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EX-10.4 - EXHIBIT 10.4 - Cheniere Energy Partners, L.P.exhibit104cqp20153rdqtr.htm
EX-10.5 - EXHIBIT 10.5 - Cheniere Energy Partners, L.P.exhibit105cqp20153rdqtr.htm
EX-31.2 - EXHIBIT 31.2 - Cheniere Energy Partners, L.P.exhibit312cqp20153rdqtr.htm
EX-31.1 - EXHIBIT 31.1 - Cheniere Energy Partners, L.P.exhibit311cqp20153rdqtr.htm
EX-32.2 - EXHIBIT 32.2 - Cheniere Energy Partners, L.P.exhibit322cqp20153rdqtr.htm
EX-32.1 - EXHIBIT 32.1 - Cheniere Energy Partners, L.P.exhibit321cqp20153rdqtr.htm
EX-10.6 - EXHIBIT 10.6 - Cheniere Energy Partners, L.P.exhibit106cqp20153rdqtr.htm


 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
 
FORM 10-Q
 
 
 
 
 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2015
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to            
Cheniere Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
 
 
 
 
 
 
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)
(713) 375-5000
(Registrant’s telephone number, including area code)
 
 
 
 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes x   No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  x
Accelerated filer                     ¨
Non-accelerated filer    ¨
Smaller reporting company    ¨
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes ¨   No x
As of October 20, 2015, the issuer had 57,101,348 common units, 145,333,334 Class B units and 135,383,831 subordinated units outstanding.
 
 
 
 
 
 



CHENIERE ENERGY PARTNERS, L.P.
TABLE OF CONTENTS




i




DEFINITIONS

As commonly used in the liquefied natural gas industry, to the extent applicable, and as used in this quarterly report, the terms listed below have the following meanings: 

Common Industry and Other Terms
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 consisting primarily of methane (CH4) that is in liquid form at near atmospheric pressure
MMBtu
 
million British thermal units, an energy unit
mtpa
 
million tonnes per annum
non-FTA countries
 
countries without a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC
 
Securities and Exchange Commission
SPA
 
LNG sale and purchase agreement
Train
 
a refrigerant compressor train used in the industrial process to convert natural gas into LNG
TUA
 
terminal use agreement

1




Abbreviated Organizational Structure

The following diagram depicts our abbreviated organizational structure as of September 30, 2015, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

  
Unless the context requires otherwise, references to “Cheniere Partners,” “the Partnership,” “we,” “us” and “our” refer to Cheniere Energy Partners, L.P. (NYSE MKT: CQP) and its consolidated subsidiaries, including SPLNG, SPL and CTPL

2


PART I.        FINANCIAL INFORMATION 
ITEM 1.     CONSOLIDATED FINANCIAL STATEMENTS 
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)




 
 
September 30,
 
December 31,
 
 
2015
 
2014
ASSETS
 
(unaudited)
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
170,433

 
$
248,830

Restricted cash
 
391,495

 
195,702

Accounts and interest receivable
 
95

 
333

Accounts receivable—affiliate
 
2,566

 
3,651

Advances to affiliate
 
54,995

 
27,323

LNG inventory
 
7,145

 
4,293

Other current assets
 
16,055

 
6,388

Total current assets
 
642,784

 
486,520

 
 
 
 
 
Non-current restricted cash
 
76,107

 
544,465

Property, plant and equipment, net
 
11,299,725

 
8,978,356

Debt issuance costs, net
 
307,099

 
241,909

Non-current derivative assets
 
30,657

 
11,744

Other non-current assets
 
190,960

 
124,521

Total assets
 
$
12,547,332

 
$
10,387,515

 
 
 
 
 
LIABILITIES AND PARTNERS’ EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
7,096

 
$
8,598

Accrued liabilities
 
352,457

 
136,578

Due to affiliates
 
32,851

 
18,952

Deferred revenue
 
26,653

 
26,655

Deferred revenue—affiliate
 
708

 
708

Derivative liabilities
 
7,388

 
23,247

Other current liabilities
 
267

 
18

Total current liabilities
 
427,420

 
214,756

 
 
 
 
 
Long-term debt, net
 
11,244,002

 
8,991,333

Non-current deferred revenue
 
10,500

 
13,500

Non-current derivative liabilities
 
8,832

 
267

Other non-current liabilities
 
1,177

 
2,185

Other non-current liabilities—affiliate
 
61,691

 
34,745

 
 
 
 
 
Partners’ equity
 
 
 
 
Common unitholders’ interest (57.1 million units issued and outstanding at September 30, 2015 and December 31, 2014)
 
346,443

 
495,597

Class B unitholders’ interest (145.3 million units issued and outstanding at September 30, 2015 and December 31, 2014)
 
(37,981
)
 
(38,216
)
Subordinated unitholders’ interest (135.4 million units issued and outstanding at September 30, 2015 and December 31, 2014)
 
467,054

 
648,414

General partner’s interest (2% interest with 6.9 million units issued and outstanding at September 30, 2015 and December 31, 2014)
 
18,194

 
24,934

Total partners’ equity
 
793,710


1,130,729

Total liabilities and partners’ equity
 
$
12,547,332

 
$
10,387,515


The accompanying notes are an integral part of these consolidated financial statements.

3


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(unaudited)
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Revenues

 

 
 
 
 
Revenues
$
66,596

 
$
66,890

 
$
199,804

 
$
199,933

Revenues—affiliate
941

 
700

 
2,952

 
2,206

Total revenues
67,537

 
67,590

 
202,756

 
202,139

 
 
 
 
 
 
 
 
Operating costs and expenses
 

 
 
 
 
 
 
Operating and maintenance expense (income)
(22,782
)
 
21,041

 
17,840

 
54,750

Operating and maintenance expense—affiliate
8,081

 
5,016

 
20,355

 
14,307

Depreciation expense
16,687

 
14,781

 
47,557

 
43,821

Development expense
113

 
1,383

 
2,631

 
8,671

Development expense—affiliate
152

 
329

 
562

 
723

General and administrative expense
3,673

 
2,448

 
11,269

 
10,048

General and administrative expense—affiliate
25,692

 
24,454

 
80,761

 
74,579

Total operating costs and expenses
31,616

 
69,452

 
180,975

 
206,899

 
 
 
 
 
 
 
 
Income (loss) from operations
35,921

 
(1,862
)
 
21,781

 
(4,760
)
 
 
 
 
 
 
 
 
Other income (expense)
 

 
 
 
 
 
 
Interest expense, net of amounts capitalized
(49,360
)
 
(46,884
)
 
(142,353
)
 
(130,943
)
Loss on early extinguishment of debt

 

 
(96,273
)
 
(114,335
)
Derivative gain (loss), net
(10,872
)
 
5,379

 
(46,541
)
 
(89,222
)
Other income
179

 
127

 
535

 
63

Total other expense
(60,053
)
 
(41,378
)
 
(284,632
)
 
(334,437
)
 
 
 
 
 
 
 
 
Net loss
$
(24,132
)
 
$
(43,240
)
 
$
(262,851
)
 
$
(339,197
)
 
 
 
 
 
 
 
 
Basic and diluted net income (loss) per common unit
$
0.18

 
$
0.08

 
$
(0.44
)
 
$
(0.83
)
 
 
 
 
 
 
 
 
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation
57,081

 
57,079

 
57,081

 
57,079


















The accompanying notes are an integral part of these consolidated financial statements.

4


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES


CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY
(in thousands)
(unaudited)
 
Common Unitholders’ Interest
 
Class B Unitholders’ Interest
 
Subordinated Unitholder’s Interest
 
General Partner’s Interest
 
Total Partners’ Equity
 
Units
 
Amount
 
Units
 
Amount
 
Units
 
Amount
 
Units
 
Amount
 
Balance at December 31, 2014
57,080

 
$
495,597

 
145,333

 
$
(38,216
)
 
135,384

 
$
648,414

 
6,894

 
$
24,934

 
$
1,130,729

Net loss

 
(76,399
)
 

 

 

 
(181,195
)
 

 
(5,257
)
 
(262,851
)
Distributions

 
(72,776
)
 

 

 

 

 

 
(1,485
)
 
(74,261
)
Issuance of common units as compensation to non-management directors
3

 
91

 

 

 

 

 

 
2

 
93

Amortization of beneficial conversion feature of Class B units

 
(70
)
 

 
235

 

 
(165
)
 

 

 

Balance at September 30, 2015
57,083

 
$
346,443

 
145,333

 
$
(37,981
)
 
135,384

 
$
467,054

 
6,894

 
$
18,194

 
$
793,710



























The accompanying notes are an integral part of these consolidated financial statements.

5


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
 
Nine Months Ended
 
September 30,
 
2015
 
2014
Cash flows from operating activities
 
 
 
Net loss
$
(262,851
)
 
$
(339,197
)
Adjustments to reconcile net loss to net cash used in operating activities:
 
 
 
Non-cash LNG inventory write-downs
17,826

 
23,505

Depreciation expense
47,557

 
43,821

Amortization of debt issuance costs and discount (premium)
9,282

 
10,971

Loss on early extinguishment of debt
96,273

 
114,335

Total losses on derivatives, net
13,040

 
89,286

Net cash used for settlement of derivative instruments
(40,796
)
 
(19,834
)
Other
92

 
(6
)
Changes in restricted cash for certain operating activities
167,083

 
59,942

Changes in operating assets and liabilities:
 
 
 
Accounts and interest receivable
238

 
(19,653
)
Accounts receivable—affiliate
(48
)
 
810

Advances to affiliate
(27,672
)
 
656

LNG inventory
(20,678
)
 
(26,315
)
Accounts payable and accrued liabilities
(1,178
)
 
46,693

Due to affiliates
(8,154
)
 
(813
)
Deferred revenue
(3,003
)
 
(2,955
)
Other, net
(10,156
)
 
(3,721
)
Other, net—affiliate
22,198

 
(147
)
Net cash used in operating activities
(947
)
 
(22,622
)
 
 
 
 
Cash flows from investing activities
 

 
 

Property, plant and equipment, net
(2,130,959
)
 
(1,968,249
)
Use of restricted cash for the acquisition of property, plant and equipment
2,178,481

 
1,978,891

Other
(50,711
)
 
(12,188
)
Net cash used in investing activities
(3,189
)
 
(1,546
)
 
 
 
 
Cash flows from financing activities
 

 
 

Proceeds from issuances of long-term debt
2,250,000

 
2,584,500

Repayments of long-term debt

 
(177,000
)
Debt issuance and deferred financing costs
(177,001
)
 
(94,270
)
Investment in restricted cash
(2,072,999
)
 
(2,312,160
)
Distributions to owners
(74,261
)
 
(74,236
)
Other

 
(1,050
)
Net cash used in financing activities
(74,261
)
 
(74,216
)
 
 
 
 
Net decrease in cash and cash equivalents
(78,397
)
 
(98,384
)
Cash and cash equivalents—beginning of period
248,830

 
351,032

Cash and cash equivalents—end of period
$
170,433

 
$
252,648





The accompanying notes are an integral part of these consolidated financial statements.

6


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)


 
NOTE 1—BASIS OF PRESENTATION

The accompanying unaudited Consolidated Financial Statements of Cheniere Partners have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.

Results of operations for the three and nine months ended September 30, 2015 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2015.

We are not subject to either federal or state income tax, as our partners are taxed individually on their allocable share of our taxable income.

For further information, refer to the Consolidated Financial Statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2014.

NOTE 2—UNITHOLDERS’ EQUITY
 
The common units, Class B units and subordinated units represent limited partner interests in us. The holders of the units are entitled to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Generally, our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from operating surplus as defined in the partnership agreement.

The holders of common units have the right to receive initial quarterly distributions of $0.425 per common unit, plus any arrearages thereon, before any distribution is made to the holders of the subordinated units. The holders of subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distribution requirement for our common unitholders and general partner and certain reserves.  Subordinated units will convert into common units on a one-for-one basis when we meet financial tests specified in the partnership agreement. Although common and subordinated unitholders are not obligated to fund losses of the Partnership, their capital accounts, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continue to share in losses.

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights, which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus after the initial quarterly distributions have been achieved and as additional target levels are met. The higher percentages range from 15% to 50%.
 
During 2012, Blackstone CQP Holdco LP (“Blackstone”) and Cheniere completed their purchases of a new class of equity interests representing limited partner interests in us (“Class B units”) for total consideration of $1.5 billion and $500.0 million, respectively. Proceeds from the financings were used to fund a portion of the costs of developing, constructing and placing into service the first two Trains of the natural gas liquefaction facilities at the Sabine Pass LNG terminal adjacent to the existing regasification facilities (the “Liquefaction Project”). In May 2013, Cheniere purchased an additional 12.0 million Class B units for consideration of $180.0 million in connection with our acquisition of CTPL and Cheniere Pipeline GP Interests, LLC.  In 2013, Cheniere formed Cheniere Holdings to hold its limited partner interests in us. The Class B units are subject to conversion, mandatorily or at the option of the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. The Class B units are not entitled to cash distributions except in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets. On a quarterly basis beginning on the date of the initial purchase of the Class B units and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere Holdings and Blackstone was 1.57 and 1.54, respectively, as of September 30, 2015. We expect the Class B units to

7


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

mandatorily convert into common units within 90 days of the substantial completion date of Train 3 of the Liquefaction Project, which we currently expect to occur before April 30, 2017. If the Class B units are not mandatorily converted by July 2019, the holders of the Class B units have the option to convert the Class B units into common units at that time.

NOTE 3—RESTRICTED CASH
 
Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. Restricted cash includes the following:
 
SPLNG Senior Notes Debt Service Reserve

SPLNG, our wholly owned subsidiary, has consummated private offerings of an aggregate principal amount of $1,665.5 million, before discount, of 7.50% Senior Secured Notes due 2016 (the “2016 SPLNG Senior Notes”) and $420.0 million of 6.50% Senior Secured Notes due 2020 (the “2020 SPLNG Senior Notes” and collectively with the 2016 SPLNG Senior Notes, the “SPLNG Senior Notes”). Under the indentures governing the SPLNG Senior Notes (the “SPLNG Indentures”), except for permitted tax distributions, SPLNG may not make distributions until certain conditions are satisfied, including: (1) there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and (2) there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the SPLNG Indentures.

As of September 30, 2015 and December 31, 2014, we classified $53.0 million and $15.0 million, respectively, as current restricted cash for the payment of current interest due. As of both September 30, 2015 and December 31, 2014, we classified the permanent debt service reserve fund of $76.1 million as non-current restricted cash. These cash accounts are controlled by a collateral trustee; therefore, these amounts are shown as restricted cash on our Consolidated Balance Sheets.

SPL Reserve

During 2013, SPL entered into four credit facilities aggregating $5.9 billion (collectively, the “2013 SPL Credit Facilities”). In June 2015, SPL entered into four credit facilities aggregating $4.6 billion (collectively, the “2015 SPL Credit Facilities”), which replaced the 2013 SPL Credit Facilities. Under the terms and conditions of the 2015 SPL Credit Facilities (and previously the 2013 SPL Credit Facilities), SPL is required to deposit all cash received into reserve accounts controlled by a collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project; therefore, these amounts are shown as restricted cash on our Consolidated Balance Sheets.

During 2013, SPL issued an aggregate principal amount of $2.0 billion, before premium, of 5.625% Senior Secured Notes due 2021 (the “2021 SPL Senior Notes”), $1.0 billion of 6.25% Senior Secured Notes due 2022 (the “2022 SPL Senior Notes”) and $1.0 billion of 5.625% Senior Secured Notes due 2023 (the “Initial 2023 SPL Senior Notes”). During 2014, SPL issued an aggregate principal amount of $2.0 billion of 5.75% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) and additional 5.625% Senior Secured Notes due 2023 in an aggregate principal amount of $0.5 billion, before premium (the “Additional 2023 SPL Senior Notes” and collectively with the Initial 2023 SPL Senior Notes, the “2023 SPL Senior Notes”). In March 2015, SPL issued an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes” and collectively with the 2021 SPL Senior Notes, the 2022 SPL Senior Notes, the 2023 SPL Senior Notes and the 2024 SPL Senior Notes, the “SPL Senior Notes”). The use of cash proceeds from the SPL Senior Notes is restricted to the payment of liabilities related to the Liquefaction Project; therefore, these amounts are shown as restricted cash on our Consolidated Balance Sheets. See Note 7—Long-Term Debt for additional details about our long-term debt.

As of September 30, 2015 and December 31, 2014, we classified $327.2 million and $155.8 million, respectively, as current restricted cash held by SPL for the payment of current liabilities, including interest payments, related to the Liquefaction Project and zero and $457.1 million, respectively, as non-current restricted cash held by SPL for future Liquefaction Project construction costs.


8


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

CTPL Reserve

In May 2013, CTPL entered into a $400.0 million term loan facility (the “CTPL Term Loan”). As of September 30, 2015 and December 31, 2014, we classified $11.3 million and $24.9 million, respectively, as current restricted cash held by CTPL for the payment of current liabilities and zero and $11.3 million, respectively, as non-current restricted cash held by CTPL, because the usage and withdrawal of such funds is primarily restricted to the payment of liabilities related to modifications of the 94-mile pipeline which interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) in order to enable bi-directional natural gas flow, and for the payment of interest during construction of such modifications. The restricted cash reserved to pay interest during construction is controlled by a collateral agent and can only be released by the collateral agent upon satisfaction of certain terms and conditions. CTPL is required to pay annual fees to the administrative and collateral agents.

NOTE 4—PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment consists of LNG terminal costs and fixed assets, as follows (in thousands):
 
 
September 30,
 
December 31,
 
 
2015
 
2014
LNG terminal costs
 
 
 
 
LNG terminal
 
$
2,446,927

 
$
2,240,233

LNG terminal construction-in-process
 
9,240,976

 
7,082,732

LNG site and related costs, net
 
136

 
141

Accumulated depreciation
 
(395,426
)
 
(348,907
)
Total LNG terminal costs, net
 
11,292,613

 
8,974,199

Fixed assets
 
 

 
 

Computer and office equipment
 
1,126

 
1,105

Furniture and fixtures
 
1,375

 
1,375

Vehicles
 
2,033

 
1,507

Machinery and equipment
 
2,014

 
1,508

Other
 
5,592

 
2,505

Accumulated depreciation
 
(5,028
)
 
(3,843
)
Total fixed assets, net
 
7,112

 
4,157

Property, plant and equipment, net
 
$
11,299,725

 
$
8,978,356

 

NOTE 5—DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments that are reported at fair value:
commodity derivatives to hedge the exposure to price risk attributable to future: (1) sales of our LNG inventory and (2) purchases of natural gas to operate the Sabine Pass LNG terminal (“Natural Gas Derivatives”);
commodity derivatives consisting of natural gas purchase agreements and associated economic hedges to secure natural gas feedstock for the Liquefaction Project (“Liquefaction Supply Derivatives”); and
interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 SPL Credit Facilities (and previously the 2013 SPL Credit Facilities) (“Interest Rate Derivatives”).
None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations.

SPLNG has elected to account for a portion of the Natural Gas Derivatives as normal purchase normal sale transactions, exempt from fair value accounting. Gains and losses for these physical hedges are not reflected on our Consolidated Statements of Operations until the period of delivery. SPLNG had not posted collateral for such forward contracts as of September 30, 2015 and December 31, 2014.


9


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

The following table (in thousands) shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of September 30, 2015 and December 31, 2014, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets.
 
Fair Value Measurements as of
 
September 30, 2015
 
December 31, 2014
 
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
Natural Gas Derivatives asset
$

 
$
470

 
$

 
$
470

 
$

 
$
1,216

 
$

 
$
1,216

Liquefaction Supply Derivatives asset

 

 
32,546

 
32,546

 

 

 
342

 
342

Interest Rate Derivatives liability

 
(15,738
)
 

 
(15,738
)
 

 
(12,036
)
 

 
(12,036
)

The estimated fair values of our Natural Gas Derivatives are the amounts at which the instruments could be exchanged currently between willing parties. We value these derivatives using observable commodity price curves and other relevant data. We value the Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.

The fair value of substantially all of the Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of the Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of the Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a particular Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. Internal fair value models that include contractual pricing with a fixed basis include fixed basis amounts for delivery at locations for which no market currently exists. Internal fair value models also include conditions precedent to the respective long-term natural gas purchase agreements. As of September 30, 2015 and December 31, 2014, some of the Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure has not been developed to accommodate marketable physical gas flow. In the absence of infrastructure to accommodate marketable physical gas flow, our internal fair value models are based on a market price that equates to our own contractual pricing due to: (1) the inactive and unobservable market and (2) conditions precedent and their impact on the uncertainty in the timing of our actual receipt of the physical volumes associated with each forward. The fair value of the Liquefaction Supply Derivatives is predominantly driven by market commodity basis prices and our assessment of the associated conditions precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. Upon the completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas purchase agreements as of the reporting date.

There were no transfers into or out of Level 3 Liquefaction Supply Derivatives for the three and nine months ended September 30, 2015 and 2014. As all of the physical Liquefaction Supply Derivatives are either purely index-priced or index-priced with a fixed basis, we do not believe that a significant change in market commodity prices would have a material impact on our Level 3 fair value measurements. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of September 30, 2015:
 
 
Net Fair Value Asset (in thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
Significant Unobservable Inputs Range
Liquefaction Supply Derivatives
 
$32,546
 
Income Approach
 
Basis Spread
 
$ (0.350) - $0.050

Derivative assets and liabilities arising from our derivative contracts with the same counterparty are reported on a net basis, as all counterparty derivative contracts provide for net settlement. The use of derivative instruments exposes us to counterparty

10


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position.  

Commodity Derivatives

We recognize all commodity derivative instruments that qualify for derivative accounting treatment, including our Natural Gas Derivatives and the Liquefaction Supply Derivatives (collectively, “Commodity Derivatives”), as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Commodity Derivatives are reported in earnings.

The following table (in thousands) shows the fair value and location of our Commodity Derivatives on our Consolidated Balance Sheets:
 
 
September 30, 2015
 
December 31, 2014
 
 
Natural Gas Derivatives (1)
 
Liquefaction Supply Derivatives
 
Total
 
Natural Gas Derivatives (1)
 
Liquefaction Supply Derivatives
 
Total
Balance Sheet Location
 
 
 
 
 
 
 
 
 
 
 
 
Other current assets
 
$
470

 
$
2,371

 
$
2,841

 
$
1,216

 
$
76

 
$
1,292

Non-current derivative assets
 

 
30,657

 
30,657

 

 
586

 
586

Total derivative assets
 
470


33,028

 
33,498

 
1,216

 
662

 
1,878

 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative liabilities
 

 
(349
)
 
(349
)
 

 
(53
)
 
(53
)
Non-current derivative liabilities
 

 
(133
)
 
(133
)
 

 
(267
)
 
(267
)
Total derivative liabilities
 


(482
)
 
(482
)
 

 
(320
)
 
(320
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative asset, net
 
$
470


$
32,546


$
33,016

 
$
1,216

 
$
342

 
$
1,558

 
(1)
Does not include collateral calls of $0.3 million and $1.1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014, respectively.

The following table (in thousands) shows the changes in the fair value and settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2015 and 2014:
 
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
Statement of Operations Location
 
2015
 
2014
 
2015
 
2014
Natural Gas Derivatives loss
Revenues
 
$

 
$

 
$

 
$
(31
)
Natural Gas Derivatives gain (loss)
Operating and maintenance expense (income)
 
857

 
194

 
1,317

 
(64
)
Liquefaction Supply Derivatives gain (1)
Operating and maintenance expense (income)
 
32,103

 

 
32,184

 

 
 
 
 
 
(1)
There were no physical settlements during the reporting period.

 Natural Gas Derivatives

Our Natural Gas Derivatives are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. We are required by these financial institutions to use margin deposits as credit support for our Natural Gas Derivatives activities.

11


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)


Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges to secure natural gas feedstock for the Liquefaction Project. The terms of the physical contracts range from approximately one to seven years and commence upon the occurrence of conditions precedent, including the date of first commercial operation of specified Trains of the Liquefaction Project. We recognize the Liquefaction Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of the Liquefaction Supply Derivatives are reported in earnings. As of September 30, 2015, SPL has secured up to approximately 2,156.6 million MMBtu of natural gas feedstock through long-term natural gas purchase agreements, of which the forward notional natural gas buy position of the Liquefaction Supply Derivatives was approximately 1,244.1 million MMBtu, which were recorded as derivatives due to minimum purchase requirements.

Interest Rate Derivatives

SPL has entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2015 SPL Credit Facilities. The Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities.

In March 2015, SPL settled a portion of its Interest Rate Derivatives, and we recognized a derivative loss of $34.7 million within our Consolidated Statements of Operations in conjunction with the termination of approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities as discussed in Note 7—Long-Term Debt. In May 2014, SPL settled a portion of its Interest Rate Derivatives and recognized a derivative loss of $9.3 million within our Consolidated Statements of Operations in conjunction with the early termination of approximately $2.1 billion of commitments under the 2013 SPL Credit Facilities.

At September 30, 2015, SPL had the following Interest Rate Derivatives outstanding:
 
 
Initial Notional Amount
 
Maximum Notional Amount
 
Effective Date
 
Maturity Date
 
Weighted Average Fixed Interest Rate Paid
 
Variable Interest Rate Received
Interest Rate Derivatives
 
$20.0 million
 
$628.8 million
 
August 14, 2012
 
July 31, 2019
 
1.98%
 
One-month LIBOR

The following table (in thousands) shows the fair value and location of the Interest Rate Derivatives on our Consolidated Balance Sheets:
 
 
 
 
Fair Value Measurements as of
 
 
Balance Sheet Location
 
September 30, 2015
 
December 31, 2014
Interest Rate Derivatives
 
Derivative liabilities
 
$
(7,039
)
 
$
(23,194
)
Interest Rate Derivatives
 
Non-current derivative assets (Non-current derivative liabilities)
 
(8,699
)
 
11,158


The following table (in thousands) shows the changes in the fair value and settlements of the Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the three and nine months ended September 30, 2015 and 2014:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014
Interest Rate Derivatives gain (loss)
 
$
(10,872
)
 
$
5,379

 
$
(46,541
)
 
$
(89,222
)


12


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

Balance Sheet Presentation

Our Commodity Derivatives and Interest Rate Derivatives are presented on a net basis on our Consolidated Balance Sheets as described above. The following table (in thousands) shows the fair value of our derivatives outstanding on a gross and net basis:
 
 
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 September 30, 2015
 
 
 
 
 
 
Natural Gas Derivatives
 
$
513

 
$
(43
)
 
$
470

Liquefaction Supply Derivatives
 
33,028

 

 
33,028

Liquefaction Supply Derivatives
 
(482
)
 

 
(482
)
Interest Rate Derivatives
 
(15,738
)
 

 
(15,738
)
As of December 31, 2014
 
 
 
 
 
 
Natural Gas Derivatives
 
1,226

 
(10
)
 
1,216

Liquefaction Supply Derivatives
 
662

 

 
662

Liquefaction Supply Derivatives
 
(320
)
 

 
(320
)
Interest Rate Derivatives
 
11,158

 

 
11,158

Interest Rate Derivatives
 
(23,194
)
 

 
(23,194
)

NOTE 6—ACCRUED LIABILITIES
 
As of September 30, 2015 and December 31, 2014, accrued liabilities consisted of the following (in thousands):
 
 
September 30,
 
December 31,
 
 
2015
 
2014
Interest expense and related debt fees
 
$
166,317

 
$
112,858

Liquefaction Project costs
 
177,516

 
22,014

LNG terminal costs
 
5,987

 
1,077

Other accrued liabilities
 
2,637

 
629

Total accrued liabilities
 
$
352,457

 
$
136,578


NOTE 7—LONG-TERM DEBT
 
As of September 30, 2015 and December 31, 2014, our long-term debt consisted of the following (in thousands):
 
 
Interest
 
September 30,
 
December 31,
 
 
Rate
 
2015
 
2014
Long-term debt
 
 
 
 
 
 
2016 SPLNG Senior Notes
 
7.500%
 
$
1,665,500

 
$
1,665,500

2020 SPLNG Senior Notes
 
6.500%
 
420,000

 
420,000

2021 SPL Senior Notes
 
5.625%
 
2,000,000

 
2,000,000

2022 SPL Senior Notes
 
6.250%
 
1,000,000

 
1,000,000

2023 SPL Senior Notes
 
5.625%
 
1,500,000

 
1,500,000

2024 SPL Senior Notes
 
5.750%
 
2,000,000

 
2,000,000

2025 SPL Senior Notes
 
5.625%
 
2,000,000

 

2015 SPL Credit Facilities (1)
 
(2)
 
250,000

 

CTPL Term Loan (3)
 
(4)
 
400,000

 
400,000

SPL Working Capital Facility (5)
 
(6)
 

 

Total long-term debt
 
 
 
11,235,500

 
8,985,500

Long-term debt premium (discount)
 
 
 
 
 
 
2016 SPLNG Senior Notes
 
 
 
(5,477
)
 
(8,998
)
2021 SPL Senior Notes
 
 
 
9,090

 
10,177

2023 SPL Senior Notes
 
 
 
6,570

 
7,089

CTPL Term Loan
 
 
 
(1,681
)
 
(2,435
)
Total long-term debt, net
 
 
 
$
11,244,002

 
$
8,991,333


13


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

 
(1)
Matures on the earlier of December 31, 2020 or the second anniversary of the completion date of Trains 1 through 5 of the Liquefaction Project.
(2)
Variable interest rate, at SPL’s election, is LIBOR or the base rate plus the applicable margin. The applicable margins for LIBOR loans range from 1.30% to 1.75%, depending on the applicable 2015 SPL Credit Facility, and the applicable margin for base rate loans is 1.75%. Interest on LIBOR loans is due and payable at the end of each LIBOR period, and interest on base rate loans is due and payable at the end of each quarter.
(3)
Matures on May 28, 2017 when the full amount of the outstanding principal obligations must be repaid.
(4)
Variable interest rate, at CTPL’s election, is LIBOR or the base rate plus the applicable margin. CTPL has historically elected LIBOR loans, for which the applicable margin is 3.25% and is due and payable at the end of each LIBOR period.
(5)
Matures on December 31, 2020, with various terms for underlying loans, as further described below under SPL Working Capital Facility. As of September 30, 2015 and December 31, 2014, no loans were outstanding under the SPL Working Capital Facility or the SPL LC Agreement it replaced.
(6)
Variable interest rates, based on LIBOR or the base rate, as further described below under SPL Working Capital Facility.

For the three months ended September 30, 2015 and 2014, we incurred $185.2 million and $154.8 million of total interest cost, respectively, of which we capitalized and deferred $135.8 million and $107.9 million, respectively, including amortization of debt issuance costs, primarily related to the construction of the Liquefaction Project. For the nine months ended September 30, 2015 and 2014, we incurred $520.1 million and $423.8 million of total interest cost, respectively, of which we capitalized and deferred $377.7 million and $292.8 million, respectively, including amortization of debt issuance costs, primarily related to this construction.
 
SPLNG Senior Notes

Under the SPLNG Indentures, except for permitted tax distributions, SPLNG may not make distributions until certain conditions are satisfied as described in Note 3—Restricted Cash. During the nine months ended September 30, 2015 and 2014, SPLNG made distributions of $267.9 million and $237.7 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

SPL Senior Notes

In March 2015, SPL issued an aggregate principal amount of $2.0 billion of the 2025 SPL Senior Notes, for which borrowings accrue interest at a fixed rate of 5.625%. The terms of the 2025 SPL Senior Notes are governed by the same common indenture with the other SPL Senior Notes. In connection with the closing of the sale of the 2025 SPL Senior Notes, SPL entered into a Registration Rights Agreement dated March 3, 2015 (the “2025 SPL Registration Rights Agreement”). Under the terms of the 2025 SPL Registration Rights Agreement, SPL has agreed, and any future guarantors of the 2025 SPL Senior Notes will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement within 360 days after March 3, 2015 with respect to an offer to exchange any and all of the 2025 SPL Senior Notes for a like aggregate principal amount of debt securities of SPL with terms identical in all material respects to the respective 2025 SPL Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), and that are registered under the Securities Act of 1933, as amended. Under specified circumstances, SPL has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2025 SPL Senior Notes. SPL will be obligated to pay additional interest if it fails to comply with its obligations to register the 2025 SPL Senior Notes within the specified time period.

2015 SPL Credit Facilities

In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion. The 2015 SPL Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project. Borrowings under the 2015 SPL Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred. As of September 30, 2015, SPL had $4.3 billion of available commitments and $250.0 million of outstanding borrowings under the 2015 SPL Credit Facilities.


14


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

SPL incurred $88.2 million of debt issuance costs in connection with the 2015 SPL Credit Facilities. In addition to interest, SPL is required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered tranches of the 2015 SPL Credit Facilities.  The 2015 SPL Credit Facilities also require SPL to pay a quarterly commitment fee calculated at a rate per annum equal to either: (1) 40% of the applicable margin, multiplied by the average daily amount of the undrawn commitment, or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 SPL Credit Facility. The principal of the loans made under the 2015 SPL Credit Facilities must be repaid in quarterly installments, commencing with the earlier of June 30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the Liquefaction Project. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2015 SPL Credit Facilities.

The 2015 SPL Credit Facilities contain conditions precedent for borrowings, as well as customary affirmative and negative covenants. The obligations of SPL under the 2015 SPL Credit Facilities are secured by substantially all of the assets of SPL as well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes and the Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “SPL Working Capital Facility”) described below.

Under the terms of the 2015 SPL Credit Facilities, SPL is required to hedge not less than 65% of the variable interest rate exposure of its projected outstanding borrowings, calculated on a weighted average basis in comparison to its anticipated draw of principal.

2013 SPL Credit Facilities

 In May 2013, SPL entered into the 2013 SPL Credit Facilities to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 4 of the Liquefaction Project. As of December 31, 2014, SPL had no outstanding borrowings under the 2013 SPL Credit Facilities. In June 2015, the 2013 SPL Credit Facilities were replaced with the 2015 SPL Credit Facilities.

In March 2015, in conjunction with SPL’s issuance of the 2025 SPL Senior Notes, SPL terminated approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities. This termination and the replacement of the 2013 SPL Credit Facilities with the 2015 SPL Credit Facilities in June 2015 resulted in a write-off of debt issuance costs and deferred commitment fees associated with the 2013 SPL Credit Facilities of $96.3 million for the nine months ended September 30, 2015.
CTPL Term Loan

As of September 30, 2015, CTPL had borrowed the full amount of $400.0 million available under the CTPL Term Loan. The outstanding balance may be repaid, in whole or in part, at any time without premium or penalty.

SPL Working Capital Facility

In September 2015, SPL entered into a $1.2 billion SPL Working Capital Facility, which replaced the $325.0 million Senior Letter of Credit and Reimbursement Agreement that was entered into in April 2014 (the “SPL LC Agreement”). The SPL Working Capital Facility is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of letters of credit on behalf of SPL (“Letters of Credit”), as well as for swing line loans to SPL (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to an additional $390 million. As of September 30, 2015, SPL had $1.1 billion of available commitments, $127.6 million aggregate amount of issued Letters of Credit and no Working Capital Loans, Swing Line Loans or loans deemed made in connection with a draw upon a Letter of Credit (“LC Loans” and collectively with Working Capital Loans and Swing Line Loans, the “SPL Working Capital Facility Loans”) outstanding under the SPL Working Capital Facility. As of December 31, 2014, SPL had issued letters of credit in an aggregate amount of $9.5 million, and no draws had been made upon any letters of credit issued under the SPL LC Agreement.
 
SPL Working Capital Facility Loans accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR

15


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

SPL Working Capital Facility Loans is 1.75% per annum, and the applicable margin for base rate SPL Working Capital Facility Loans is 0.75% per annum. Interest on Swing Line Loans and LC Loans is due and payable on the date the loan becomes due. Interest on LIBOR Working Capital Loans is due and payable at the end of each applicable LIBOR period, and interest on base rate Working Capital Loans is due and payable at the end of each fiscal quarter. However, if such base rate Working Capital Loan is converted into a LIBOR Working Capital Loan, interest is due and payable on that date. Additionally, if the loans become due prior to such periods, the interest also becomes due on that date.

SPL incurred $27.5 million of debt issuance costs in connection with the SPL Working Capital Facility. SPL pays (1) a commitment fee on the average daily amount of the excess of the total commitment amount over the principal amount outstanding without giving effect to any outstanding Swing Line Loans in an amount equal to an annual rate of 0.70% and (2) a Letter of Credit fee equal to an annual rate of 1.75% of the undrawn portion of all Letters of Credit issued under the SPL Working Capital Facility. If draws are made upon a Letter of Credit issued under the SPL Working Capital Facility and SPL does not elect for such draw (an “LC Draw”) to be deemed an LC Loan, SPL is required to pay the full amount of the LC Draw on or prior to the business day following the notice of the LC Draw. An LC Draw accrues interest at an annual rate of 2.0% plus the base rate. As of September 30, 2015, no LC Draws had been made upon any Letters of Credit issued under the SPL Working Capital Facility.

The SPL Working Capital Facility matures on December 31, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty upon three business days’ notice. LC Loans have a term of up to one year. Swing Line Loans terminate upon the earliest of (1) the maturity date or earlier termination of the SPL Working Capital Facility, (2) the date 15 days after such Swing Line Loan is made and (3) the first borrowing date for a Working Capital Loan or Swing Line Loan occurring at least three business days following the date the Swing Line Loan is made. SPL is required to reduce the aggregate outstanding principal amount of all Working Capital Loans to zero for a period of five consecutive business days at least once each year.

The SPL Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. The obligations of SPL under the SPL Working Capital Facility are secured by substantially all of the assets of SPL as well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes and 2015 SPL Credit Facilities.

Fair Value Disclosures

The following table (in thousands) shows the carrying amount and estimated fair value of our long-term debt:
 
 
September 30, 2015
 
December 31, 2014
 
 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
2016 SPLNG Senior Notes, net of discount (1)
 
$
1,660,023

 
$
1,684,923

 
$
1,656,502

 
$
1,718,621

2020 SPLNG Senior Notes (1)
 
420,000

 
410,550

 
420,000

 
428,400

2021 SPL Senior Notes, net of premium (1)
 
2,009,090

 
1,853,386

 
2,010,177

 
1,985,050

2022 SPL Senior Notes (1)
 
1,000,000

 
930,000

 
1,000,000

 
1,020,000

2023 SPL Senior Notes, net of premium (1)
 
1,506,570

 
1,344,614

 
1,507,089

 
1,476,947

2024 SPL Senior Notes (1)
 
2,000,000

 
1,765,000

 
2,000,000

 
1,970,000

2025 SPL Senior Notes (1)
 
2,000,000

 
1,755,000

 

 

2015 SPL Credit Facilities (2)
 
250,000

 
250,000

 

 

CTPL Term Loan, net of discount (2)
 
398,319

 
400,000

 
397,565

 
400,000

SPL Working Capital Facility (2)
 

 

 

 

 
(1)
The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on September 30, 2015 and December 31, 2014, as applicable.
(2)
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.


16


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

NOTE 8—RELATED PARTY TRANSACTIONS
 
LNG Terminal-Related Agreements

Terminal Use Agreement

SPL obtained approximately 2.0 Bcf/d of regasification capacity under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year, continuing until at least 20 years after SPL delivers its first commercial cargo at the Liquefaction Project.

In connection with this TUA, SPL is required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. We recorded operating and maintenance expense (income) related to this obligation of $(0.7) million and $10.2 million during the three months ended September 30, 2015 and 2014, respectively, and $17.0 million and $25.0 million during the nine months ended September 30, 2015 and 2014, respectively. 

Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments has the right to use SPL’s reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to SPLNG. However, the revenue earned by SPLNG from the capacity payments made under the TUA and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our financial statements. We have guaranteed the obligations of SPL under its TUA and the obligations of Cheniere Investments under the TURA.

In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. We recorded no revenues—affiliate from Cheniere Marketing during the three and nine months ended September 30, 2015 and 2014, respectively, related to the Amended and Restated VCRA.

Cheniere Marketing SPA

Cheniere Marketing has entered into an amended and restated SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

Commissioning Agreement

In May 2015, SPL entered into an agreement with Cheniere Marketing that obligates Cheniere Marketing, in certain circumstances, to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. has control of, and is commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

In May 2015, SPL entered into an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on SPL’s behalf to market and sell pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC.

Services Agreements
As of September 30, 2015 and December 31, 2014, we had $55.0 million and $27.3 million of advances to affiliates, respectively, under the services agreements described below. During the three months ended September 30, 2015 and 2014, we recorded general and administrative expense—affiliate of $25.7 million and $24.5 million, respectively, and operating and maintenance expense—affiliate of $8.1 million and $5.0 million, respectively, under the services agreements described below. During the nine months ended September 30, 2015 and 2014, we recorded general and administrative expense—affiliate of $80.8

17


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

million and $74.6 million, respectively, and operating and maintenance expense—affiliate of $20.4 million and $14.3 million, respectively, under the services agreements described below.

Cheniere Partners Services Agreement

We have entered into a services agreement with Cheniere Terminals, a wholly owned subsidiary of Cheniere, pursuant to which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $2.8 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

SPLNG O&M Agreement

SPLNG has entered into a long-term operation and maintenance agreement (the “SPLNG O&M Agreement”) with Cheniere Investments pursuant to which SPLNG receives all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. SPLNG incurs a fixed monthly fee of $130,000 (indexed for inflation) under the SPLNG O&M Agreement and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between SPLNG and Cheniere Investments at the beginning of each operating year. In addition, SPLNG incurs costs to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments meets its obligations under the SPLNG O&M Agreement with resources provided by a wholly owned subsidiary of Cheniere pursuant to a secondment agreement. All payments received by Cheniere Investments under the SPLNG O&M Agreement are required to be remitted to such subsidiary.
 
SPLNG MSA

SPLNG has entered into a long-term management services agreement (the “SPLNG MSA”) with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters provided for under the SPLNG O&M Agreement. SPLNG incurs a monthly fixed fee of $520,000 (indexed for inflation) under the SPLNG MSA.

SPL O&M Agreement

SPL has entered into an operation and maintenance agreement (the “SPL O&M Agreement”) with Cheniere Investments pursuant to which SPL receives all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on behalf of SPL, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After the Liquefaction Project is operational, the services include all necessary services required to operate and maintain the Liquefaction Project. Before the Liquefaction Project is operational, in addition to reimbursement of operating expenses, SPL is required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Liquefaction Project is operational, SPL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to such Train. Cheniere Investments meets its obligations under the SPL O&M Agreement with resources provided by a wholly owned subsidiary of Cheniere pursuant to a secondment agreement. All payments received by Cheniere Investments under the SPL O&M Agreement are required to be remitted to such subsidiary.
SPL MSA

SPL has entered into a management services agreement (the “SPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the SPL O&M Agreement. The services include, among other services, exercising the day-to-day management of SPL’s affairs and business, managing SPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of SPL’s business and operations, entering into financial derivatives on our behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Under the SPL MSA, SPL pays a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, SPL will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.

18


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)


CTPL O&M Agreement

CTPL has entered into an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses. Cheniere Investments meets its obligations under the CTPL O&M Agreement with resources provided by a wholly owned subsidiary of Cheniere pursuant to a secondment agreement. All payments received by Cheniere Investments under the CTPL O&M Agreement are required to be remitted to such subsidiary.
 
CTPL MSA

CTPL has entered into a management services agreement (the “CTPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the modification and operation of the Creole Trail Pipeline, excluding those matters provided for under the CTPL O&M Agreement. The services include, among other services, exercising the day-to-day management of CTPL’s affairs and business, managing CTPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of CTPL’s business and operations and providing contract administration services for all contracts associated with the pipeline facilities. Under the CTPL MSA, CTPL pays a monthly fee equal to 3.0% of the capital expenditures to enable bi-directional natural gas flow on the Creole Trail Pipeline incurred in the previous month.

LNG Lease Agreement

In September 2011, Cheniere Investments entered into an agreement in the form of a lease (the “LNG Lease Agreement”) with Cheniere Marketing that enables Cheniere Investments to supply the Sabine Pass LNG terminal with LNG to maintain proper LNG inventory levels and temperature. The LNG Lease Agreement also enables Cheniere Investments to hedge the exposure to variability in expected future cash flows of the LNG inventory. Under the terms of the LNG Lease Agreement, Cheniere Marketing funds all activities related to the purchase and hedging of the LNG, and Cheniere Investments reimburses Cheniere Marketing for all costs and assumes full price risk associated with these activities.

As a result of Cheniere Investments assuming full price risk associated with the LNG Lease Agreement, any LNG inventory purchased by Cheniere Marketing under this arrangement is classified as LNG inventory—affiliate on our Consolidated Balance Sheets. This amount is recorded at cost and subject to lower of cost or market (“LCM”) adjustments at the end of each period. LNG inventory—affiliate cost is determined using the average cost method. Recoveries of losses resulting from interim period LCM adjustments are made due to market price recoveries on the same LNG inventory—affiliate in the same fiscal year and are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. Gains or losses on the sale of LNG inventory—affiliate and LCM adjustments are recorded as revenues on our Consolidated Statements of Operations. As of September 30, 2015 and December 31, 2014, we had no LNG inventory—affiliate recorded on our Consolidated Balance Sheets under the LNG Lease Agreement.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements (“CEAs”)
 
In July 2007, SPLNG executed CEAs with various Cameron Parish, Louisiana taxing authorities that allow them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This ten-year initiative represents an aggregate commitment of up to $25.0 million, and SPLNG will make resources available to the Cameron Parish taxing authorities on an accelerated basis in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. In September 2007, SPLNG entered into an agreement with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable under the CEAs in exchange for a similar amount of credits against future TUA payments it would owe SPLNG under its TUA starting in 2019. In June 2010, Cheniere Marketing assigned its TUA to Cheniere Investments and concurrently entered into a variable capacity rights agreement, allowing Cheniere Marketing to utilize Cheniere Investments’ capacity under the TUA after the assignment. In July 2012, Cheniere Investments entered into the Amended and Restated VCRA with Cheniere Marketing in order for Cheniere Investments to utilize during construction of the Liquefaction Project the capacity rights granted under the TURA. Cheniere Marketing will continue to fund the CEAs during the term of the Amended and Restated VCRA and, in exchange, Cheniere Marketing will receive the benefit of any future credits.

19


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)


On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of September 30, 2015 and December 31, 2014, we had $22.1 million and $19.6 million, respectively, of other non-current assets resulting from SPLNG’s ad valorem tax payments and non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.
 
Contracts for Sale and Purchase of Natural Gas and LNG
 
SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal. As a result, SPLNG records the purchases of natural gas and LNG from Cheniere Marketing to be utilized as fuel to operate the Sabine Pass LNG terminal as operating and maintenance expense.

SPLNG recorded operating and maintenance expense of $1.1 million and $0.9 million in the three months ended September 30, 2015 and 2014, respectively, and $3.7 million and $2.1 million in the nine months ended September 30, 2015 and 2014, respectively, for natural gas purchased from Cheniere Marketing under these agreements. SPLNG recorded revenues—affiliate of $4.4 million and $0.3 million in the three months ended September 30, 2015 and 2014, respectively, and $9.8 million and $0.5 million in the nine months ended September 30, 2015 and 2014, respectively, for natural gas sold to Cheniere Marketing under these agreements.

Tug Boat Lease Sharing Agreement

In connection with its tug boat lease, Sabine Pass Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of SPLNG, entered into a tug sharing agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. Tug Services recorded revenues—affiliate of $0.7 million pursuant to this agreement in each of the three months ended September 30, 2015 and 2014, and $2.1 million in each of the nine months ended September 30, 2015 and 2014.

LNG Terminal Export Agreement

In January 2010, SPLNG and Cheniere Marketing entered into an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the three and nine months ended September 30, 2015 and 2014.

State Tax Sharing Agreements

In November 2006, SPLNG entered into a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

In August 2012, SPL entered into a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPL will pay to Cheniere an amount equal to the state and local tax that SPL would be required to pay if SPL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from SPL under this agreement; therefore, Cheniere has not demanded any such payments from SPL. The agreement is effective for tax returns due on or after August 2012.


20


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

In May 2013, CTPL entered into a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CTPL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CTPL will pay to Cheniere an amount equal to the state and local tax that CTPL would be required to pay if CTPL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CTPL under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement is effective for tax returns due on or after May 2013.

NOTE 9—NET INCOME (LOSS) PER COMMON UNIT
 
Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statement of Partners’ Equity. On October 23, 2015, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on November 13, 2015 to unitholders of record as of November 2, 2015 for the period from July 1, 2015 to September 30, 2015.

The two-class method dictates that net income (loss) for a period be reduced by the amount of available cash that will be distributed with respect to that period and that any residual amount representing undistributed net income be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net income for the period had been distributed in accordance with the partnership agreement. Undistributed income is allocated to participating securities based on the distribution waterfall for available cash specified in the partnership agreement. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units and other participating securities on a pro rata basis based on provisions of the partnership agreement. Historical income (loss) attributable to a company that was purchased from an entity under common control is allocated to the predecessor owner in accordance with the terms of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

The Class B units were issued at a discount to the market price of the common units into which they are convertible.  This discount totaling $2,130.0 million represents a beneficial conversion feature and is reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at issuance on our Consolidated Statements of Partners’ Equity.  The beneficial conversion feature is considered a dividend that will be distributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortize the beneficial conversion feature assuming a conversion date of August 2017 for Cheniere Holdings’ and Blackstone’s Class B units although actual conversion may occur prior to or after these assumed dates. We are amortizing using the effective yield method with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ and Blackstone’s Class B units, respectively. The impact of the beneficial conversion feature is also included in earnings per unit for the three and nine months ended September 30, 2015 and 2014.

The following is a schedule by years, based on the capital structure as of September 30, 2015, of the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature (in thousands):
 
Common Units
 
Class B Units
 
Subordinated Units
2015
(232
)
 
781

 
(549
)
2016
(29,565
)
 
99,685

 
(70,120
)
2017
(594,420
)
 
2,004,209

 
(1,409,788
)


21


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)

Under our partnership agreement, the incentive distribution rights (“IDRs”) participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss). We did not allocate earnings or losses to IDR holders for the purpose of the two-class method earnings per unit calculation for any of the periods presented. The following table (in thousands, except per unit data) provides a reconciliation of net income (loss) and the allocation of net loss to the common units, the subordinated units and the general partner for purposes of computing net income (loss) per unit:
 
 
 
 
Limited Partner Units
 
 
 
 
Total
 
Common Units
 
Class B Units
 
Subordinated Units
 
General Partner
Three Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
 
Net loss
 
$
(24,132
)
 
 
 
 
 
 
 
 
Declared distributions
 
24,755

 
24,260

 

 

 
495

Assumed allocation of undistributed net loss
 
$
(48,887
)
 
(14,209
)
 

 
(33,700
)
 
(978
)
Assumed allocation of net income (loss)
 
 
 
$
10,051

 
$

 
$
(33,700
)
 
$
(483
)
 
 
 
 
 
 
 
 
 
 
 
Weighted average units outstanding
 
 
 
57,081

 
145,333

 
135,384

 
 
Net income (loss) per unit
 
 
 
$
0.18

 
$

 
$
(0.25
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
Net loss
 
$
(43,240
)
 
 
 
 
 
 
 
 
Declared distributions
 
24,754

 
24,259

 

 

 
495

Assumed allocation of undistributed net loss
 
$
(67,994
)
 
(19,762
)
 

 
(46,872
)
 
(1,360
)
Assumed allocation of net income (loss)
 
 
 
$
4,497

 
$

 
$
(46,872
)
 
$
(865
)
 
 
 
 
 
 
 
 
 
 
 
Weighted average units outstanding
 
 
 
57,079

 
145,333

 
135,384

 
 
Net income (loss) per unit
 
 
 
$
0.08

 
$

 
$
(0.35
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
 
Net loss
 
$
(262,851
)
 
 
 
 
 
 
 
 
Declared distributions
 
74,266

 
72,781

 

 

 
1,485

Assumed allocation of undistributed net loss
 
$
(337,117
)
 
(97,984
)
 

 
(232,389
)
 
(6,744
)
Assumed allocation of net loss
 
 
 
$
(25,203
)
 
$

 
$
(232,389
)
 
$
(5,259
)
 
 
 
 
 
 
 
 
 
 
 
Weighted average units outstanding
 
 
 
57,081

 
145,333

 
135,384

 
 
Net loss per unit
 
 
 
$
(0.44
)
 
$

 
$
(1.72
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
Net loss
 
$
(339,197
)
 
 
 
 
 
 
 
 
Declared distributions
 
74,261

 
72,776

 

 

 
1,485

Assumed allocation of undistributed net loss
 
$
(413,458
)
 
(120,168
)
 

 
(285,021
)
 
(8,269
)
Assumed allocation of net loss
 
 
 
$
(47,392
)
 
$

 
$
(285,021
)
 
$
(6,784
)
 
 
 
 
 
 
 
 
 
 
 
Weighted average units outstanding
 
 
 
57,079

 
145,333

 
135,384

 
 
Net loss per unit
 
 
 
$
(0.83
)
 
$

 
$
(2.11
)
 
 

NOTE 10—SUPPLEMENTAL CASH FLOW INFORMATION
 
The following table (in thousands) provides supplemental disclosure of cash flow information:
 
Nine Months Ended September 30,
 
2015
 
2014
Cash paid during the year for interest, net of amounts capitalized and deferred
$
80,150

 
$
47,152

Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)
362,435

 
280,290

Non-cash conveyance of assets
13,169

 


22


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)


NOTE 11—RECENT ACCOUNTING STANDARDS

In May 2014, the Financial Accounting Standards Board (the “FASB”) amended its guidance on revenue recognition. The core principle of this amendment is that an entity should 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. This guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Earlier adoption is permitted as of annual reporting periods beginning after December 15, 2016. This guidance may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

In August 2014, the FASB issued authoritative guidance that requires an entity’s management to evaluate, for each reporting period, whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued. Additional disclosures are required if management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. This guidance is effective for annual reporting periods ending after December 15, 2016, and for annual periods and interim periods thereafter, with earlier adoption permitted. The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.

In February 2015, the FASB amended its guidance on consolidation analysis. This amendment primarily affects asset managers and reporting entities involved with limited partnerships or similar entities, but the analysis is relevant in the evaluation of any reporting organization’s requirement to consolidate a legal entity. This guidance changes (1) the identification of variable interests, (2) the variable interest entity characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This guidance is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with earlier adoption permitted. This guidance may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.

In April 2015, the FASB issued authoritative guidance that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. In August 2015, the FASB further issued guidance clarifying the SEC staff’s position on presentation and subsequent measurement of debt issuance costs incurred in connection with line of credit arrangements. This guidance is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with earlier adoption permitted. This guidance must be adopted retrospectively to each prior reporting period presented and disclosures will be required for a change in accounting principles. We are currently evaluating the impact of the provisions of this guidance on our Consolidated Balance Sheets.

In April 2015, the FASB issued authoritative guidance that requires a master limited partnership to allocate net income (losses) of a transferred business entirely to the general partner when computing earnings per unit for periods before the dropdown transaction occurred. This guidance also requires a master limited partnership to disclose the effects of the dropdown transaction on net income (losses) per unit for the periods before and after the dropdown transaction occurred. This guidance is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with earlier adoption permitted. This guidance must be adopted retrospectively to each prior reporting period presented. The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.

In July 2015, the FASB issued revised guidance related to the measurement of inventory. Inventory would be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption permitted. This guidance should be adopted prospectively. We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.


23


ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Information Regarding Forward-Looking Statements
This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements.” All statements, other than statements of historical facts, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:
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 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 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 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, 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, 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-historical or future information.
All of these types of statements, other than statements of historical fact, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors described in this quarterly report and in the other reports and other information that we file with the SEC. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.


24


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 under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

Introduction
 
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis include the following subjects: 
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
 
Overview of Business
 
We are a publicly traded Delaware limited partnership formed by Cheniere (NYSE MKT: LNG). Through our wholly owned subsidiary, SPLNG, we own and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine Pass deepwater shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We are developing and constructing natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through our wholly owned subsidiary, SPL. We plan to construct up to six Trains, which are in various stages of development. Each Train is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG. We also own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through our wholly owned subsidiary, CTPL.

Overview of Significant Events

Our significant accomplishments since January 1, 2015 and through the filing date of this Form 10-Q include the following:  
SPL issued an aggregate principal amount of $2.0 billion of 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes”). Net proceeds from the offering will be used to pay a portion of the capital costs associated with the construction of the first four Trains of the Liquefaction Project.
We received authorization from the FERC to site, construct and operate Trains 5 and 6 of the Liquefaction Project.
SPL received authorization from the DOE to export up to a combined total of the equivalent of 503.3 Bcf/yr of domestically produced LNG by vessel from Trains 5 and 6 of the Liquefaction Project to non-FTA countries for a 20-year term.
SPL entered into a lump sum turnkey contract for the engineering, procurement and construction of Train 5 of the Liquefaction Project (the “EPC Contract (Train 5)”).
SPL entered into four credit facilities (collectively, the “2015 SPL Credit Facilities”) totaling $4.6 billion, which replaced its existing credit facilities. The 2015 SPL Credit Facilities will be used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project.
SPL issued a notice to proceed to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) under the EPC Contract (Train 5).

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SPL entered into a $1.2 billion Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “SPL Working Capital Facility”), which replaced the existing Senior Letter of Credit and Reimbursement Agreement that was entered into in April 2014 (the “SPL LC Agreement”). The SPL Working Capital Facility will be used primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project.

Liquidity and Capital Resources
 
Cash and Cash Equivalents
 
As of September 30, 2015, we had $170.4 million of cash and cash equivalents and $467.6 million of current and non-current restricted cash (which included current and non-current restricted cash available to us, SPL and SPLNG) designated for the following purposes: $327.2 million for the Liquefaction Project; $11.3 million for CTPL; and $129.1 million for interest payments related to the SPLNG Senior Notes described below.

Sabine Pass LNG Terminal 

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal.  Each of Total Gas & Power North America, Inc. (“Total”) and Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, continuing until at least 20 years after SPL delivers its first commercial cargo at the Liquefaction Project.

Under each of these TUAs, SPLNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.

Liquefaction Facilities

The Liquefaction Project is being developed and constructed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We commenced construction of Trains 1 and 2 and the related new facilities needed to treat, liquefy, store and export natural gas in August 2012. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. In April 2015, we received authorization from the FERC to site, construct and operate Trains 5 and 6. In June 2015, we commenced construction of Train 5 and the related facilities.
 
The DOE has authorized the export of up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr) of domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries for a 30-year term and to non-FTA countries for a 20-year term. The DOE further issued an order authorizing SPL to export up to the equivalent of approximately 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries for a 25-year period. SPL’s application for authorization to export that same 203 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to non-FTA countries is currently pending at the DOE. Additionally, the DOE issued orders authorizing SPL to export up to a combined total of 503.3 Bcf/yr of domestically produced LNG from the Sabine Pass LNG terminal to FTA countries and non-FTA countries for a 20-year term. The Sierra Club has requested a rehearing of the non-FTA order pertaining to the 503.3 Bcf/yr, and the DOE has not yet ruled on this request. In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from 5 to 10 years from the date the order was issued.

As of September 30, 2015, the overall project completion percentage for Trains 1 and 2 of the Liquefaction Project was approximately 95.2%, which is ahead of the contractual schedule. As of September 30, 2015, the overall project completion percentage for Trains 3 and 4 of the Liquefaction Project was approximately 73.6%, which is also ahead of the contractual schedule.

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Based on our current construction schedule, we anticipate that Train 1 will produce LNG as early as late 2015, and Trains 2 through 5 are expected to commence operations on a staggered basis thereafter.
    
Customers

SPL has entered into six fixed price, 20-year SPAs with third parties that in the aggregate equate to approximately 19.75 mtpa of LNG that commence with the date of first commercial delivery for Trains 1 through 5, which are fully permitted. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee plus 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to cargoes that are not delivered. A portion of the fixed fee will be subject to annual adjustment for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA commences upon the start of operations of the specified Train.

In aggregate, the fixed fee portion to be paid by these customers is approximately $2.9 billion annually for Trains 1 through 5, with the applicable fixed fees starting from the commencement of commercial operations of the applicable Train. These fixed fees equal approximately $411 million, $564 million, $650 million, $648 million and $588 million for each of Trains 1 through 5, respectively.

In addition, Cheniere Marketing has entered into an amended and restated SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers at a price of 115% of Henry Hub plus $3.00 per MMBtu of LNG.

Natural Gas Transportation and Supply

For SPL’s natural gas feedstock transportation requirements, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has also entered into enabling agreements and long-term natural gas purchase agreements with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of September 30, 2015, SPL has secured up to approximately 2,156.6 million MMBtu of natural gas feedstock through long-term natural gas purchase agreements.

Construction

SPL entered into lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Trains 1 through 5, under which Bechtel charges a lump sum for all work performed and generally bears project cost risk unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract prices of the EPC contract for Trains 1 and 2, EPC contract for Trains 3 and 4 and EPC Contract (Train 5) are approximately $4.1 billion, $3.8 billion and $2.9 billion, respectively, reflecting amounts incurred under change orders through September 30, 2015. Total expected capital costs for Trains 1 through 5 are estimated to be between $12.5 billion and $13.5 billion before financing costs and between $17.0 billion and $18.0 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

Pipeline Facilities

During the third quarter of 2015, CTPL completed construction of certain modifications to allow the Creole Trail Pipeline to be able to transport natural gas to the Sabine Pass LNG terminal.

Final Investment Decision on Train 6

We will contemplate making a final investment decision to commence construction of Train 6 of the Liquefaction Project based upon, among other things, entering into an EPC contract, entering into acceptable commercial arrangements and obtaining adequate financing to construct the Train.

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to Trains 1 through 5 of the Liquefaction Project will be financed through one or more of the following: borrowings, equity contributions from us and cash flows under the SPAs.

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We believe that with the net proceeds of borrowings, unfunded commitments under the 2015 SPL Credit Facilities, available commitments under the SPL Working Capital Facility and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 5 of the Liquefaction Project and to meet our currently anticipated capital, operating and debt service requirements. We currently project that we will generate cash flow from the Liquefaction Project by early 2016.
    
Senior Secured Notes

As of September 30, 2015, our subsidiaries had seven series of senior secured notes outstanding (collectively, the “Senior Notes”):
$1.7 billion of 7.50% Senior Secured Notes due 2016 issued by SPLNG (the “2016 SPLNG Senior Notes”);
$0.4 billion of 6.50% Senior Secured Notes due 2020 issued by SPLNG (the “2020 SPLNG Senior Notes” and collectively with the 2016 SPLNG Senior Notes, the “SPLNG Senior Notes”);
$2.0 billion of 5.625% Senior Secured Notes due 2021 issued by SPL (the “2021 SPL Senior Notes”);
$1.0 billion of 6.25% Senior Secured Notes due 2022 issued by SPL (the “2022 SPL Senior Notes”);
$1.5 billion of 5.625% Senior Secured Notes due 2023 issued by SPL (the “2023 SPL Senior Notes”);
$2.0 billion of 5.75% Senior Secured Notes due 2024 issued by SPL (the “2024 SPL Senior Notes” and collectively with the 2021 SPL Senior Notes, the 2022 SPL Senior Notes, the 2023 SPL Senior Notes and the 2025 SPL Senior Notes, the “SPL Senior Notes”); and
$2.0 billion of the 2025 SPL Senior Notes.

Interest on the Senior Notes is payable semi-annually in arrears. Subject to permitted liens, the SPLNG Senior Notes are secured on a pari passu first-priority basis by a security interest in all of SPLNG’s equity interests and substantially all of SPLNG’s operating assets. The SPL Senior Notes are secured on a first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets.

SPLNG may redeem all or part of its 2016 SPLNG Senior Notes at any time at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:
1.0% of the principal amount of the 2016 SPLNG Senior Notes; or
the excess of: (1) the present value at such redemption date of (a) the redemption price of the 2016 SPLNG Senior Notes plus (b) all required interest payments due on the 2016 SPLNG Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the treasury rate as of such redemption date plus 50 basis points; over (2) the principal amount of the 2016 SPLNG Senior Notes, if greater.

SPLNG may redeem all or part of the 2020 SPLNG Senior Notes at any time on or after November 1, 2016 at fixed redemption prices specified in the indenture governing the 2020 SPLNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPLNG may also, at its option, redeem all or part of the 2020 SPLNG Senior Notes at any time prior to November 1, 2016, at a “make-whole” price set forth in the indenture governing the 2020 SPLNG Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, SPLNG may redeem up to 35% of the aggregate principal amount of the 2020 SPLNG Senior Notes at a redemption price of 106.5% of the principal amount of the 2020 SPLNG Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date, in an amount not to exceed the net proceeds of one or more completed equity offerings as long as SPLNG redeems the 2020 SPLNG Senior Notes within 180 days of the closing date for such equity offering and at least 65% of the aggregate principal amount of the 2020 SPLNG Senior Notes originally issued remains outstanding after the redemption.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes, SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price set forth in the common indenture governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes, redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

Under the indentures governing the SPLNG Senior Notes (the “SPLNG Indentures”), except for permitted tax distributions, SPLNG may not make distributions until, among other requirements, deposits are made into debt service reserve accounts and a fixed charge coverage ratio test of 2:1 is satisfied. Under the common indenture governing the SPL Senior Notes, SPL may not

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make any distributions until, among other requirements, substantial completion of Trains 1 and 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25:1.00 is satisfied. During the nine months ended September 30, 2015 and 2014, SPLNG made distributions of $267.9 million and $237.7 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

The SPL Senior Notes are governed by a common indenture with restrictive covenants. SPL may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of SPL, including the SPL Senior Notes, the 2015 SPL Credit Facilities and the SPL Working Capital Facility.
    
2015 SPL Credit Facilities
In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion. The 2015 SPL Credit Facilities are being used to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project. Borrowings under the 2015 SPL Credit Facilities may be refinanced, in whole or in part, at any time without premium or penalty; however, interest rate hedging and interest rate breakage costs may be incurred. As of September 30, 2015, SPL had $4.3 billion of available commitments and $250.0 million of outstanding borrowings under the 2015 SPL Credit Facilities.

Loans under the 2015 SPL Credit Facilities accrue interest at a variable rate per annum equal to, at SPL’s election, LIBOR or the base rate plus the applicable margin. The applicable margin for LIBOR loans ranges from 1.30% to 1.75%, depending on the applicable 2015 SPL Credit Facility, and the applicable margin for base rate loans is 1.75%. Interest on LIBOR loans is due and payable at the end of each LIBOR period and interest on base rate loans is due and payable at the end of each quarter. In addition, SPL is required to pay insurance/guarantee premiums of 0.45% per annum on any drawn amounts under the covered tranches of the 2015 SPL Credit Facilities. The 2015 SPL Credit Facilities also require SPL to pay a quarterly commitment fee calculated at a rate per annum equal to either: (1) 40% of the applicable margin, multiplied by the average daily amount of the undrawn commitment, or (2) 0.70% of the undrawn commitment, depending on the applicable 2015 SPL Credit Facility. The principal of the loans made under the 2015 SPL Credit Facilities must be repaid in quarterly installments, commencing with the earlier of June 30, 2020 and the last day of the first full calendar quarter after the completion date of Trains 1 through 5 of the Liquefaction Project. Scheduled repayments are based upon an 18-year amortization profile, with the remaining balance due upon the maturity of the 2015 SPL Credit Facilities.

The obligations of SPL under the 2015 SPL Credit Facilities are secured by substantially all of the assets of SPL as well as all of the membership interests in SPL on a pari passu basis with the SPL Senior Notes and SPL Working Capital Facility.

Under the terms of the 2015 SPL Credit Facilities