
Included in cost of sales
|
|
(13
|
)
|
|
(41
|
)
|
||
Purchases and settlements:
|
|
|
|
|
||||
Purchases
|
|
3
|
|
|
4
|
|
||
Settlements
|
|
(23
|
)
|
|
(1
|
)
|
||
Balance, end of period
|
|
$
|
10
|
|
|
$
|
41
|
|
Change in unrealized gains relating to instruments still held at end of period
|
|
$
|
(13
|
)
|
|
$
|
(41
|
)
|
|
|
Initial Notional Amount
|
|
Maximum Notional Amount
|
|
Effective Date
|
|
Maturity Date
|
|
Weighted Average Fixed Interest Rate Paid
|
|
Variable Interest Rate Received
|
CQP Interest Rate Derivatives
|
|
$225 million
|
|
$1.3 billion
|
|
March 22, 2016
|
|
February 29, 2020
|
|
1.19%
|
|
One-month LIBOR
|
|
|
March 31,
|
|
December 31,
|
||||
Balance Sheet Location
|
|
2018
|
|
2017
|
||||
Other current assets
|
|
$
|
12
|
|
|
$
|
7
|
|
Non-current derivative assets
|
|
15
|
|
|
14
|
|
||
Total derivative assets
|
|
$
|
27
|
|
|
$
|
21
|
|
|
|
Three Months Ended March 31,
|
||||||
|
|
2018
|
|
2017
|
||||
CQP Interest Rate Derivatives gain
|
|
$
|
8
|
|
|
$
|
2
|
|
SPL Interest Rate Derivatives loss
|
|
—
|
|
|
(2
|
)
|
|
|
Fair Value Measurements as of (1)
|
||||||
Balance Sheet Location
|
|
March 31, 2018
|
|
December 31, 2017
|
||||
Other current assets
|
|
$
|
8
|
|
|
$
|
41
|
|
Non-current derivative assets
|
|
9
|
|
|
17
|
|
||
Total derivative assets
|
|
17
|
|
|
58
|
|
||
|
|
|
|
|
||||
Derivative liabilities
|
|
(4
|
)
|
|
—
|
|
||
Non-current derivative liabilities
|
|
(3
|
)
|
|
(3
|
)
|
||
Total derivative liabilities
|
|
(7
|
)
|
|
(3
|
)
|
||
|
|
|
|
|
||||
Derivative asset, net
|
|
$
|
10
|
|
|
$
|
55
|
|
|
(1)
|
Does not include a collateral call of
$1 million
for such contracts, which is included in
other current assets
in our Consolidated Balance Sheets as of both
March 31, 2018
and
December 31, 2017
.
|
|
|
|
Three Months Ended March 31,
|
||||||
|
Statement of Income Location (1)
|
|
2018
|
|
2017
|
||||
Liquefaction Supply Derivatives loss (2)
|
Cost of sales
|
|
$
|
50
|
|
|
$
|
39
|
|
|
(1)
|
Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
|
(2)
|
Does not include the realized value associated with derivative instruments that settle through physical delivery.
|
|
|
Gross Amounts Recognized
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
||||||
Offsetting Derivative Assets (Liabilities)
|
|
|
|
|||||||||
As of March 31, 2018
|
|
|
|
|
|
|
||||||
CQP Interest Rate Derivatives
|
|
$
|
27
|
|
|
$
|
—
|
|
|
$
|
27
|
|
Liquefaction Supply Derivatives
|
|
25
|
|
|
(8
|
)
|
|
17
|
|
|||
Liquefaction Supply Derivatives
|
|
(9
|
)
|
|
2
|
|
|
(7
|
)
|
|||
As of December 31, 2017
|
|
|
|
|
|
|
||||||
CQP Interest Rate Derivatives
|
|
$
|
21
|
|
|
$
|
—
|
|
|
$
|
21
|
|
Liquefaction Supply Derivatives
|
|
64
|
|
|
(6
|
)
|
|
58
|
|
|||
Liquefaction Supply Derivatives
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|
|
March 31,
|
|
December 31,
|
||||
|
|
2018
|
|
2017
|
||||
Advances made under EPC and non-EPC contracts
|
|
$
|
18
|
|
|
$
|
26
|
|
Advances made to municipalities for water system enhancements
|
|
93
|
|
|
93
|
|
||
Advances and other asset conveyances to third parties to support LNG terminals
|
|
29
|
|
|
30
|
|
||
Tax-related payments and receivables
|
|
25
|
|
|
25
|
|
||
Information technology service assets
|
|
23
|
|
|
24
|
|
||
Other
|
|
9
|
|
|
8
|
|
||
Total other non-current assets, net
|
|
$
|
197
|
|
|
$
|
206
|
|
|
|
March 31,
|
|
December 31,
|
||||
|
|
2018
|
|
2017
|
||||
Interest costs and related debt fees
|
|
$
|
186
|
|
|
$
|
253
|
|
Sabine Pass LNG terminal and related pipeline costs
|
|
319
|
|
|
384
|
|
||
Other accrued liabilities
|
|
4
|
|
|
—
|
|
||
Total accrued liabilities
|
|
$
|
509
|
|
|
$
|
637
|
|
|
|
March 31,
|
|
December 31,
|
||||
|
|
2018
|
|
2017
|
||||
Long-term debt:
|
|
|
|
|
||||
SPL
|
|
|
|
|
||||
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $5 and $6
|
|
$
|
2,005
|
|
|
$
|
2,006
|
|
6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)
|
|
1,000
|
|
|
1,000
|
|
||
5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5 and $5
|
|
1,505
|
|
|
1,505
|
|
||
5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)
|
|
2,000
|
|
|
2,000
|
|
||
5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)
|
|
2,000
|
|
|
2,000
|
|
||
5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and $1
|
|
1,349
|
|
|
1,349
|
|
||
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)
|
|
800
|
|
|
800
|
|
||
Cheniere Partners
|
|
|
|
|
||||
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)
|
|
1,500
|
|
|
1,500
|
|
||
2016 CQP Credit Facilities
|
|
1,090
|
|
|
1,090
|
|
||
Unamortized debt issuance costs
|
|
(197
|
)
|
|
(204
|
)
|
||
Total long-term debt, net
|
|
16,052
|
|
|
16,046
|
|
||
|
|
|
|
|
||||
Current debt:
|
|
|
|
|
||||
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)
|
|
—
|
|
|
—
|
|
||
|
|
|
|
|
||||
Total debt, net
|
|
$
|
16,052
|
|
|
$
|
16,046
|
|
|
|
SPL Working Capital Facility
|
|
2016 CQP Credit Facilities
|
||||
Original facility size
|
|
$
|
1,200
|
|
|
$
|
2,800
|
|
Less:
|
|
|
|
|
||||
Outstanding balance
|
|
—
|
|
|
1,090
|
|
||
Commitments prepaid or terminated
|
|
—
|
|
|
1,470
|
|
||
Letters of credit issued
|
|
706
|
|
|
20
|
|
||
Available commitment
|
|
$
|
494
|
|
|
$
|
220
|
|
|
|
|
|
|
||||
Interest rate
|
|
LIBOR plus 1.75% or base rate plus 0.75%
|
|
LIBOR plus 2.25% or base rate plus 1.25% (1)
|
||||
Maturity date
|
|
December 31, 2020, with various terms for underlying loans
|
|
February 25, 2020, with principal payments due quarterly commencing on March 31, 2019
|
|
(1)
|
There is a
0.50%
step-up for both LIBOR and base rate loans beginning on February 25, 2019.
|
|
|
Three Months Ended March 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Total interest cost
|
|
$
|
232
|
|
|
$
|
211
|
|
Capitalized interest
|
|
(47
|
)
|
|
(81
|
)
|
||
Total interest expense, net
|
|
$
|
185
|
|
|
$
|
130
|
|
|
|
March 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
||||||||
Senior notes, net of premium or discount (1)
|
|
$
|
14,359
|
|
|
$
|
15,116
|
|
|
$
|
14,360
|
|
|
$
|
15,485
|
|
2037 SPL Senior Notes (2)
|
|
800
|
|
|
838
|
|
|
800
|
|
|
871
|
|
||||
Credit facilities (3)
|
|
1,090
|
|
|
1,090
|
|
|
1,090
|
|
|
1,090
|
|
|
(1)
|
Includes
2021 SPL Senior Notes
,
2022 SPL Senior Notes
,
2023 SPL Senior Notes
,
2024 SPL Senior Notes
,
2025 SPL Senior Notes
,
2026 SPL Senior Notes
,
2027 SPL Senior Notes
,
2028 SPL Senior Notes
and
2025 CQP Senior Notes
. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
|
(2)
|
The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.
|
(3)
|
Includes
SPL Working Capital Facility
and
2016 CQP Credit Facilities
. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.
|
|
|
Three Months Ended March 31,
|
||||||
|
|
2018
|
|
2017
|
||||
LNG revenues
|
|
$
|
996
|
|
|
$
|
485
|
|
LNG revenues—affiliate
|
|
503
|
|
|
331
|
|
||
Regasification revenues
|
|
65
|
|
|
65
|
|
||
Other revenues
|
|
10
|
|
|
2
|
|
||
Other revenues—affiliate
|
|
—
|
|
|
1
|
|
||
Total revenues from customers
|
|
1,574
|
|
|
884
|
|
||
Revenues from derivative instruments
|
|
19
|
|
|
7
|
|
||
Total revenues
|
|
$
|
1,593
|
|
|
$
|
891
|
|
|
|
Three Months Ended March 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Deferred revenues, beginning of period
|
|
$
|
111
|
|
|
$
|
73
|
|
Cash received but not yet recognized
|
|
95
|
|
|
61
|
|
||
Revenue recognized from prior period deferral
|
|
(111
|
)
|
|
(71
|
)
|
||
Deferred revenues, end of period
|
|
$
|
95
|
|
|
$
|
63
|
|
|
|
Unsatisfied
Transaction Price
(in billions)
|
|
Weighted Average Recognition Timing (years) (1)
|
||
LNG revenues
|
|
$
|
55.2
|
|
|
10.0
|
Regasification revenues
|
|
2.8
|
|
|
5.6
|
|
Total revenues
|
|
$
|
58.0
|
|
|
|
|
(1)
|
The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
|
(1)
|
We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
|
(2)
|
We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance
|
|
Three Months Ended March 31,
|
|||||||
|
2018
|
|
2017
|
|||||
LNG revenues—affiliate
|
||||||||
Cheniere Marketing SPA and Cheniere Marketing Master SPA
|
$
|
503
|
|
|
$
|
331
|
|
|
|
|
|
|
|||||
Other revenues—affiliate
|
||||||||
Terminal Marine Services Agreement
|
—
|
|
|
1
|
|
|||
|
||||||||
Operating and maintenance expense—affiliate
|
||||||||
Services Agreements
|
26
|
|
|
18
|
|
|||
|
||||||||
General and administrative expense—affiliate
|
||||||||
Services Agreements
|
18
|
|
|
22
|
|
|
|
|
|
Limited Partner Units
|
|
|
|
|
||||||||||||||||
|
|
Total
|
|
Common Units
|
|
Class B Units
|
|
Subordinated Units
|
|
General Partner Units
|
|
IDR
|
||||||||||||
Three Months Ended March 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income
|
|
$
|
335
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Declared distributions
|
|
278
|
|
|
192
|
|
|
—
|
|
|
74
|
|
|
6
|
|
|
6
|
|
||||||
Assumed allocation of undistributed net income (1)
|
|
$
|
57
|
|
|
40
|
|
|
—
|
|
|
16
|
|
|
1
|
|
|
—
|
|
|||||
Assumed allocation of net income
|
|
|
|
$
|
232
|
|
|
$
|
—
|
|
|
$
|
90
|
|
|
$
|
7
|
|
|
$
|
6
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Weighted average units outstanding
|
|
|
|
348.6
|
|
|
—
|
|
|
135.4
|
|
|
|
|
|
|||||||||
Net income per unit (2)
|
|
|
|
$
|
0.67
|
|
|
|
|
|
$
|
0.67
|
|
|
|
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Three Months Ended March 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income
|
|
$
|
47
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Declared distributions
|
|
25
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||||
Amortization of beneficial conversion feature of Class B units
|
|
—
|
|
|
(70
|
)
|
|
235
|
|
|
(165
|
)
|
|
—
|
|
|
—
|
|
||||||
Assumed allocation of undistributed net income
|
|
$
|
22
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|||||
Assumed allocation of net income
|
|
|
|
$
|
(46
|
)
|
|
$
|
235
|
|
|
$
|
(143
|
)
|
|
$
|
1
|
|
|
$
|
—
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Weighted average units outstanding
|
|
|
|
57.1
|
|
|
145.3
|
|
|
135.4
|
|
|
|
|
|
|||||||||
Net loss per unit (2)
|
|
|
|
$
|
(0.80
|
)
|
|
|
|
|
$
|
(1.06
|
)
|
|
|
|
|
|
(1)
|
Under our partnership agreement, the
IDR
s participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the
IDR
s from participating in undistributed net income (loss).
|
(2)
|
Earnings per unit in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.
|
|
|
Percentage of Total Third-Party Revenues
|
|
Percentage of Accounts Receivable from Third Parties
|
||||
|
|
Three Months Ended March 31,
|
|
March 31,
|
|
December 31,
|
||
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Customer A
|
|
31%
|
|
54%
|
|
33%
|
|
39%
|
Customer B
|
|
25%
|
|
29%
|
|
19%
|
|
32%
|
Customer C
|
|
25%
|
|
—%
|
|
19%
|
|
26%
|
Customer D
|
|
*
|
|
—%
|
|
26%
|
|
—%
|
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
Cash paid during the period for interest, net of amounts capitalized
|
$
|
242
|
|
|
$
|
175
|
|
Standard
|
|
Description
|
|
Expected Date of Adoption
|
|
Effect on our Consolidated Financial Statements or Other Significant Matters
|
ASU 2016-02,
Leases (Topic 842)
, and subsequent amendments thereto
|
|
This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.
|
|
January 1, 2019
|
|
We continue to evaluate the effect of this standard on our Consolidated Financial Statements. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population, analyzing the practical expedients and assessing opportunities to make certain changes to our lease accounting information technology system in order to determine the best implementation strategy. Preliminarily, we anticipate a material impact from the requirement to recognize all leases upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the package of practical expedients permitted under the transition guidance which, among other things, allows the carryforward of prior conclusions related to lease identification and classification. We also expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.
|
Standard
|
|
Description
|
|
Date of Adoption
|
|
Effect on our Consolidated Financial Statements or Other Significant Matters
|
ASU 2014-09,
Revenue from Contracts with Customers (Topic 606)
, and subsequent amendments thereto
|
|
This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).
|
|
January 1, 2018
|
|
We adopted this guidance on January 1, 2018, using the full retrospective method. The adoption of this guidance represents a change in accounting principle that will provide financial statement readers with enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this guidance did not impact our previously reported financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings. See
Note 11—Revenues from Contracts with Customers
for additional disclosures.
|
ASU 2016-16,
Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
|
|
This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.
|
|
January 1, 2018
|
|
The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.
|
ITEM 2.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
statements regarding our ability to pay distributions to our unitholders;
|
•
|
statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL;
|
•
|
statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, 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 our ability to enter into such transactions;
|
•
|
statements relating to the construction of our Trains, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any such EPC or other contractor, and anticipated costs related thereto;
|
•
|
statements regarding any SPA or other 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, natural gas liquefaction or storage capacities that are, or may become, subject to 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, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
|
•
|
statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions; and
|
•
|
any other statements that relate to non-historica
l or future information.
|
•
|
Overview of Business
|
•
|
Overview of Significant Events
|
•
|
Liquidity and Capital Resources
|
•
|
Results of Operations
|
•
|
Off-Balance Sheet Arrangements
|
•
|
Summary of Critical Accounting Estimates
|
•
|
Recent Accounting Standards
|
•
|
As of April 30, approximately
90
cargoes have been produced, loaded and exported from the
Liquefaction Project
in 2018. To date, approximately
350
cumulative LNG cargoes have been exported from the
Liquefaction Project
, with deliveries to
26
countries and regions worldwide.
|
•
|
In March 2018, the date of first commercial delivery was reached under the 20-year SPA with GAIL (India) Limited relating to Train 4 of the
Liquefaction Project
.
|
|
March 31,
|
|
December 31,
|
||||
|
2018
|
|
2017
|
||||
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
—
|
|
Restricted cash designated for the following purposes:
|
|
|
|
||||
Liquefaction Project
|
561
|
|
|
544
|
|
||
CQP and cash held by guarantor subsidiaries
|
916
|
|
|
1,045
|
|
||
Available commitments under the following credit facilities:
|
|
|
|
||||
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)
|
494
|
|
|
470
|
|
||
2016 CQP Credit Facilities (“2016 CQP Credit Facilities”)
|
220
|
|
|
220
|
|
|
|
Train 5
|
|
Overall project completion percentage
|
|
89.3%
|
|
Completion percentage of:
|
|
|
|
Engineering
|
|
100%
|
|
Procurement
|
|
100%
|
|
Subcontract work
|
|
70.2%
|
|
Construction
|
|
78.0%
|
|
Date of expected substantial completion
|
|
1H 2019
|
•
|
Trains 1 through 4—
FTA countries
for a 30-year term, which commenced on May 15, 2016, and
non-FTA countries
for a 20-year term, which commenced on June 3, 2016, in an amount up to a combined total of the equivalent of 16
mtpa
(approximately 803
Bcf/yr
of natural gas).
|
•
|
Trains 1 through 4—
FTA countries
for a 25-year term and non-FTA countries for a 20-year term in an amount up to a combined total of the equivalent of approximately 203
Bcf/yr
of natural gas (approximately 4 mtpa).
|
•
|
Trains 5 and 6—
FTA countries
and
non-FTA countries
for a 20-year term, in an amount up to a combined total of 503.3
Bcf/yr
of natural gas (approximately 10 mtpa).
|
|
|
March 31,
|
|
December 31,
|
||||
|
|
2018
|
|
2017
|
||||
Senior notes (1)
|
|
$
|
15,150
|
|
|
$
|
15,150
|
|
Credit facilities outstanding balance (2)
|
|
1,090
|
|
|
1,090
|
|
||
Letters of credit issued (3)
|
|
706
|
|
|
730
|
|
||
Available commitments under credit facilities (3)
|
|
494
|
|
|
470
|
|
||
Total capital resources from borrowings and available commitments
|
|
$
|
17,440
|
|
|
$
|
17,440
|
|
|
(1)
|
Includes SPL’s 5.625% Senior Secured Notes due 2021, 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026
(the “2026 SPL Senior Notes”)
, 5.00% Senior Secured Notes due 2027
(the “2027 SPL Senior Notes”)
, 4.200% Senior Secured Notes due 2028
(the “2028 SPL Senior Notes”)
and 5.00% Senior Secured Notes due 2037
(the “2037 SPL Senior Notes”)
(collectively, the “SPL Senior Notes”)
and our
2025 CQP Senior Notes
.
|
(2)
|
Includes
SPL Working Capital Facility
and CTPL and SPLNG tranche term loans outstanding under the
2016 CQP Credit Facilities
.
|
(3)
|
Consists of
SPL Working Capital Facility
. Does not include the letters of credit issued or available commitments under the
2016 CQP Credit Facilities
, which are not specifically for the
Liquefaction Project
.
|
|
Three Months Ended March 31,
|
||||||
|
2018
|
|
2017
|
||||
Operating cash flows
|
$
|
331
|
|
|
$
|
115
|
|
Investing cash flows
|
(194
|
)
|
|
(524
|
)
|
||
Financing cash flows
|
(249
|
)
|
|
1,560
|
|
||
|
|
|
|
||||
Net increase (decrease) in cash, cash equivalents and restricted cash
|
(112
|
)
|
|
1,151
|
|
||
Cash, cash equivalents and restricted cash—beginning of period
|
1,589
|
|
|
605
|
|
||
Cash, cash equivalents and restricted cash—end of period
|
$
|
1,477
|
|
|
$
|
1,756
|
|
•
|
issuances of SPL’s senior notes for an aggregate principal amount of $2.15 billion;
|
•
|
$55 million of borrowings and $369 million of repayments made under the credit facilities SPL entered into in June 2015;
|
•
|
$110 million of borrowings and $334 million of repayments made under the
SPL Working Capital Facility
;
|
•
|
$26 million
of debt issuance costs related to up-front fees paid upon the closing of these transactions; and
|
•
|
$25 million
of distributions to unitholders.
|
|
|
|
|
|
|
|
|
Total Distribution (in millions)
|
||||||||||||||||||
Date Paid
|
|
Period Covered by Distribution
|
|
Distribution Per Common Unit
|
|
Distribution Per Subordinated Unit
|
|
Common Units
|
|
Subordinated Units
|
|
General Partner Units
|
|
Incentive Distribution Rights
|
||||||||||||
February 14, 2018
|
|
October 1 - December 31, 2017
|
|
$
|
0.500
|
|
|
$
|
0.500
|
|
|
$
|
174
|
|
|
$
|
68
|
|
|
$
|
5
|
|
|
$
|
1
|
|
February 13, 2017
|
|
October 1 - December 31, 2016
|
|
0.425
|
|
|
—
|
|
|
24
|
|
|
—
|
|
|
0.5
|
|
|
—
|
|
|
|
Three Months Ended March 31,
|
||||||||||
(in millions, except volumes)
|
|
2018
|
|
2017
|
|
Change
|
||||||
LNG revenues
|
|
$
|
1,015
|
|
|
$
|
492
|
|
|
$
|
523
|
|
LNG revenues—affiliate
|
|
503
|
|
|
331
|
|
|
172
|
|
|||
Regasification revenues
|
|
65
|
|
|
65
|
|
|
—
|
|
|||
Other revenues
|
|
10
|
|
|
2
|
|
|
8
|
|
|||
Other revenues—affiliate
|
|
—
|
|
|
1
|
|
|
(1
|
)
|
|||
Total revenues
|
|
$
|
1,593
|
|
|
$
|
891
|
|
|
$
|
702
|
|
|
|
|
|
|
|
|
||||||
LNG volumes recognized as revenues (in TBtu)
|
|
241
|
|
|
128
|
|
|
113
|
|
|
Three Months Ended March 31,
|
||||||||||
(in millions)
|
2018
|
|
2017
|
|
Change
|
||||||
Cost of sales
|
$
|
837
|
|
|
$
|
513
|
|
|
$
|
324
|
|
Operating and maintenance expense
|
95
|
|
|
50
|
|
|
45
|
|
|||
Operating and maintenance expense—affiliate
|
26
|
|
|
18
|
|
|
8
|
|
|||
General and administrative expense
|
4
|
|
|
3
|
|
|
1
|
|
|||
General and administrative expense—affiliate
|
18
|
|
|
22
|
|
|
(4
|
)
|
|||
Depreciation and amortization expense
|
105
|
|
|
66
|
|
|
39
|
|
|||
Total operating costs and expenses
|
$
|
1,085
|
|
|
$
|
672
|
|
|
$
|
413
|
|
|
Three Months Ended March 31,
|
||||||||||
(in millions)
|
2018
|
|
2017
|
|
Change
|
||||||
Interest expense, net of capitalized interest
|
$
|
185
|
|
|
$
|
130
|
|
|
$
|
55
|
|
Loss on early extinguishment of debt
|
—
|
|
|
42
|
|
|
(42
|
)
|
|||
Derivative gain, net
|
(8
|
)
|
|
—
|
|
|
(8
|
)
|
|||
Other income
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
|||
Total other expense
|
$
|
173
|
|
|
$
|
172
|
|
|
$
|
1
|
|
ITEM 3.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
March 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Fair Value
|
|
Change in Fair Value
|
|
Fair Value
|
|
Change in Fair Value
|
||||||||
Liquefaction Supply Derivatives
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
55
|
|
|
$
|
5
|
|
|
March 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Fair Value
|
|
Change in Fair Value
|
|
Fair Value
|
|
Change in Fair Value
|
||||||||
CQP Interest Rate Derivatives
|
$
|
27
|
|
|
$
|
5
|
|
|
$
|
21
|
|
|
$
|
5
|
|
ITEM 1A.
|
RISK FACTORS
|
ITEM 6.
|
EXHIBITS
|
Exhibit No.
|
|
Description
|
10.1*
|
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1**
|
|
|
32.2**
|
|
|
101.INS*
|
|
XBRL Instance Document
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
101.LAB*
|
|
XBRL Taxonomy Extension Labels Linkbase Document
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
|
|
|
|
*
|
Filed herewith.
|
**
|
Furnished herewith.
|
|
|
CHENIERE ENERGY PARTNERS, L.P.
|
|
|
|
By:
|
Cheniere Energy Partners GP, LLC,
|
|
|
|
its general partner
|
|
|
|
|
Date:
|
May 3, 2018
|
By:
|
/s/ Michael J. Wortley
|
|
|
|
Michael J. Wortley
|
|
|
|
Executive Vice President and Chief Financial Officer
|
|
|
|
(on behalf of the registrant and
as principal financial officer)
|
|
|
|
|
Date:
|
May 3, 2018
|
By:
|
/s/ Leonard Travis
|
|
|
|
Leonard Travis
|
|
|
|
Vice President and Chief Accounting Officer
|
|
|
|
(on behalf of the registrant and
as principal accounting officer)
|
PROJECT NAME:
Sabine Pass LNG Stage 3 Liquefaction Facility
OWNER:
Sabine Pass Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: May 4, 2015
|
CHANGE ORDER NUMBER:
CO-00025
DATE OF CHANGE ORDER:
January 19, 2018
|
1.
|
Per Article 6.1.B of the Agreement, the Parties agree Contractor will perform the Procurement and Construction services for the BOG and LNG Rundown tie-ins. These services will be based on the Engineering for the BOG and LNG Rundown that was included in the original RFS (RFS 109265 Revision 5).
|
2.
|
The BOG and LNG Rundown line tie-in packages will be developed after the HAZOP and Model review occurs. These packages will include IFC drawings to procure and construct the required materials. Potential changes due to HAZOP or Model review action items are excluded from this Change Order. For clarity, the tie-ins are depicted in Exhibit A of this Change Order.
|
3.
|
This Change Order is not included as part of Stage 3 Substantial Completion and will not prevent achievement thereof.
|
4.
|
The cost breakdown for this Change Order is detailed in Exhibit B.
|
5.
|
Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit C of this Change Order.
|
The original Contract Price was
|
$
|
2,987,000,000
|
|
Net change by previously authorized Change Orders (#00001-00024)
|
$
|
95,972,403
|
|
The Contract Price prior to this Change Order was
|
$
|
3,082,972,403
|
|
The Contract Price will be increased by this Change Order in the amount of
|
$
|
506,471
|
|
The new Contract Price including this Change Order will be
|
$
|
3,083,478,874
|
|
/s/ Ed Lehotsky
|
|
/s/ Bhupesh Thakkar
|
Owner
|
|
Contractor
|
Ed Lehotsky
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP LNG E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
February 15, 2018
|
|
January 19, 2018
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Sabine Pass LNG Stage 3 Liquefaction Facility
OWNER:
Sabine Pass Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: May 4, 2015
|
CHANGE ORDER NUMBER:
CO-00026
DATE OF CHANGE ORDER:
February 1, 2018
|
1.
|
Per Article 6.1.B of the Agreement, the Parties agree Contractor shall perform various transient runs along with CSA/PD&P design analysis of the existing East and West Jetty piping and structure for simultaneous loading. The key items for this analysis are listed as follows:
|
a.
|
Validation of Contractor’s transient model.
|
b.
|
Completion of 8,000 m
3
/hr simultaneous loading analysis to the existing East and West Jetty. Results will be reviewed by PD&P Pipe Stress to update load tables and identify pipe supports exceeding the original design loads.
|
c.
|
Completion of CSA and PD&P design analysis to support loading lines from the existing LNG tanks to the East and West Jetty. In addition, for the proposed modifications, the associated CSA and PD&P redline markups and IFC drawings will be provided to Owner.
|
2.
|
Owner may not disclose the Contractor Work Product to any third party, unless Contractor's prior written consent has been obtained (such consent not to be unreasonably withheld or delayed), provided that Contractor's prior written consent is hereby deemed to be given for disclosure to the Parties listed in Exhibit A to the extent such Parties have entered into a confidentiality agreement with Owner no less stringent than this Agreement.
|
3.
|
Notwithstanding anything to the contrary herein, Contractor shall perform the Work in accordance with the standard of skill and care reasonably to be expected in the international engineering and construction industry for projects of the type, size and complexity of the Work contemplated herein. In the event that any such Work under this Change Order fails to meet that standard of performance, Contractor's sole liability and Owner’s sole remedy shall be limited to Contractor reperforming such Work at its own expense; provided that notice of such failure is given by Owner within a reasonable time and no later than twelve (12) months from the completion of the Work in question.
|
4.
|
The Work to be performed under this Change Order is not a condition to and will not prevent the achievement of Substantial Completion of Subproject 5.
|
5.
|
The cost breakdown for this Change Order is detailed in Exhibit B.
|
6.
|
Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit C of this Change Order.
|
The original Contract Price was
|
$
|
2,987,000,000
|
|
Net change by previously authorized Change Orders (#00001-00025)
|
$
|
96,478,874
|
|
The Contract Price prior to this Change Order was
|
$
|
3,083,478,874
|
|
The Contract Price will be increased by this Change Order in the amount of
|
$
|
671,121
|
|
The new Contract Price including this Change Order will be
|
$
|
3,084,149,995
|
|
/s/ Ed Lehotsky
|
|
/s/ Bhupesh Thakkar
|
Owner
|
|
Contractor
|
Ed Lehotsky
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP LNG E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
February 15, 2018
|
|
February 1, 2018
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Sabine Pass LNG Stage 3 Liquefaction Facility
OWNER:
Sabine Pass Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: May 4, 2015
|
CHANGE ORDER NUMBER:
CO-00027
DATE OF CHANGE ORDER:
February 1, 2018
|
1.
|
The value of the Performance and Attendance Bonus (PAB) Incentive Program Provisional Sum incorporated into the Agreement in Change Order CO-00005, dated March 16, 2016, was U.S. $36,900,000. Parties now agree the Stage 2 accrued cost for retention of the PAB incentive will be transferred to Stage 3 and invoiced against the PAB value in the Stage 3 Agreement due to Craft personnel moving to Stage 3 as opposed to being released as part of a reduction of Stage 2 workforce. The amount to be transferred is $8,100,000. The contract price will be increased by $8,100,000.
|
2.
|
The Provisional Sum breakdown is described as follows:
|
a.
|
The previous PAB Incentive Program Provisional Sum in Article 2.6 of Attachment EE of the Agreement was Thirty-Six Million, Nine Hundred Thousand U.S. Dollars (U.S. $36,900,000). This Change Order will increase the PAB Incentive Program Provisional Sum by $8,100,000 and the value will be $45,000,000.
|
b.
|
The Parties agree to adjust the Aggregate Provisional Sum specified in Article 7.1A of the Agreement which prior to this Change Order was Three Hundred Sixteen Million, Two Hundred Forty-Six Thousand, Four Hundred Thirty-Seven U.S. Dollars (U.S. $316,246,437). This Change Order will increase the Aggregate Provisional Sum amount by Eight Million, One Hundred Thousand U.S. Dollars (U.S. $8,100,000) and the new Aggregate Provisional Sum value shall be Three Hundred Twenty-Four Million, Three Hundred Forty-Six Thousand, Four Hundred Thirty-Seven U.S. Dollars (U.S. $324,346,437).
|
3.
|
Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit A of this Change Order.
|
The original Contract Price was
|
$
|
2,987,000,000
|
|
Net change by previously authorized Change Orders (#00001-00026)
|
$
|
97,149,995
|
|
The Contract Price prior to this Change Order was
|
$
|
3,084,149,995
|
|
The Contract Price will be increased by this Change Order in the amount of
|
$
|
8,100,000
|
|
The new Contract Price including this Change Order will be
|
$
|
3,092,249,995
|
|
/s/ Ed Lehotsky
|
|
/s/ Bhupesh Thakkar
|
Owner
|
|
Contractor
|
Ed Lehotsky
|
|
Bhupesh Thakkar
|
Name
|
|
Name
|
SVP LNG E&C
|
|
Senior Project Manager
|
Title
|
|
Title
|
February 15, 2018
|
|
February 1, 2018
|
Date of Signing
|
|
Date of Signing
|
PROJECT NAME:
Sabine Pass LNG Stage 3 Liquefaction Facility
OWNER:
Sabine Pass Liquefaction, LLC
CONTRACTOR:
Bechtel Oil, Gas and Chemicals, Inc.
DATE OF AGREEMENT: May 4, 2015
|
CHANGE ORDER NUMBER:
CO-00028
DATE OF CHANGE ORDER:
February 27, 2018
|
1.
|
Per Article 6.1.B of the Agreement, the Parties agree Contractor will obtain structural steel from CIVES via purchase order to support the modifications of the existing jetty. This will require award of a purchase order referencing the existing Stage 3 CIVES purchase order and will require review by the CSA team prior to delivery of the steel to the Site.
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2.
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The following areas will be revised by CIVES: Area 1R1, Area 2R1, Area 3R1 and Area 22R. For clarity, the revised areas are depicted in Exhibit A of this Change Order.
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3.
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The steel associated with this Change Order will be free issued to Owner. The existing Stage 3 contract terms are not applicable to this work and Contractor’s obligation is limited to providing steel of good quality and ensuring the steel is fabricated in accordance with the specification, design drawings and fabrication details.
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4.
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The work pursuant to this Change Order is not a condition to and will not prevent the achievement of Stage 3 Substantial Completion or impact the Stage 3 warranty period.
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5.
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The cost breakdown for this Change Order is detailed in Exhibit B.
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6.
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Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit C of this Change Order.
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The original Contract Price was
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$
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2,987,000,000
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Net change by previously authorized Change Orders (#00001-00027)
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$
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105,249,995
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The Contract Price prior to this Change Order was
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$
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3,092,249,995
|
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The Contract Price will be increased by this Change Order in the amount of
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$
|
34,820
|
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The new Contract Price including this Change Order will be
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$
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3,092,284,815
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/s/ Ed Lehotsky
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/s/ Bhupesh Thakkar
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Owner
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Contractor
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Ed Lehotsky
|
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Bhupesh Thakkar
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Name
|
|
Name
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SVP LNG E&C
|
|
Senior Project Manager
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Title
|
|
Title
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March 13, 2018
|
|
February 27, 2018
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Date of Signing
|
|
Date of Signing
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1.
|
I have reviewed this
quarterly report on Form 10-Q
of Cheniere Energy Partners, L.P.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ Jack A. Fusco
|
Jack A. Fusco
|
Chief Executive Officer of
|
Cheniere Energy Partners GP, LLC, the general partner of
|
Cheniere Energy Partners, L.P.
|
1.
|
I have reviewed this
quarterly report on Form 10-Q
of Cheniere Energy Partners, L.P.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ Michael J. Wortley
|
Michael J. Wortley
|
Chief Financial Officer of
|
Cheniere Energy Partners GP, LLC, the general partner of
|
Cheniere Energy Partners, L.P.
|
(1)
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
/s/ Jack A. Fusco
|
Jack A. Fusco
|
Chief Executive Officer of
|
Cheniere Energy Partners GP, LLC, the general partner of
|
Cheniere Energy Partners, L.P.
|
(1)
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
/s/ Michael J. Wortley
|
Michael J. Wortley
|
Chief Financial Officer of
|
Cheniere Energy Partners GP, LLC, the general partner of
|
Cheniere Energy Partners, L.P.
|