Document


 
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, 2016
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to            
colorlogoonwhitecmyka12.gif
CHENIERE ENERGY, INC.
(Exact name of registrant as specified in its charter)
 
 
 
 
 
Delaware
001-16383
95-4352386
(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 27, 2016, the issuer had 234,985,131 shares of Common Stock outstanding.

 



CHENIERE ENERGY, INC.
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
 
billion cubic feet
Bcf/d
 
billion cubic feet per day
Bcf/yr
 
billion cubic feet per year
Bcfe
 
billion cubic feet equivalent
DOE
 
U.S. Department of Energy
EPC
 
engineering, procurement and construction
FERC
 
Federal Energy Regulatory Commission
FTA countries
 
countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP
 
generally accepted accounting principles in the United States
Henry Hub
 
the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR
 
London Interbank Offered Rate
LNG
 
liquefied natural gas, a product of natural gas 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 with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC
 
Securities and Exchange Commission
SPA
 
LNG sale and purchase agreement
Train
 
an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA
 
terminal use agreement

1


Abbreviated Organizational Structure

The following diagram depicts our abbreviated organizational structure as of September 30, 2016, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:
ceia14.jpg
Unless the context requires otherwise, references to “Cheniere,” the “Company,” “we,” “us” and “our” refer to Cheniere Energy, Inc. (NYSE MKT: LNG) and its consolidated subsidiaries, including our publicly traded subsidiaries, Cheniere Partners (NYSE MKT: CQP) and Cheniere Holdings (NYSE MKT: CQH).
Unless the context requires otherwise, references to the “CCH Group” refer to CCH HoldCo II, CCH HoldCo I, CCH, CCL and CCP, collectively.

2


PART I.
FINANCIAL INFORMATION
ITEM 1.
CONSOLIDATED FINANCIAL STATEMENTS
CHENIERE ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)





 
September 30,
 
December 31,
 
2016
 
2015
ASSETS
(unaudited)
 
 
Current assets
 
 
 
Cash and cash equivalents
$
990,132

 
$
1,201,112

Restricted cash
827,545

 
503,397

Accounts and other receivables
154,167

 
5,749

Inventory
63,853

 
18,125

Other current assets
69,030

 
54,203

Total current assets
2,104,727

 
1,782,586

 
 
 
 
Non-current restricted cash
31,128

 
31,722

Property, plant and equipment, net
19,891,666

 
16,193,907

Debt issuance costs, net
294,059

 
378,677

Non-current derivative assets
11,247

 
30,887

Goodwill
76,819

 
76,819

Other non-current assets
279,434

 
314,455

Total assets
$
22,689,080

 
$
18,809,053

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

Current liabilities
 

 
 

Accounts payable
$
38,569

 
$
22,820

Accrued liabilities
699,996

 
427,199

Current debt, net
1,781,511

 
1,673,379

Deferred revenue
26,709

 
26,669

Derivative liabilities
61,829

 
35,201

Other current liabilities
264

 

Total current liabilities
2,608,878

 
2,185,268

 
 
 
 
Long-term debt, net
19,033,513

 
14,920,427

Non-current deferred revenue
6,500

 
9,500

Non-current derivative liabilities
268,601

 
79,387

Other non-current liabilities
65,849

 
53,068

 
 
 
 
Commitments and contingencies (see Note 16)


 


 
 
 
 
Stockholders’ equity
 

 
 

Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued

 

Common stock, $0.003 par value
 
 
 

Authorized: 480.0 million shares at September 30, 2016 and December 31, 2015
 
 
 
Issued and outstanding: 235.1 million shares and 235.6 million shares at September 30, 2016 and December 31, 2015, respectively
705

 
708

Treasury stock: 12.1 million shares and 11.6 million shares at September 30, 2016 and December 31, 2015, respectively, at cost
(372,531
)
 
(353,927
)
Additional paid-in-capital
3,112,753

 
3,075,317

Accumulated deficit
(4,343,646
)
 
(3,623,948
)
Total stockholders’ deficit
(1,602,719
)
 
(901,850
)
Non-controlling interest
2,308,458

 
2,463,253

Total equity
705,739

 
1,561,403

Total liabilities and equity
$
22,689,080

 
$
18,809,053


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

3



CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data) 
(unaudited)
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2016
 
2015
 
2016
 
2015
Revenues
 
 
 
 
 
 
 
Regasification revenues
$
66,970

 
$
66,597

 
$
198,143

 
$
199,888

LNG revenues (losses)
398,554

 
(1,557
)
 
511,993

 
(1,601
)
Other revenues
149

 
1,019

 
1,445

 
4,166

Total revenues
465,673

 
66,059

 
711,581

 
202,453

 
 
 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
 
 
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)
252,343

 
(24,214
)
 
352,559

 
(22,077
)
Operating and maintenance expense
61,610

 
17,963

 
143,489

 
71,396

Development expense
1,546

 
4,935

 
4,709

 
37,640

Selling, general and administrative expense
59,418

 
97,332

 
196,999

 
263,205

Depreciation and amortization expense
49,212

 
21,638

 
106,082

 
59,561

Restructuring expense
26,241

 

 
49,196

 

Impairment expense

 
396

 
10,095

 
572

Other
27

 
83

 
189

 
348

Total operating costs and expenses
450,397

 
118,133

 
863,318

 
410,645

 
 
 
 
 
 
 
 
Income (loss) from operations
15,276

 
(52,074
)
 
(151,737
)
 
(208,192
)
 
 
 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
(148,053
)
 
(93,566
)
 
(330,357
)
 
(238,664
)
Loss on early extinguishment of debt
(25,765
)
 

 
(82,537
)
 
(96,273
)
Derivative gain (loss), net
29,327

 
(161,482
)
 
(242,228
)
 
(242,123
)
Other income (expense)
437

 
(39
)
 
(5,564
)
 
616

Total other expense
(144,054
)
 
(255,087
)
 
(660,686
)
 
(576,444
)
 
 
 
 
 
 
 
 
Loss before income taxes and non-controlling interest
(128,778
)

(307,161
)

(812,423
)

(784,636
)
Income tax benefit (provision)
(1,638
)

69


(1,911
)

(102
)
Net loss
(130,416
)

(307,092
)

(814,334
)

(784,738
)
Less: net loss attributable to non-controlling interest
(29,974
)

(9,284
)

(94,636
)

(100,726
)
Net loss attributable to common stockholders
$
(100,442
)

$
(297,808
)

$
(719,698
)

$
(684,012
)












Net loss per share attributable to common stockholders—basic and diluted
$
(0.44
)

$
(1.31
)

$
(3.15
)

$
(3.02
)
 











Weighted average number of common shares outstanding—basic and diluted
228,924


227,126


228,463


226,648

 




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

4



CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(in thousands)
(unaudited)
 
Total Stockholders’ Equity
 
 
 
 
Common Stock
 
Treasury Stock
 
Additional Paid-in Capital
 
Accumulated Deficit
 
Non-controlling Interest
 
Total
Equity
 
Shares
 
Par Value Amount
 
Shares
 
Amount
 
 
 
 
Balance at December 31, 2015
235,639

 
$
708

 
11,649

 
$
(353,927
)
 
$
3,075,317

 
$
(3,623,948
)
 
$
2,463,253

 
$
1,561,403

Exercise of stock options
2

 

 

 

 
50

 

 

 
50

Issuances of restricted stock
273

 
1

 

 

 
(1
)
 

 

 

Forfeitures of restricted stock
(377
)
 
(2
)
 
10

 

 
2

 

 

 

Share-based compensation

 

 

 

 
36,526

 

 

 
36,526

Shares repurchased related to share-based compensation
(464
)
 
(2
)
 
464

 
(18,604
)
 
2

 

 

 
(18,604
)
Loss attributable to non-controlling interest

 

 

 

 

 

 
(94,636
)
 
(94,636
)
Equity portion of convertible notes, net

 

 

 

 
857

 

 

 
857

Distributions to non-controlling interest

 

 

 

 

 

 
(60,159
)
 
(60,159
)
Net loss

 

 

 

 

 
(719,698
)
 

 
(719,698
)
Balance at September 30, 2016
235,073

 
$
705

 
12,123

 
$
(372,531
)
 
$
3,112,753

 
$
(4,343,646
)
 
$
2,308,458

 
$
705,739


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

5



CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
 
Nine Months Ended September 30,
 
2016
 
2015
Cash flows from operating activities
 
 
 
Net loss
$
(814,334
)
 
$
(784,738
)
Adjustments to reconcile net loss to net cash used in operating activities:
 
 
 
Non-cash LNG inventory write-downs

 
17,826

Depreciation and amortization expense
106,082

 
59,561

Share-based compensation
85,128

 
92,627

Amortization of debt issuance costs and discount
38,826

 
28,552

Loss on early extinguishment of debt
82,537

 
96,273

Total losses on derivatives, net
269,399

 
208,769

Net cash used for settlement of derivative instruments
(34,567
)
 
(94,170
)
Impairment expense
10,095

 
572

Other
9,803

 
834

Changes in restricted cash for certain operating activities
119,831

 
92,589

Changes in operating assets and liabilities:
 
 
 
Accounts and other receivables
(128,042
)
 
(2,226
)
Inventory
(28,051
)
 
(25,966
)
Accounts payable and accrued liabilities
39,599

 
16,671

Deferred revenue
(2,960
)
 
(3,003
)
Other, net
47,627

 
21,252

Net cash used in operating activities
(199,027
)
 
(274,577
)
 
 
 
 
Cash flows from investing activities
 
 
 
Property, plant and equipment, net
(3,449,161
)
 
(5,747,596
)
Use of restricted cash for the acquisition of property, plant and equipment
3,488,263

 
5,330,526

Other
(51,308
)
 
(111,518
)
Net cash used in investing activities
(12,206
)
 
(528,588
)
 
 
 
 
Cash flows from financing activities
 
 
 
Proceeds from issuances of debt
8,308,306

 
6,178,000

Repayments of debt
(4,180,660
)
 

Debt issuance and deferred financing costs
(116,715
)
 
(519,699
)
Investment in restricted cash
(3,931,648
)
 
(5,161,701
)
Distributions and dividends to non-controlling interest
(60,159
)
 
(60,154
)
Proceeds from exercise of stock options
50

 
2,279

Payments related to tax withholdings for share-based compensation
(18,604
)
 
(44,305
)
Other
(317
)
 
1,424

Net cash provided by financing activities
253

 
395,844

 
 
 
 
Net decrease in cash and cash equivalents
(210,980
)
 
(407,321
)
Cash and cash equivalents—beginning of period
1,201,112

 
1,747,583

Cash and cash equivalents—end of period
$
990,132

 
$
1,340,262



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

6


  
CHENIERE ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)


NOTE 1—BASIS OF PRESENTATION

The accompanying unaudited Consolidated Financial Statements of Cheniere 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, operating results or cash flows.

Directly and through our subsidiary, Cheniere Partners, we are developing, constructing and operating liquefaction projects near Corpus Christi, Texas (the “CCL Project”) and at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana (the “SPL Project”), respectively. In 2016, we started production at the SPL Project. As a result, we introduced a new line item entitled “cost of sales” and modified the components of activity included in “operating and maintenance expense” on our Consolidated Statements of Operations. To conform to the new presentation, reclassifications were made to the prior periods. Cost of sales includes costs incurred directly for the production and delivery of LNG from the SPL Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the SPL Project, vessel chartering costs and other costs related to converting natural gas into LNG, all to the extent not utilized for the commissioning process. These costs were reclassified from operating and maintenance expense. Also included in cost of sales are purchase and delivery costs of our LNG and natural gas marketing business incurred by Cheniere Marketing. Operating and maintenance expense now primarily includes costs associated with operating and maintaining the SPL Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs.

Additionally, we distinguished and reclassified our historical “LNG terminal revenues” line item into “regasification revenues” and “LNG revenues.” Regasification revenues include LNG regasification capacity reservation fees that are received pursuant to our TUAs and tug services fees that are received by Sabine Pass Tug Services, LLC, a wholly owned subsidiary of SPLNG. Substantially all of our regasification revenues, which are generated by our LNG terminal segment, are received from our two long-term TUA customers. LNG revenues include fees that are received pursuant to our SPAs and related LNG marketing activities. During the three and nine months ended September 30, 2016, we received 44% and 50%, respectively, of our net LNG revenues from one SPA customer, which were generated by our LNG terminal segment.

Results of operations for the three and nine months ended September 30, 2016 are not necessarily indicative of the operating results that will be realized for the year ending December 31, 2016.

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, 2015.


7


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

NOTE 2—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. As of September 30, 2016 and December 31, 2015, restricted cash consisted of the following (in thousands):
 
 
September 30,
 
December 31,
 
 
2016
 
2015
Current restricted cash
 
 
 
 
SPLNG debt service and interest payment
 
$
115,490

 
$
77,415

SPL Project
 
325,630

 
189,260

CTPL construction and interest payment
 

 
7,882

CQP and cash held by guarantor subsidiaries
 
127,429

 

CCL Project
 
192,812

 
46,770

Cash held by our subsidiaries restricted to Cheniere
 
12,930

 
147,138

Other
 
53,254

 
34,932

Total current restricted cash
 
$
827,545

 
$
503,397

 
 
 
 
 
Non-current restricted cash
 
 
 
 
SPLNG debt service
 
$
13,650

 
$
13,650

Other
 
17,478

 
18,072

Total non-current restricted cash
 
$
31,128

 
$
31,722


Under the indentures governing the senior notes issued by SPLNG (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. During the nine months ended September 30, 2016 and 2015, SPLNG made distributions of $230.4 million and $267.9 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

In February 2016, Cheniere Partners entered into a $2.8 billion credit facility (the “2016 CQP Credit Facilities”). Cheniere Partners, and Cheniere Investments and CTPL as Cheniere Partners’ guarantor subsidiaries, are subject to limitations on the use of cash under the terms of the 2016 CQP Credit Facilities and the related depositary agreement governing the extension of credit to Cheniere Partners. Specifically, Cheniere Partners, Cheniere Investments and CTPL may only withdraw funds from collateral accounts held at a designated depositary bank on a monthly basis and for specific purposes, including for the payment of operating expenses. In addition, distributions and capital expenditures may only be made quarterly and are subject to certain restrictions.

NOTE 3—ACCOUNTS AND OTHER RECEIVABLES

As of September 30, 2016 and December 31, 2015, accounts and other receivables consisted of the following (in thousands):
 
 
September 30,
 
December 31,
 
 
2016
 
2015
SPL trade receivable
 
$
38,432

 
$

Cheniere Marketing trade receivable
 
100,555

 

Interest receivable
 
234

 
95

Other accounts receivable
 
14,946

 
5,654

Total accounts and other receivables
 
$
154,167

 
$
5,749

Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of SPL’s debt holders, SPL is required to deposit all cash received into reserve accounts controlled by the collateral trustee.  The usage or withdrawal of such cash is restricted to the payment of liabilities related to the SPL Project and other restricted payments.


8


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

NOTE 4—INVENTORY

As of September 30, 2016 and December 31, 2015, inventory consisted of the following (in thousands):
 
 
September 30,
 
December 31,
 
 
2016
 
2015
Natural gas
 
$
4,181

 
$
5,724

LNG
 
29,111

 
5,148

Materials and other
 
30,561

 
7,253

Total inventory
 
$
63,853

 
$
18,125


NOTE 5—PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment consists of LNG terminal costs and fixed assets and other, as follows (in thousands):
 
 
September 30,
 
December 31,
 
 
2016
 
2015
LNG terminal costs
 
 
 
 
LNG terminal
 
$
7,976,737

 
$
2,487,759

LNG terminal construction-in-process
 
12,176,899

 
13,875,204

LNG site and related costs, net
 
38,752

 
33,512

Accumulated depreciation
 
(498,934
)
 
(413,545
)
Total LNG terminal costs, net
 
19,693,454

 
15,982,930

Fixed assets and other
 
 

 
 

Computer and office equipment
 
13,241

 
12,153

Furniture and fixtures
 
17,393

 
17,101

Computer software
 
78,942

 
69,340

Leasehold improvements
 
46,351

 
40,136

Land
 
60,582

 
60,612

Other
 
36,369

 
49,376

Accumulated depreciation
 
(54,666
)
 
(37,741
)
Total fixed assets and other, net
 
198,212

 
210,977

Property, plant and equipment, net
 
$
19,891,666

 
$
16,193,907


During the three and nine months ended September 30, 2016, we realized offsets to LNG terminal costs of $68.3 million and $214.3 million, respectively, that were related to the sale of commissioning cargoes because these amounts were earned prior to the start of commercial operations, during the testing phase for the construction of Trains 1 and 2 of the SPL Project.

NOTE 6—DERIVATIVE INSTRUMENTS
 
We have entered into the following derivative instruments that are reported at fair value:
interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under certain of our credit facilities (“Interest Rate Derivatives”);
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 supply contracts for the commissioning and operation of the SPL Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives”, and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”);
financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (“LNG Trading Derivatives”); and
foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with operations in countries outside of the United States (“FX Derivatives”).

9


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

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.

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, 2016 and December 31, 2015, 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, 2016
 
December 31, 2015
 
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
SPL Interest Rate Derivatives liability
$

 
$
(15,948
)
 
$

 
$
(15,948
)
 
$

 
$
(8,740
)
 
$

 
$
(8,740
)
CQP Interest Rate Derivatives liability

 
(12,166
)
 

 
(12,166
)
 

 

 

 

CCH Interest Rate Derivatives liability

 
(297,539
)
 

 
(297,539
)
 

 
(104,999
)
 

 
(104,999
)
Liquefaction Supply Derivatives asset (liability)
(105
)
 
(275
)
 
12,480

 
12,100

 

 
(25
)
 
32,492

 
32,467

LNG Trading Derivatives asset (liability)
284

 
(632
)
 

 
(348
)
 

 
1,053

 

 
1,053

Natural Gas Derivatives liability

 

 

 

 

 
(66
)
 

 
(66
)
FX Derivatives liability

 
(1,193
)
 

 
(1,193
)
 

 

 

 


We value our 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 estimated fair values of our economic hedges related to the LNG Trading Derivatives and 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 estimate the fair values of our FX Derivatives with a market approach using observable FX rates and other relevant data.

We acquired $0.8 million of certain LNG Trading Derivatives during the first quarter of 2016, which we transferred into Level 1 during the second quarter of 2016. We transferred these LNG Trading Derivatives to Level 1 due to the use of unadjusted quoted exchange prices to calculate the fair value of these LNG Trading derivative positions, which were previously Level 2 as the fair value was calculated using adjusted quoted exchange prices. There were no transfers in and out of Level 2 during the three months ended September 30, 2016.

The fair value of substantially all of our Physical 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 our Physical Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of our Physical 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 Physical 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 include conditions precedent to the respective long-term natural gas supply contracts. As of September 30, 2016 and December 31, 2015, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow. Accordingly, our internal fair value models are based on market prices that equate 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 our Physical 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

10


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

infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts as of the reporting date.

As all of our 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 our Level 3 Physical Liquefaction Supply Derivatives as of September 30, 2016:
 
 
Net Fair Value Asset
(in thousands)
 
Valuation Technique
 
Significant Unobservable Input
 
Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives
 
$12,480
 
Income Approach
 
Basis Spread
 
$(0.35) - $(0.03)

The following table (in thousands) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and nine months ended September 30, 2016 and 2015:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
2016
 
2015
Balance, beginning of period
 
$
22,434

 
$
440

 
$
32,492

 
$
342

Realized and mark-to-market losses:
 
 
 
 
 
 
 
 
Included in cost of sales (1)
 
(10,567
)
 
32,177

 
(20,482
)
 
32,204

Purchases and settlements:
 
 
 
 
 
 
 
 
Purchases
 
968

 

 
968

 

Settlements (1)
 
(308
)
 
(71
)
 
(741
)
 

Transfers out of Level 3 (2)
 
(47
)
 

 
243

 

Balance, end of period
 
$
12,480

 
$
32,546

 
$
12,480

 
$
32,546

Change in unrealized gains relating to instruments still held at end of period
 
$
(10,567
)
 
$

 
$
(19,763
)
 
$

 
    
(1)
Does not include the decrease in fair value of $0.7 million related to the realized gains capitalized during the nine months ended September 30, 2016.
(2)
Transferred to Level 2 as a result of observable market for the underlying natural gas supply contracts.
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 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.  

Interest Rate Derivatives

SPL Interest Rate Derivatives

SPL has entered into interest rate swaps (“SPL Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the credit facilities it entered into in June 2015 (the “2015 SPL Credit Facilities”). The SPL 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 the SPL Interest Rate Derivatives and 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 previous credit facilities.
 
CQP Interest Rate Derivatives

In March 2016, Cheniere Partners entered into interest rate swaps (“CQP Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the 2016 CQP Credit Facilities. The CQP Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2016 CQP Credit Facilities.

11


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


CCH Interest Rate Derivatives

CCH has entered into interest rate swaps (“CCH Interest Rate Derivatives”) to protect against volatility of future cash flows and hedge a portion of the variable interest payments on its credit facility (the “2015 CCH Credit Facility”). The CCH Interest Rate Derivatives hedge a portion of the expected outstanding borrowings over the term of the 2015 CCH Credit Facility. The CCH Interest Rate Derivatives have a seven-year term and were contingent upon reaching a final investment decision with respect to the CCL Project, which was reached in May 2015. Upon meeting the contingency related to the CCH Interest Rate Derivatives in May 2015, we paid $50.1 million related to contingency and syndication premiums, which is included in derivative gain (loss), net on our Consolidated Statements of Operations.

As of September 30, 2016, we 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
SPL Interest Rate Derivatives
 
$20.0 million
 
$628.8 million
 
August 14, 2012
 
July 31, 2019
 
1.98%
 
One-month LIBOR
CQP Interest Rate Derivatives
 
$225.0 million
 
$1.3 billion
 
March 22, 2016
 
February 29, 2020
 
1.19%
 
One-month LIBOR
CCH Interest Rate Derivatives
 
$28.8 million
 
$5.5 billion
 
May 20, 2015
 
May 31, 2022
 
2.29%
 
One-month LIBOR

The following table (in thousands) shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets:
 
 
September 30, 2016
 
December 31, 2015
 
 
SPL Interest Rate Derivatives
 
CQP Interest Rate Derivatives
 
CCH Interest Rate Derivatives
 
Total
 
SPL Interest Rate Derivatives
 
CQP Interest Rate Derivatives
 
CCH Interest Rate Derivatives
 
Total
Balance Sheet Location
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative liabilities
 
$
(6,376
)
 
$
(5,248
)
 
$
(45,481
)
 
$
(57,105
)
 
$
(5,940
)
 
$

 
$
(28,559
)
 
$
(34,499
)
Non-current derivative liabilities
 
(9,572
)
 
(6,918
)
 
(252,058
)
 
(268,548
)
 
(2,800
)
 

 
(76,440
)
 
(79,240
)
Total derivative liabilities
 
$
(15,948
)
 
$
(12,166
)
 
$
(297,539
)
 
$
(325,653
)
 
$
(8,740
)
 
$

 
$
(104,999
)
 
$
(113,739
)

The following table (in thousands) shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain (loss), net on our Consolidated Statements of Operations during the three and nine months ended September 30, 2016 and 2015:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2016
 
2015
 
2016
 
2015
SPL Interest Rate Derivatives gain (loss)
 
$
2,557

 
$
(10,872
)
 
$
(13,473
)
 
$
(46,541
)
CQP Interest Rate Derivatives gain (loss)
 
6,626

 

 
(12,944
)
 

CCH Interest Rate Derivatives gain (loss)
 
20,113

 
(150,610
)
 
(215,940
)
 
(195,582
)

Commodity Derivatives

Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the SPL Project. The terms of the physical natural gas supply contracts primarily range from approximately one to seven years and commence upon the satisfaction of certain conditions precedent, including but not limited to the date of first commercial operation of specified Trains of the SPL Project. We recognize our Physical Liquefaction Supply Derivatives as either assets or liabilities and measure those instruments at fair value. Changes in the fair value of our Physical Liquefaction Supply Derivatives are reported in earnings. As of September 30, 2016, SPL has secured up to approximately

12


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

1,982.0 million MMBtu of natural gas feedstock through natural gas supply contracts. The notional natural gas position of our Physical Liquefaction Supply Derivatives was approximately 1,069.0 million MMBtu as of September 30, 2016.

Our Financial Liquefaction Supply 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 Financial Liquefaction Supply Derivatives activities.

LNG Trading Derivatives

As of September 30, 2016, we have entered into certain LNG Trading Derivatives representing a short position of 12.6 million MMBtu, and we may from time to time enter into certain financial derivatives in the form of swaps, forwards, options or futures to economically hedge exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG. We have entered into LNG Trading Derivatives to secure a fixed price position to minimize future cash flow variability associated with such LNG transactions.

Natural Gas Derivatives

Our Natural Gas Derivatives were executed through over-the-counter contracts which were subject to nominal credit risk as these transactions settled on a daily margin basis with investment grade financial institutions. We were required by these financial institutions to use margin deposits as credit support for our Natural Gas Derivatives activities. As of September 30, 2016, we did not have any open Natural Gas Derivatives positions or margin deposits at financial institutions.

We recognize all commodity derivative instruments, including our Liquefaction Supply Derivatives, LNG Trading Derivatives and Natural Gas 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, 2016
 
December 31, 2015
 
Liquefaction Supply Derivatives (1)
 
LNG Trading Derivatives (2)
 
Natural Gas Derivatives
 
Total
 
Liquefaction Supply Derivatives
 
LNG Trading Derivatives (2)
 
Natural Gas Derivatives (3)
 
Total
Balance Sheet Location
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other current assets
$
1,947

 
$
2,142

 
$

 
$
4,089

 
$
2,737

 
$
640

 
$

 
$
3,377

Non-current derivative assets
11,247

 

 

 
11,247

 
30,304

 
583

 

 
30,887

Total derivative assets
13,194

 
2,142

 

 
15,336

 
33,041

 
1,223

 

 
34,264

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative liabilities
(1,083
)
 
(2,490
)
 

 
(3,573
)
 
(490
)
 
(107
)
 
(66
)
 
(663
)
Non-current derivative liabilities
(11
)
 

 

 
(11
)
 
(84
)
 
(63
)
 

 
(147
)
Total derivative liabilities
(1,094
)
 
(2,490
)
 

 
(3,584
)
 
(574
)
 
(170
)
 
(66
)
 
(810
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative asset (liabilities), net
$
12,100

 
$
(348
)
 
$

 
$
11,752

 
$
32,467

 
$
1,053

 
$
(66
)
 
$
33,454

 
    
(1)
Does not include collateral of $1.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of September 30, 2016.
(2)
Does not include collateral of $13.4 million and $11.0 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015, respectively.
(3)
Does not include collateral of $5.5 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2015.

13


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

The following table (in thousands) shows the changes in the fair value, settlements and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2016 and 2015:
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
Statement of Operations Location
 
2016
 
2015
 
2016
 
2015
Liquefaction Supply Derivatives gain
LNG revenues (losses)
 
$
374

 
$

 
$
368

 
$

Liquefaction Supply Derivatives gain (loss) (1)
Cost (cost recovery) of sales
 
(10,416
)
 
32,103

 
(22,680
)
 
32,184

LNG Trading Derivatives gain (loss)
LNG revenues (losses)
 
8,617

 
113

 
(3,597
)
 
113

Natural Gas Derivatives loss
LNG revenues (losses)
 

 
(152
)
 
(5
)
 
(260
)
Natural Gas Derivatives gain
Operating and maintenance expense
 

 
857

 
174

 
1,317

 
(1)    Does not include the realized value associated with derivative instruments that settle through physical delivery.

The use of Commodity Derivatives exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our Commodity Derivatives are in an asset position.

FX Derivatives

Cheniere Marketing has entered into FX Derivatives to protect against the volatility in future cash flows attributable to changes in international currency exchange rates. The FX Derivatives economically hedge the foreign currency exposure arising from cash flows expended for both physical and financial LNG transactions and general and administrative expenses related to operations in countries outside of the United States. The total notional amount of our FX Derivatives was $14.6 million as of September 30, 2016.

The following table (in thousands) shows the fair value and location of our FX Derivatives on our Consolidated Balance Sheets:
 
 
 
 
Fair Value Measurements as of
 
Balance Sheet Location
 
September 30, 2016
 
December 31, 2015
FX Derivatives
Derivative liabilities
 
$
(1,151
)
 
$

FX Derivatives
Non-current derivative liabilities
 
(42
)
 


The following table (in thousands) shows the changes in the fair value of our FX Derivatives recorded on our Consolidated Statements of Operations during the three and nine months ended September 30, 2016 and 2015:
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
 
September 30,
 
September 30,
 
 
Statement of Operations Location
 
2016
 
2015
 
2016
 
2015
FX Derivatives loss
 
LNG revenues (losses)
 
$
(1,385
)
 
$

 
$
(1,345
)
 
$

FX Derivatives gain
 
Derivative gain (loss), net
 
31

 

 
129

 

FX Derivatives gain (loss)
 
Other income (expense)
 
2

 

 
(86
)
 



14


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

Balance Sheet Presentation

Our derivative instruments 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, 2016
 
 
 
 
 
 
SPL Interest Rate Derivatives
 
$
(15,948
)
 
$

 
$
(15,948
)
CQP Interest Rate Derivatives
 
(12,166
)
 

 
(12,166
)
CCH Interest Rate Derivatives
 
(297,539
)
 

 
(297,539
)
Liquefaction Supply Derivatives
 
13,740

 
(546
)
 
13,194

Liquefaction Supply Derivatives
 
(2,803
)
 
1,709

 
(1,094
)
LNG Trading Derivatives
 
6,829

 
(4,687
)
 
2,142

LNG Trading Derivatives
 
(5,712
)
 
3,222

 
(2,490
)
FX Derivatives
 
(2,036
)
 
843

 
(1,193
)
As of December 31, 2015
 
 
 
 
 


SPL Interest Rate Derivatives
 
$
(8,740
)
 
$

 
$
(8,740
)
CCH Interest Rate Derivatives
 
(104,999
)
 

 
(104,999
)
Liquefaction Supply Derivatives
 
33,636

 
(595
)
 
33,041

Liquefaction Supply Derivatives
 
(574
)
 

 
(574
)
LNG Trading Derivatives
 
1,922

 
(699
)
 
1,223

LNG Trading Derivatives
 
(2,826
)
 
2,656

 
(170
)
Natural Gas Derivatives
 
188

 
(254
)
 
(66
)

NOTE 7—OTHER NON-CURRENT ASSETS

As of September 30, 2016 and December 31, 2015, other non-current assets consisted of the following (in thousands):
 
 
September 30,
 
December 31,
 
 
2016
 
2015
Advances made under EPC and non-EPC contracts
 
$
13,678

 
$
83,579

Advances made to municipalities for water system enhancements
 
98,958

 
89,953

Collateral payments for the CCL Project
 
36,341

 
4,994

Tax-related payments and receivables
 
31,218

 
31,712

Equity method investments
 
11,058

 
20,295

Other
 
88,181

 
83,922

Total other non-current assets
 
$
279,434

 
$
314,455


NOTE 8—VARIABLE INTEREST ENTITY

Cheniere Holdings
On January 1, 2016, we adopted ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This guidance changed (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.

Cheniere Holdings is a limited liability company formed by us in 2013 to hold our Cheniere Partners limited partner interests. As of September 30, 2016, we owned 80.1% of Cheniere Holdings as well as the director voting share. The director voting share is the sole share entitled to vote in the election of Cheniere Holdings’ board of directors and allows us to remove members of the board of directors at any time and for any reason. If we cease to own greater than 25% of the common shares of Cheniere Holdings or if we choose to relinquish the director voting share, the director voting share will be extinguished.

The board of directors makes all major operating and financial decisions on behalf of Cheniere Holdings. Because ownership of the director voting share allows us to control Cheniere Holdings, irrespective of our majority ownership interest, and the director voting share cannot be removed from our control by the other equity holders of Cheniere Holdings, we have determined that

15


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

Cheniere Holdings is now a variable interest entity. However, this determination has not changed the consolidation of Cheniere Holdings as we have determined that we are its primary beneficiary. Therefore, the determination that Cheniere Holdings is now a variable interest entity had no impact on our Consolidated Financial Statements.

NOTE 9—NON-CONTROLLING INTEREST
 
As of both September 30, 2016 and December 31, 2015, we owned 80.1% of Cheniere Holdings as well as the director voting share, with the remaining non-controlling interest held by the public. Cheniere Holdings owns a 55.9% limited partner interest in Cheniere Partners in the form of 12.0 million common units, 45.3 million Class B units and 135.4 million subordinated units, with the remaining non-controlling interest held by Blackstone CQP Holdco LP and the public. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners.

NOTE 10—ACCRUED LIABILITIES
  
As of September 30, 2016 and December 31, 2015, accrued liabilities consisted of the following (in thousands): 
 
 
September 30,
 
December 31,
 
 
2016
 
2015
Interest costs and related debt fees
 
$
228,434

 
$
159,968

Compensation and benefits
 
104,318

 
99,511

SPL Project and CCL Project costs
 
343,782

 
145,759

LNG terminal costs
 
4,430

 
3,918

Other accrued liabilities
 
19,032

 
18,043

Total accrued liabilities
 
$
699,996

 
$
427,199

 

16


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

NOTE 11—DEBT
 
As of September 30, 2016 and December 31, 2015, our debt consisted of the following (in thousands): 
 
 
September 30,
 
December 31,
 
 
2016
 
2015
Long-term debt:
 
 
 
 
SPLNG
 
 
 
 
6.50% Senior Secured Notes due 2020 (“2020 SPLNG Senior Notes”) (1)
 
$
420,000

 
$
420,000

SPL
 
 
 


5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $7,573 and $8,718
 
2,007,573

 
2,008,718

6.25% Senior Secured Notes due 2022 (“2022 SPL Senior Notes”)
 
1,000,000

 
1,000,000

5.625% Senior Secured Notes due 2023 (“2023 SPL Senior Notes”), net of unamortized premium of $5,844 and $6,392
 
1,505,844

 
1,506,392

5.75% Senior Secured Notes due 2024 (“2024 SPL Senior Notes”)
 
2,000,000

 
2,000,000

5.625% Senior Secured Notes due 2025 (“2025 SPL Senior Notes”)
 
2,000,000

 
2,000,000

5.875% Senior Secured Notes due 2026 (“2026 SPL Senior Notes”)
 
1,500,000

 

5.00% Senior Secured Notes due 2027 (“2027 SPL Senior Notes”)
 
1,500,000

 

2015 SPL Credit Facilities
 

 
845,000

CTPL
 
 
 
 
$400.0 million Term Loan Facility (“CTPL Term Loan”), net of unamortized discount of zero and $1,429
 

 
398,571

Cheniere Partners
 
 
 
 
2016 CQP Credit Facilities
 
450,000

 

CCH
 
 
 
 
7.000% Senior Secured Notes due 2024 (“2024 CCH Senior Notes”)
 
1,250,000

 

2015 CCH Credit Facility
 
3,283,340

 
2,713,000

CCH HoldCo II
 
 
 
 
11.0% Convertible Senior Notes due 2025 (“2025 CCH HoldCo II Convertible Senior Notes”)
 
1,139,667

 
1,050,588

Cheniere
 
 
 
 
4.875% Convertible Unsecured Notes due 2021 (“2021 Cheniere Convertible Unsecured Notes”), net of unamortized discount of $151,996 and $174,095
 
927,729

 
879,938

4.25% Convertible Senior Notes due 2045 (“2045 Cheniere Convertible Senior Notes”), net of unamortized discount of $317,441 and $319,062
 
307,559

 
305,938

Unamortized debt issuance costs (2)
 
(258,199
)
 
(207,718
)
Total long-term debt, net
 
19,033,513

 
14,920,427

 
 
 
 
 
Current debt:
 
 
 
 
7.50% Senior Secured Notes due 2016 (“2016 SPLNG Senior Notes”), net of unamortized discount of $782 and $4,303 (3)
 
1,664,718

 
1,661,197

$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)
 
98,500

 
15,000

Cheniere Marketing trade finance facilities
 
18,807

 

Unamortized debt issuance costs (2)
 
(514
)
 
(2,818
)
Total current debt, net
 
1,781,511

 
1,673,379

 
 
 
 
 
Total debt, net
 
$
20,815,024

 
$
16,593,806

 
(1)
Must be redeemed or repaid concurrently with the 2016 SPLNG Senior Notes under the terms of the 2016 CQP Credit Facilities if the obligations under the 2016 SPLNG Senior Notes are satisfied with borrowings under the 2016 CQP Credit Facilities. See Note 20—Subsequent Events for additional details about the redemption of the 2020 SPLNG Senior Notes.
(2)
Effective January 1, 2016, we adopted ASU 2015-03 and ASU 2015-15, which require debt issuance costs related to term notes to be presented in the balance sheet as a direct deduction from the debt liability, rather than as an asset, retrospectively

17


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

for each reporting period presented. As a result, we reclassified $207.7 million and $2.8 million from debt issuance costs, net to long-term debt, net and current debt, net, respectively, as of December 31, 2015.
(3)
Matures on November 30, 2016. We currently anticipate satisfying this obligation with borrowings under the 2016 CQP Credit Facilities. See Note 20—Subsequent Events for additional details about the intended repayment of the 2016 SPLNG Senior Notes.

2016 Debt Issuances and Redemptions

SPL Senior Notes

In June and September 2016, SPL issued the 2026 SPL Senior Notes and the 2027 SPL Senior Notes, respectively, for aggregate principal amounts of $1.5 billion each. Net proceeds of the offerings of the 2026 SPL Senior Notes and 2027 SPL Senior Notes were approximately $1.3 billion and $1.4 billion, respectively, after deducting commissions, fees and expenses and incremental interest required under the respective senior notes during construction. The net proceeds were used to prepay a portion (for the 2026 SPL Senior Notes) or all (for the 2027 SPL Senior Notes) of the outstanding borrowings and terminate commitments under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $25.8 million and $51.8 million during the three and nine months ended September 30, 2016, respectively. The remaining proceeds from the 2027 SPL Senior Notes are being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the SPL Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities. The 2026 SPL Senior Notes and 2027 SPL Senior Notes accrue interest at fixed rates of 5.875% and 5.00%, respectively, and interest is payable semi-annually in arrears. The terms of the 2026 SPL Senior Notes and 2027 SPL Senior Notes are governed by the same common indenture as the other senior notes of SPL, which contains customary terms and events of default, covenants and redemption terms.

In connection with the issuance of the 2026 SPL Senior Notes and the 2027 SPL Senior Notes, SPL entered into registration rights agreements (the “SPL Registration Rights Agreements”). Under the terms of the SPL Registration Rights Agreements, SPL has agreed, and any future guarantors will agree, to use commercially reasonable efforts to file with the SEC and cause to become effective registration statements relating to offers to exchange any and all of the 2026 SPL Senior Notes and 2027 SPL Senior Notes for like aggregate principal amounts of debt securities of SPL with terms identical in all material respects to the respective senior notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after June 14, 2016 and September 23, 2016, respectively. Under specified circumstances, SPL has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to become effective shelf registration statements relating to resales of the 2026 SPL Senior Notes and the 2027 SPL Senior Notes. SPL will be obligated to pay additional interest on these senior notes if it fails to comply with its obligation to register them within the specified time period.

2024 CCH Senior Notes

In May 2016, CCH issued an aggregate principal amount of $1.25 billion of the 2024 CCH Senior Notes, which are jointly and severally guaranteed by its subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (“CCP GP”, and collectively with CCL and CCP, the “Guarantors”). Net proceeds of the offering of approximately $1.1 billion, after deducting commissions, fees and expenses and incremental interest required under the 2024 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under the 2015 CCH Credit Facility, resulting in a write-off of debt issuance costs associated with the 2015 CCH Credit Facility of $29.0 million during the nine months ended September 30, 2016. Borrowings under the 2024 CCH Senior Notes accrue interest at a fixed rate of 7.000%, and interest on the 2024 CCH Senior Notes is payable semi-annually in arrears.

The indenture governing the 2024 CCH Senior Notes (the “CCH Indenture”) contains customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of CCH and its restricted subsidiaries taken as a whole; or permit any Guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets.


18


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

At any time prior to January 1, 2024, CCH may redeem all or a part of the 2024 CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the CCH Indenture, plus accrued and unpaid interest, if any, to the date of redemption. CCH also may at any time on or after January 1, 2024 through the maturity date of June 30, 2024, redeem the 2024 CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2024 CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

In connection with the closing of the sale of the 2024 CCH Senior Notes, CCH and the Guarantors entered into a Registration Rights Agreement dated May 18, 2016 (the “CCH Registration Rights Agreement”). Under the terms of the CCH Registration Rights Agreement, CCH and the Guarantors have agreed, and any future guarantors of the 2024 CCH 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 May 18, 2016 with respect to an offer to exchange any and all of the 2024 CCH Senior Notes for a like aggregate principal amount of debt securities of CCH with terms identical in all material respects to the respective 2024 CCH 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. Under specified circumstances, CCH and the Guarantors have also agreed, and any future guarantors of the 2024 CCH Senior Notes will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2024 CCH Senior Notes. CCH will be obligated to pay additional interest if it fails to comply with its obligation to register the 2024 CCH Senior Notes within the specified time period.

2016 CQP Credit Facilities

In February 2016, Cheniere Partners entered into the $2.8 billion 2016 CQP Credit Facilities, which consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 million CTPL Term Loan in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 2016 SPLNG Senior Notes and the 2020 SPLNG Senior Notes (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities), (3) a $125.0 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes.

The 2016 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and adjusted one month LIBOR plus 1.0%), plus the applicable margin. The applicable margin for LIBOR loans is 2.25% per annum, and the applicable margin for base rate loans is 1.25% per annum, in each case with a 0.50% step-up beginning on February 25, 2019. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

Cheniere Partners incurred $48.7 million of debt issuance costs as of September 30, 2016, and will incur an additional $21.5 million of debt issuance costs when the SPLNG tranche is funded. The prepayment of the CTPL Term Loan resulted in a write-off of unamortized discount and debt issuance costs of $1.5 million during the nine months ended September 30, 2016. Cheniere Partners pays a commitment fee equal to an annual rate of 40% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears. The DSR Facility and the revolving credit facility are both available for the issuance of letters of credit, which incur a fee equal to an annual rate of 2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019.

The 2016 CQP Credit Facilities mature on February 25, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit Cheniere Partners’ ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the terms of the 2016 CQP Credit Facilities, Cheniere Partners is required to hedge not less than 50% of the variable interest rate exposure on its projected aggregate outstanding balance, maintain a minimum debt service coverage ratio of at least 1.15x at the end of each fiscal quarter beginning March 31, 2019 and have a projected debt service coverage ratio of 1.55x in order to incur additional indebtedness to refinance a portion of the existing obligations.


19


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

The 2016 CQP Credit Facilities are unconditionally guaranteed by each subsidiary of Cheniere Partners other than: (1) SPL, (2) SPLNG until funding of its tranche term loan and (3) certain of the subsidiaries of Cheniere Partners owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2016 (in thousands):
 
 
2015 SPL Credit Facilities
 
SPL Working Capital Facility
 
2016 CQP Credit Facilities
 
2015 CCH Credit Facility
Original facility size
 
$
4,600,000

 
$
1,200,000

 
$
2,800,000

 
$
8,403,714

Outstanding balance
 

 
98,500

 
450,000

 
3,283,340

Commitments prepaid or terminated
 
2,643,867

 

 

 
1,050,660

Letters of credit issued
 

 
337,044

 
7,500

 

Available commitment
 
$
1,956,133

 
$
764,456

 
$
2,342,500

 
$
4,069,714

 
 
 
 
 
 
 
 
 
Interest rate
 
LIBOR plus 1.30% - 1.75% or base rate plus 1.75%
 
LIBOR plus 1.75% or base rate plus 0.75%
 
LIBOR plus 2.25% or base rate plus 1.25% (1)
 
LIBOR plus 2.25% or base rate plus 1.25% (2)
Maturity date
 
Earlier of December 31, 2020 or second anniversary of SPL Trains 1 through 5 completion date
 
December 31, 2020, with various terms for underlying loans
 
February 25, 2020, with principals due quarterly commencing on February 19, 2019
 
Earlier of May 13, 2022 or second anniversary of CCL Trains 1 and 2 completion date
 
(1)
There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.
(2)
There is a 0.25% step-up for both LIBOR and base rate loans following completion of the first two Trains of the CCL Project.

Convertible Notes

Below is a summary of our convertible notes outstanding as of September 30, 2016 (in thousands):
 
 
2021 Cheniere Convertible Unsecured Notes
 
2025 CCH HoldCo II Convertible Senior Notes
 
2045 Cheniere Convertible Senior Notes
Aggregate original principal
 
$
1,000,000

 
$
1,000,000

 
$
625,000

Debt component, net of discount
 
$
927,729

 
$
1,139,667

 
$
307,559

Equity component
 
$
203,892

 
$

 
$
194,082

Interest payment method
 
Paid-in-kind

 
Paid-in-kind (1)

 
Cash

Conversion by us (2)
 

 
(3)

 
(4)

Conversion by holders (2)
 
(5)

 
(6)

 
(7)

Conversion basis
 
Cash and/or stock

 
Stock

 
Cash and/or stock

Conversion value in excess of principal
 
$

 
$

 
$

Maturity date
 
May 28, 2021

 
March 1, 2025

 
March 15, 2045

Contractual interest rate
 
4.875
%
 
11.0
%
 
4.25
%
Effective interest rate
 
8.3
%
 
11.9
%
 
9.4
%
Remaining debt discount and debt issuance costs amortization period (8)
 
4.7 years

 
4.0 years

 
28.5 years

 
(1)
Prior to the substantial completion of Train 2 of the CCL Project, interest will be paid entirely in kind. Following this date, the interest generally must be paid in cash; however, a portion of the interest may be paid in kind under certain specified circumstances.
(2)
Conversion is subject to various limitations and conditions.
(3)
Convertible on or after the later of March 1, 2020 and the substantial completion of Train 2 of the CCL Project, provided that our market capitalization is not less than $10.0 billion (“Eligible Conversion Date”). The conversion price is the

20


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

lower of (1) a 10% discount to the average of the daily volume-weighted average price (“VWAP”) of our common stock for the 90 trading day period prior to the date notice is provided, and (2) a 10% discount to the closing price of our common stock on the trading day preceding the date notice is provided.
(4)
Redeemable at any time after March 15, 2020 at a redemption price payable in cash equal to the accreted amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date.
(5)
Initially convertible at $93.64 (subject to adjustment upon the occurrence of certain specified events), provided that the closing price of our common stock is greater than or equal to the conversion price on the conversion date.
(6)
Convertible on or after the six-month anniversary of the Eligible Conversion Date, provided that our total market capitalization is not less than $10.0 billion, at a price equal to the average of the daily VWAP of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided.
(7)
Prior to December 15, 2044, convertible only under certain circumstances as specified in the indenture; thereafter, holders may convert their notes regardless of these circumstances. The conversion rate will initially equal 7.2265 shares of our common stock per $1,000 principal amount of the 2045 Cheniere Convertible Senior Notes, which corresponds to an initial conversion price of approximately $138.38 per share of our common stock (subject to adjustment upon the occurrence of certain specified events).
(8)
We amortize any debt discount and debt issuance costs using the effective interest over the period through contractual maturity except for the 2025 CCH HoldCo II Convertible Senior Notes, which are amortized through the date they are first convertible by holders into our common stock.

Interest Expense

Total interest expense, including interest expense related to our convertible notes, consisted of the following (in thousands):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
2016
 
2015
Interest cost on convertible notes:
 
 
 
 
 
 
 
 
Interest per contractual rate
 
$
51,000

 
$
46,782

 
$
149,893

 
$
97,991

Amortization of debt discount
 
6,593

 
7,233

 
24,578

 
20,948

Amortization of debt issuance costs
 
1,362

 
1,133

 
3,766

 
1,748

Total interest cost related to convertible notes
 
58,955


55,148

 
178,237

 
120,687

Interest cost on debt excluding convertible notes
 
281,814


230,807

 
773,032


587,137

Total interest cost
 
340,769

 
285,955

 
951,269

 
707,824

Capitalized interest
 
(192,716
)
 
(192,389
)
 
(620,912
)
 
(469,160
)
Total interest expense, net
 
$
148,053


$
93,566

 
$
330,357

 
$
238,664


Fair Value Disclosures

The following table (in thousands) shows the carrying amount and estimated fair value of our debt:
 
 
September 30, 2016
 
December 31, 2015
 
 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
Senior Notes, net of premium or discount (1)
 
$
14,848,135

 
$
15,747,108

 
$
10,596,307

 
$
9,525,809

CTPL Term Loan, net of discount (2)
 

 

 
398,571

 
400,000

Credit facilities (2) (3)
 
3,850,647

 
3,850,647

 
3,573,000

 
3,573,000

2021 Cheniere Convertible Unsecured Notes, net of discount (4)
 
927,729

 
981,520

 
879,938

 
825,413

2025 CCH HoldCo II Convertible Senior Notes (4)
 
1,139,667

 
1,296,440

 
1,050,588

 
914,363

2045 Cheniere Convertible Senior Notes, net of discount (5)
 
307,559

 
414,063

 
305,938

 
331,919

 
(1)
Includes 2016 SPLNG Senior Notes, net of discount; 2020 SPLNG Senior Notes; 2021 SPL Senior Notes, net of premium; 2022 SPL Senior Notes; 2023 SPL Senior Notes, net of premium; 2024 SPL Senior Notes; 2025 SPL Senior Notes; 2026

21


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

SPL Senior Notes; 2027 SPL Senior Notes; and 2024 CCH Senior Notes (collectively, the “Senior Notes”). The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of the Senior Notes and other similar instruments.
(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. 
(3)
Includes 2015 SPL Credit Facilities, SPL Working Capital Facility, 2016 CQP Credit Facilities, 2015 CCH Credit Facility and Cheniere Marketing trade finance facilities.
(4)
The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 
(5)
The Level 1 estimated fair value was based on unadjusted quoted prices in active markets for identical liabilities that we had the ability to access at the measurement date.

NOTE 12—RESTRUCTURING EXPENSE
  
During the fourth quarter of 2015, we initiated certain organizational changes to simplify our corporate structure, improve our operational efficiencies and implement a strategy for sustainable, long-term stockholder value creation through financially disciplined development, construction, operation and investment.  As a result of these efforts, we recorded $26.2 million and $49.2 million of restructuring charges and other costs associated with restructuring and operational efficiency initiatives during the three and nine months ended September 30, 2016, respectively, for which the majority of these charges required, or will require, cash expenditure. Included in these amounts are $20.9 million and $42.9 million for share-based compensation during the three and nine months ended September 30, 2016, respectively.  All charges were recorded within the line item entitled “restructuring expense” on our Consolidated Statements of Operations and substantially all related to severance and other employee-related costs. As of September 30, 2016 and December 31, 2015, we had $14.6 million and $33.0 million, respectively, of accrued restructuring charges and other costs that were recorded as part of accrued liabilities on our Consolidated Balance Sheets.  Operational efficiency initiatives remain ongoing and are expected to be substantially complete by the end of 2016.

NOTE 13—INCOME TAXES
  
We are not presently a taxpayer for federal or state income tax purposes and have not recorded a provision for federal or state income taxes in any of the periods included in the accompanying Consolidated Financial Statements. We have recorded a net benefit (provision) of $(1.6) million and $0.1 million for the three months ended September 30, 2016 and 2015, respectively, and $(1.9) million and $(0.1) million for the nine months ended September 30, 2016 and 2015, respectively, for foreign income taxes.

We experienced an ownership change within the provisions of Internal Revenue Code (“IRC”) Section 382 in 2008, 2010 and 2012. An analysis of the annual limitation on the utilization of our net operating losses (“NOLs”) was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not limit the use of our NOLs in full over the carryover period. We will continue to monitor trading activity in our shares which may cause an additional ownership change which could ultimately affect our ability to fully utilize our existing NOL carryforwards.

NOTE 14—SHARE-BASED COMPENSATION
  
We have granted stock, restricted stock, phantom units and options to purchase common stock to employees, outside directors and a consultant under the Amended and Restated 2003 Stock Incentive Plan, as amended (the “2003 Plan”), 2011 Incentive Plan, as amended (the “2011 Plan”), the 2015 Long-Term Cash Incentive Plan (the “2015 Plan”) and the 2015 Employee Inducement Incentive Plan (the “Inducement Plan”).

The 2003 Plan and 2011 Plan provide for the issuance of 21.0 million shares and 35.0 million shares, respectively, of our common stock that may be in the form of non-qualified stock options, incentive stock options, purchased stock, restricted (non-vested) stock, bonus (unrestricted) stock, stock appreciation rights, phantom units and other share-based performance awards deemed by the Compensation Committee of our Board of Directors (the “Compensation Committee”) to be consistent with the purposes of the 2003 Plan and 2011 Plan. As of September 30, 2016, all of the shares under the 2003 Plan have been granted and

22


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

26.6 million shares, net of cancellations, have been granted under the 2011 Plan. The 2015 Plan generally provides for cash-settled awards in the form of stock appreciation rights, phantom unit awards, performance unit awards, other-stock based awards and cash awards. As of September 30, 2016, 6.3 million phantom units have been granted under the 2015 Plan. See Note 20—Subsequent Events regarding the termination of 2014-2018 Long-Term Cash Incentive Program (“2014-2018 LTIP”) under the 2015 Plan. The Inducement Plan provides for the issuance of up to 1.0 million shares of our common stock in the form of non-qualified stock options, restricted stock awards, stock appreciation rights, performance awards, phantom stock awards and other stock-based awards deemed by the Compensation Committee to provide us with an opportunity to attract employees. As of September 30, 2016, 0.2 million shares of restricted stock have been granted under the Inducement Plan.

Total share-based compensation expense consisted of the following (in thousands):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
2016
 
2015
Total share-based compensation
 
$
39,557

 
$
27,451

 
$
97,617

 
$
114,107

Capitalized share-based compensation
 
(6,153
)
 
(1,202
)
 
(12,489
)
 
(21,480
)
Total share-based compensation expense
 
$
33,404

 
$
26,249

 
$
85,128

 
$
92,627

 
The total unrecognized compensation cost at September 30, 2016 relating to non-vested share-based compensation arrangements was $138.0 million, which is expected to be recognized over a weighted average period of 1.4 years.

During the three and nine months ended September 30, 2016, we recognized $4.3 million and $5.6 million, respectively, of share-based compensation expense related to the modification of share-based compensation awards resulting from employee terminations.

We received $0.1 million in each of the three and nine months ended September 30, 2016 and $0.4 million and $2.3 million in the three and nine months ended September 30, 2015, respectively, of proceeds from the exercise of stock options.

NOTE 15—NET LOSS PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

Basic net loss per share attributable to common stockholders (“EPS”) excludes dilution and is computed by dividing net loss attributable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted EPS reflects potential dilution and is computed by dividing net loss attributable to common stockholders by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued.
 
The following table (in thousands, except for loss per share) reconciles basic and diluted weighted average common shares outstanding for the three and nine months ended September 30, 2016 and 2015:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2016
 
2015
 
2016
 
2015
Weighted average common shares outstanding:
 
 
 
 
 
 
 
 
Basic
 
228,924

 
227,126

 
228,463

 
226,648

Dilutive common stock options and unvested stock (1)
 

 

 

 

Diluted
 
228,924

 
227,126

 
228,463

 
226,648

 
 
 
 
 
 
 
 
 
Basic and diluted net loss per share attributable to common stockholders
 
$
(0.44
)
 
$
(1.31
)
 
$
(3.15
)
 
$
(3.02
)
 
(1)
Stock options and unvested stock of 5.8 million shares and 5.7 million shares for the three and nine months ended September 30, 2016, respectively, and 8.6 million shares for each of the three and nine months ended September 30, 2015, representing securities that could potentially dilute basic EPS in the future, were not included in the diluted net loss per share computations because their effect would have been anti-dilutive. Included in these numbers of shares are 5.1 million shares for each of the three and nine months ended September 30, 2016 and 5.4 million shares for each of the three and nine months ended September 30, 2015 of unvested stock that have performance conditions not yet satisfied as of September 30, 2016 and 2015, respectively. In addition, 16.2 million shares in aggregate for the three and nine months

23


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

ended September 30, 2016 and 15.6 million shares in aggregate for the three and nine months ended September 30, 2015, issuable upon conversion of the 2021 Cheniere Convertible Unsecured Notes and the 2045 Cheniere Convertible Senior Notes, were not included in the computation of diluted net loss per share because the computation of diluted net loss per share utilizing the “if-converted” method would be anti-dilutive. There were no shares included in the computation of diluted net loss per share for the 2025 CCH HoldCo II Convertible Senior Notes because substantive non-market-based contingencies underlying the eligible conversion date have not been met as of September 30, 2016.

NOTE 16—COMMITMENTS AND CONTINGENCIES

Cheniere has various contractual obligations which are recorded as liabilities in our Consolidated Financial Statements. Other items, such as certain purchase commitments and other executed contracts which do not meet the definition of a liability as of September 30, 2016, are not recognized as liabilities.

Parallax Litigation

In 2015, our wholly owned subsidiary, Cheniere LNG Terminals, LLC (“CLNGT”), entered into discussions with Parallax Enterprises, LLC (“Parallax Enterprises”) regarding the potential joint development of two liquefaction plants in Louisiana (the “Potential Liquefaction Transactions”). While the parties negotiated regarding the Potential Liquefaction Transactions, CLNGT loaned Parallax Enterprises approximately $46 million, as reflected in a secured note dated April 23, 2015, as amended on June 30, 2015, September 30, 2015 and November 4, 2015 (the “Secured Note”). The Secured Note was secured by all assets of Parallax Enterprises and its subsidiary entities. On June 30, 2015, Parallax Enterprises’ parent entity, Parallax Energy LLC (“Parallax Energy”), executed a Pledge and Guarantee Agreement further securing repayment of the Secured Note by providing a parent guaranty and a pledge of all of the equity of Parallax Enterprises in satisfaction of the Secured Note (the “Pledge Agreement”). CLNGT and Parallax Enterprises never executed a definitive agreement to pursue the Potential Liquefaction Transactions. The Secured Note matured on December 11, 2015, and Parallax Enterprises failed to make payment. On February 3, 2016, CLNGT filed an action against Parallax Energy, Parallax Enterprises, and certain of Parallax Enterprises’ subsidiary entities, styled Cause No. 4:16-cv-00286, Cheniere LNG Terminals, LLC v. Parallax Energy LLC, et al., in the United States District Court for the Southern District of Texas (the “Texas Suit”). CLNGT asserted claims in the Texas Suit for (1) recovery of all amounts due under the Secured Note and (2) declaratory relief establishing that CLNGT is entitled to enforce its rights under the Secured Note and Pledge Agreement in accordance with each instrument’s terms and that CLNGT has no obligations of any sort to Parallax Enterprises concerning the Potential Liquefaction Transactions. On March 11, 2016, Parallax Enterprises and the other defendants in the Texas Suit moved to dismiss the suit for lack of subject matter jurisdiction. On August 2, 2016, the court denied the defendants’ motion to dismiss without prejudice and permitted the parties to pursue jurisdictional discovery, which is ongoing.

On March 11, 2016, Parallax Enterprises filed a suit against us and CLNGT styled Civil Action No. 62-810, Parallax Enterprises LLP v. Cheniere Energy, Inc. and Cheniere LNG Terminals, LLC, in the 25th Judicial District Court of Plaquemines Parish, Louisiana (the “Louisiana Suit”), wherein Parallax Enterprises asserted claims for breach of contract, fraudulent inducement, negligent misrepresentation, detrimental reliance, unjust enrichment and violation of the Louisiana Unfair Trade Practices Act. Parallax Enterprises predicated its claims in the Louisiana Suit on an allegation that we and CLNGT breached a purported agreement to jointly develop the Potential Liquefaction Transactions. Parallax Enterprises sought $400 million in alleged economic damages and rescission of the Secured Note. On April 15, 2016, we and CLNGT removed the Louisiana Suit to the United States District Court for the Eastern District of Louisiana, which subsequently transferred the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was assigned Civil Action No. 4:16-cv-01628 and transferred to the same judge presiding over the Texas Suit for coordinated handling. On August 22, 2016, Parallax Enterprises voluntarily dismissed all claims asserted against CLNGT and us in the Louisiana Suit without prejudice to refiling. We do not expect that the resolution of this litigation will have a material adverse impact on our financial results.

Obligations under Certain Guarantee Contracts

Cheniere and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate transactions with third parties. These arrangements include financial guarantees, letters of credit and debt guarantees. As of September 30, 2016 and December 31, 2015, there were no liabilities recognized under these guarantee arrangements.


24


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

NOTE 17—BUSINESS SEGMENT INFORMATION
  
We have two reportable segments: LNG terminal segment and LNG and natural gas marketing segment. We determine our reportable segments by identifying each segment that engaged in business activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the entities’ chief operating decision maker for purposes of resource allocation and performance assessment and had discrete financial information. Revenues from external customers that were derived from customers outside of the United States were $224.3 million and $255.7 million for the three and nine months ended September 30, 2016, respectively. We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States.

Our LNG terminal segment consists of the Sabine Pass and Corpus Christi LNG terminals. We own and operate the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast through our ownership interest in and management agreements with Cheniere Partners. We own 100% of the general partner interest in Cheniere Partners and 80.1% of the common shares of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners. We are also developing and constructing a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal near Corpus Christi, Texas.
 
Our LNG and natural gas marketing segment consists of LNG and natural gas marketing activities by Cheniere Marketing. Cheniere Marketing is developing a portfolio of long-term, short-term and spot LNG SPAs with professional staff based in the United States, United Kingdom, Singapore and Chile.


25


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

The following table (in thousands) summarizes revenues (losses) and income (loss) from operations for each of our reporting segments: 
 
Segments
 
LNG Terminal
 
LNG & Natural Gas Marketing
 
Corporate and Other (1)
 
Total
Consolidation
Three Months Ended September 30, 2016
 
 
 
 
 
 
 
Revenues (losses) from external customers
$
314,917

 
$
179,188

 
$
(28,432
)
 
$
465,673

Intersegment revenues (losses) (2)
16,244

 
8,692

 
(24,936
)
 

Depreciation and amortization expense
43,014

 
344

 
5,854

 
49,212

Income (loss) from operations (3)
44,346

 
26,614

 
(55,684
)
 
15,276

Interest expense, net of capitalized interest
(121,636
)
 

 
(26,417
)
 
(148,053
)
Income (loss) before income taxes and non-controlling interest (4)
(68,345
)
 
26,736

 
(87,169
)
 
(128,778
)
Share-based compensation
9,183

 
5,434

 
24,940

 
39,557

Expenditures for additions to long-lived assets
1,213,662

 
1,103

 
170

 
1,214,935

 
 
 
 
 
 
 
 
Three Months Ended September 30, 2015
 
 
 
 
 
 
 
Revenues (losses) from external customers
$
67,212

 
$
(1,557
)

$
404

 
$
66,059

Intersegment revenues (losses) (2)
233

 
11,354

 
(11,587
)
 

Depreciation and amortization expense
16,775

 
320

 
4,543

 
21,638

Income (loss) from operations
27,072

 
(27,117
)
 
(52,029
)
 
(52,074
)
Interest expense, net of capitalized interest
(67,589
)
 
(14
)
 
(25,963
)
 
(93,566
)
Loss before income taxes and non-controlling interest (4)
(196,693
)
 
(27,665
)
 
(82,803
)
 
(307,161
)
Share-based compensation
1,316

 
2,051

 
24,084

 
27,451

Expenditures for additions to long-lived assets
1,429,808

 
403

 
21,258

 
1,451,469

 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2016
 
 
 
 
 
 

Revenues (losses) from external customers
$
530,526

 
$
222,418

 
$
(41,363
)
 
$
711,581

Intersegment revenues (losses) (2)
17,168

 
29,259

 
(46,427
)
 

Depreciation and amortization expense
87,698

 
965

 
17,419

 
106,082

Income (loss) from operations (3)
41,912

 
(35,850
)
 
(157,799
)
 
(151,737
)
Interest expense, net of capitalized interest
(253,129
)
 

 
(77,228
)
 
(330,357
)
Loss before income taxes and non-controlling interest (4)
(519,877
)
 
(35,814
)
 
(256,732
)
 
(812,423
)
Share-based compensation
19,005

 
20,580

 
58,032

 
97,617

Expenditures for additions to long-lived assets
3,800,814

 
2,634

 
13,238

 
3,816,686

 
 
 
 
 
 
 

Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
Revenues (losses) from external customers
$
203,324

 
$
(1,601
)
 
$
730

 
$
202,453

Intersegment revenues (losses) (2)
827

 
24,725

 
(25,552
)
 

Depreciation and amortization expense
47,787

 
764

 
11,010

 
59,561

Loss from operations
(15,324
)
 
(58,667
)
 
(134,201
)
 
(208,192
)
Interest expense, net of capitalized interest
(169,899
)
 
(14
)
 
(68,751
)
 
(238,664
)
Loss before income taxes and non-controlling interest (4)
(507,751
)
 
(59,871
)
 
(217,014
)
 
(784,636
)
Share-based compensation
30,233

 
12,138

 
71,736

 
114,107

Expenditures for additions to long-lived assets
5,964,244

 
2,517

 
70,913

 
6,037,674

 
(1)
Includes corporate activities, business development, strategic activities and certain intercompany eliminations. These activities have been included in the corporate and other column. Also includes $45.1 million and $60.5 million for the three and nine months ended September 30, 2016, respectively, of Cheniere Marketing’s LNG revenues, which is eliminated in consolidation.
(2)
Intersegment revenues (losses) related to our LNG and natural gas marketing segment are primarily a result of international revenue allocations using a cost plus transfer pricing methodology. These LNG and natural gas marketing segment

26


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

intersegment revenues (losses) are eliminated with intersegment revenues (losses) in our Consolidated Statements of Operations.
(3)
Includes restructuring expense of $23.1 million and $35.3 million for the three and nine months ended September 30, 2016, respectively, in the corporate and other column and $3.1 million and $13.9 million for the three and nine months ended September 30, 2016, respectively, in the LNG and natural gas marketing segment.
(4)
Items to reconcile income (loss) from operations and income (loss) before income taxes and non-controlling interest include consolidated other income (expense) amounts as presented on our Consolidated Statements of Operations primarily related to our LNG terminal segment.

The following table (in thousands) shows total assets for each of our reporting segments: 
 
 
September 30,
 
December 31,
 
 
2016
 
2015
LNG Terminal
 
$
21,365,364

 
$
17,363,750

LNG & Natural Gas Marketing
 
631,378

 
550,896

Corporate and Other
 
692,338

 
894,407

Total Consolidation
 
$
22,689,080

 
$
18,809,053


NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION

The following table (in thousands) provides supplemental disclosure of cash flow information: 
 
 
Nine Months Ended September 30,
 
 
2016
 
2015
Cash paid during the period for interest, net of amounts capitalized
 
$
29,879

 
$
48,271

Non-cash conveyance of assets
 

 
13,169

 
The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities was $491.4 million and $356.3 million as of September 30, 2016 and 2015, respectively.

NOTE 19—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by the Company as of September 30, 2016:
Standard
 
Description
 
Expected Date of Adoption
 
Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto
 
This standard amends existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance may be early adopted beginning January 1, 2017, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.
 
January 1, 2018
 
We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.


27


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

Standard
 
Description
 
Expected Date of Adoption
 
Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

 
This standard 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. Early adoption is permitted.
 
December 31, 2016
 
The adoption of this guidance is not expected to have an impact on our Consolidated Financial Statements or related disclosures.

ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory

 
This standard requires inventory to 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 may be early adopted and must be adopted prospectively.
 
January 1, 2017
 
We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-02, Leases (Topic 842)
 
This standard requires a lessee to recognize leases on its balance sheet by recording a liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.
 
January 1, 2019

 
We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
 
This standard primarily requires the recognition of excess tax benefits for share-based awards in the statement of operations and the classification of excess tax benefits as an operating activity within the statement of cash flows. The guidance also allows an entity to elect to account for forfeitures when they occur. This guidance may be early adopted, but all of the guidance must be adopted in the same period.
 
January 1, 2017

 
We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
 
This standard requires the immediate recognition of the tax consequences of intercompany asset transfers other than inventory. This guidance may be early adopted, but only at the beginning of an annual period, and must be adopted using a modified retrospective approach.
 
January 1, 2018

 
We are currently evaluating the impact of the provisions of this guidance on our Consolidated Financial Statements and related disclosures.


28


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

Additionally, the following table provides a brief description of recent accounting standards that were adopted by the Company during the reporting period:
Standard
 
Description
 
Date of Adoption
 
Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis

 
These amendments primarily affect 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 may be early adopted, and may be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption.
 
January 1, 2016
 
The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.

ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements

 
These standards require 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. Debt issuance costs incurred in connection with line of credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the line of credit arrangement. This guidance may be early adopted, and must be adopted retrospectively to each prior reporting period presented.
 
January 1, 2016
 
Upon adoption of these standards, the balance of debt, net was reduced by the balance of debt issuance costs, net, except for the balance related to line of credit arrangements, on our Consolidated Balance Sheets. See Note 11—Debt for additional disclosures.
ASU 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement

 
This standard clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. This guidance may be early adopted, and may be adopted as either retrospectively or prospectively to arrangements entered into, or materially modified, after the effective date.
 
January 1, 2016
 
The adoption of this guidance did not have an impact on our Consolidated Financial Statements or related disclosures.


NOTE 20—SUBSEQUENT EVENTS

SPLNG Senior Notes Redemption

On October 14, 2016, SPLNG issued a notice of redemption to redeem all of its outstanding 2020 SPLNG Senior Notes. The redemption date will be November 30, 2016 (the “Redemption Date”) and the price will be equal to 103.250% of the principal amount of the 2020 SPLNG Senior Notes, plus accrued and unpaid interest and additional interest, if any, on the 2020 SPLNG Senior Notes to, but not including, the Redemption Date. Concurrently with the redemption of the 2020 SPLNG Senior Notes, SPLNG intends to repay all of its outstanding 2016 SPLNG Senior Notes, which mature on the Redemption Date, at a price equal to 100% of the principal amount of the 2016 SPLNG Senior Notes, plus accrued and unpaid interest and additional interest, if any, on the 2016 SPLNG Senior Notes to, but not including, the Redemption Date.

Termination of 2014-2018 LTIP

On October 27, 2016, the Compensation Committee recommended and our Board of Directors approved the termination, effective as of October 31, 2016, of the 2014-2018 LTIP under the 2015 Plan.


29


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” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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 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 and pipeline, 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, natural gas 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 and pipelines, including the financing of such Trains;
statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
statements regarding our anticipated LNG and natural gas marketing activities; 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.

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,

30


2015. 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 includes 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
 
Cheniere, a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. Our vision is to be recognized as the premier global LNG company and provide a reliable, competitive and integrated source of LNG to our customers while creating a safe, productive and rewarding work environment for our employees. We own and operate the Sabine Pass LNG terminal in Louisiana through our ownership interest in and management agreements with Cheniere Partners, which is a publicly traded limited partnership that we created in 2007. We own 100% of the general partner interest in Cheniere Partners and 80.1% of Cheniere Holdings, which is a publicly traded limited liability company formed in 2013 that owns a 55.9% limited partner interest in Cheniere Partners. We are currently developing and constructing two natural gas liquefaction and export facilities.

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. The Sabine Pass LNG terminal has operational regasification facilities owned by Cheniere Partners’ wholly owned subsidiary, SPLNG, that include existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two marine berths 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. Cheniere Partners is developing and constructing natural gas liquefaction facilities (the “SPL Project”) at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, SPL. Cheniere Partners plans to construct up to six Trains, which are in various stages of development and construction. Trains 1 and 2 have commenced operating activities, Train 3 is undergoing commissioning, Trains 4 and 5 are under construction and Train 6 is fully permitted. Each Train is expected to have a nominal production capacity of approximately 4.5 mtpa of LNG. Cheniere Partners also owns a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through a wholly owned subsidiary, CTPL.

We are developing and constructing a second natural gas liquefaction and export facility at the Corpus Christi LNG terminal, which is on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas, and a pipeline facility (collectively, the “CCL Project”) through wholly owned subsidiaries CCL and CCP, respectively. The CCL Project is being developed for up to three Trains, with expected aggregate nominal production capacity of approximately 13.5 mtpa of LNG, three LNG storage tanks with capacity of approximately 10.1 Bcfe and two marine berths that can accommodate vessels with nominal capacity of up to 266,000 cubic meters. The CCL Project is being developed in stages. The first stage (“Stage 1”) includes Trains 1 and 2, two LNG storage tanks, one complete marine berth and a second partial berth and all of the CCL Project’s necessary infrastructure facilities. The second stage (“Stage 2”) includes Train 3, one LNG storage tank and the completion of the second partial berth. The CCL Project also includes a 23-mile, 48-inch natural gas supply pipeline that will interconnect the Corpus Christi LNG terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”).


31


Corpus Christi Liquefaction Stage III, LLC and Cheniere Corpus Christi Pipeline Stage III, LLC (the “CCL Stage III entities”), our wholly owned subsidiaries separate from the CCH Group, are also developing two additional Trains and one LNG storage tank at the Corpus Christi LNG terminal adjacent to the CCL Project, along with a second natural gas pipeline.

Cheniere Marketing is engaged in the LNG and natural gas marketing business and is developing a portfolio of long-term, short-term and spot SPAs. Cheniere Marketing has entered into SPAs with SPL and CCL to purchase, at Cheniere Marketing’s option, LNG produced by the SPL Project and the CCL Project.

We are also in various stages of developing other projects which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision (“FID”). We have proposed the development of a pipeline with expected capacity of up to 1.4 Bcf/d connecting new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the SPL Project and the CCL Project. We expect the regulatory pre-filing process to commence imminently and to file formal applications for the required regulatory permits in 2017. We are also exploring the development of a midscale liquefaction project using electric drive modular Trains, with an expected aggregate nominal production capacity of approximately 9.5 mtpa of LNG.

Overview of Significant Events

Our significant accomplishments since January 1, 2016 and through the filing date of this Form 10-Q include the following:  
SPL commenced production and shipment of LNG commissioning cargoes from Trains 1 and 2 of the SPL Project in February and August 2016, respectively, and achieved substantial completion and commenced operating activities in May and September 2016, respectively.
In September 2016, SPL initiated the commissioning process for Train 3 of the SPL Project.
In October 2016, the previously announced planned outage to improve performance of the flare systems at the SPL Project, as well as to perform scheduled maintenance to Train 1 and other facilities, was completed on schedule and budget.
In May 2016, our Board of Directors appointed Jack Fusco as our President and Chief Executive Officer.
In February 2016, Cheniere Partners entered into a Credit and Guaranty Agreement for the incurrence of debt of up to an aggregate amount of approximately $2.8 billion (the “2016 CQP Credit Facilities”). The 2016 CQP Credit Facilities consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 million term loan facility (the “CTPL Term Loan”) in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 7.50% Senior Secured Notes due 2016 issued by SPLNG (the “2016 SPLNG Senior Notes”) and the 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”) (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities ), (3) a $125.0 million debt service reserve credit facility (the “DSR Facility”) that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes.
In May 2016, CCH issued an aggregate principal amount of $1.25 billion of 7.000% Senior Secured Notes due 2024 (the “2024 CCH Senior Notes”). Net proceeds of the offering of approximately $1.1 billion, after deducting commissions, fees and expenses and incremental interest required under the 2024 CCH Senior Notes during construction, were used to prepay a portion of the outstanding borrowings under its credit facility (the “2015 CCH Credit Facility”).
In June and September 2016, SPL issued 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”) and 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), respectively, for aggregate principal amounts of $1.5 billion each. Net proceeds of the offerings of the 2026 SPL Senior Notes and 2027 SPL Senior Notes were approximately $1.3 billion and $1.4 billion, respectively, after deducting commissions, fees and expenses and incremental interest required under the respective senior notes during construction. The net proceeds were used to prepay a portion (for the 2026 SPL Senior Notes) or all (for the 2027 SPL Senior Notes) of the outstanding borrowings under the credit facilities we entered into in June 2015 (the “2015 SPL Credit Facilities”). The remaining proceeds from the 2027 SPL Senior Notes are being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the SPL Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.
On September 30, 2016, we submitted a proposal to Cheniere Holdings’ board of directors to acquire the publicly held shares of Cheniere Holdings not already owned by us in a stock for stock exchange. There can be no assurance that any discussions that may occur between us and Cheniere Holdings in connection with our proposal will result in the entry

32


into a definitive agreement concerning a transaction or, if such a definitive agreement is reached, will result in the consummation of a transaction provided for in such definitive agreement.
In October 2016, SPLNG issued a notice of redemption to redeem all of its outstanding 2020 SPLNG Senior Notes. The redemption date will be November 30, 2016 (the “Redemption Date”) and the price will be equal to 103.250% of the principal amount of the 2020 SPLNG Senior Notes, plus accrued and unpaid interest and additional interest, if any, on the 2020 SPLNG Senior Notes to, but not including, the Redemption Date. Concurrently with the redemption of the 2020 SPLNG Senior Notes, SPLNG intends to repay all of its outstanding 2016 SPLNG Senior Notes, which mature on the Redemption Date, at a price equal to 100% of the principal amount of the 2016 SPLNG Senior Notes, plus accrued and unpaid interest and additional interest, if any, on the 2016 SPLNG Senior Notes to, but not including, the Redemption Date.
Liquidity and Capital Resources

Although results are consolidated for financial reporting, Cheniere, Cheniere Holdings, Cheniere Partners, SPL, SPLNG and the CCH Group operate with independent capital structures. We expect the cash needs for at least the next twelve months will be met for each of these independent capital structures as follows:
SPLNG through operating cash flows, existing unrestricted cash and debt offerings or equity contributions;
SPL through project debt and borrowings, equity contributions from Cheniere Partners and operating cash flows;
Cheniere Partners through operating cash flows from SPLNG, SPL and CTPL, existing unrestricted cash and debt or equity offerings;
Cheniere Holdings through distributions from Cheniere Partners;
CCH Group through project financing and equity contributions from Cheniere; and
Cheniere through project financing, existing unrestricted cash, debt and equity offerings by us or our subsidiaries, operating cash flows, services fees from Cheniere Holdings, Cheniere Partners and its other subsidiaries and distributions from our investments in Cheniere Holdings and Cheniere Partners.

As of September 30, 2016, we had cash and cash equivalents of $990.1 million available to Cheniere. In addition, we had current and non-current restricted cash of $858.7 million (which included current and non-current restricted cash available to us and our subsidiaries) designated for the following purposes: $192.8 million for the CCL Project; $325.6 million for the SPL Project; $127.5 million due to restrictions under the 2016 CQP Credit Facilities; $129.1 million for interest payments related to the SPLNG Senior Notes; and $83.7 million for other restricted purposes.

In November 2014, we issued an aggregate principal amount of $1.0 billion Convertible Unsecured Notes due 2021 (the “2021 Cheniere Convertible Unsecured Notes”). The 2021 Cheniere Convertible Unsecured Notes are convertible at the option of the holder into our common stock at the then applicable conversion rate, provided that the closing price of our common stock is greater than or equal to the conversion price on the date of conversion. The initial conversion price was $93.64 and is subject to adjustment upon the occurrence of certain specified events. We have the option to satisfy the conversion obligation with cash, common stock or a combination thereof.

In March 2015, we issued the $625.0 million aggregate principal amount of 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”). We have the right, at our option, at any time after March 15, 2020, to redeem all or any part of the 2045 Cheniere Convertible Senior Notes at a redemption price equal to the accreted amount of the 2045 Cheniere Convertible Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to such redemption date. The conversion rate will initially equal 7.2265 shares of our common stock per $1,000 principal amount of the 2045 Cheniere Convertible Senior Notes, which corresponds to an initial conversion price of approximately $138.38 per share of our common stock. The conversion rate is subject to adjustment upon the occurrence of certain specified events. We have the option to satisfy the conversion obligation with cash, common stock or a combination thereof.

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Cheniere Holdings

Cheniere Holdings was formed by us to hold our Cheniere Partners limited partner interests, thereby allowing us to segregate our lower risk, stable, cash flow generating assets from our higher risk, early stage development projects and marketing activities. As of September 30, 2016, we had an 80.1% direct ownership interest in Cheniere Holdings. We receive dividends on our Cheniere Holdings shares from the distributions that Cheniere Holdings receives from Cheniere Partners, and we receive management fees for managing Cheniere Holdings. We received $11.1 million and $11.0 million in dividends on our Cheniere Holdings common shares during the nine months ended September 30, 2016 and 2015, respectively, and $0.8 million of management fees from Cheniere Holdings during each of the nine months ended September 30, 2016 and 2015.

Cheniere Partners
 
Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. As of September 30, 2016, we own 80.1% of Cheniere Holdings, which owns a 55.9% limited partner interest in Cheniere Partners in the form of 11,963,488 common units, 45,333,334 Class B units and 135,383,831 subordinated units. We also own 100% of the general partner interest and the incentive distribution rights in Cheniere Partners.
 
Prior to the initial public offering by Cheniere Holdings, we received quarterly equity distributions from Cheniere Partners related to our limited partner and 2% general partner interests. We will continue to receive quarterly equity distributions from Cheniere Partners related to our 2% general partner interest, and we receive fees for providing services to Cheniere Partners, SPLNG, SPL and CTPL. We received $1.5 million in distributions on our general partner interest during each of the nine months ended September 30, 2016 and 2015, and we received $100.1 million and $66.4 million in total service fees from Cheniere Partners, SPLNG, SPL and CTPL, during the nine months ended September 30, 2016 and 2015, respectively.

Cheniere Partners’ common unit and general partner distributions are being funded from accumulated operating surplus. We have not received distributions on our subordinated units with respect to the quarters ended on or after June 30, 2010. Cheniere Partners will not make distributions on our subordinated units until it generates additional cash flow from SPLNG, SPL, CTPL or other new business, which would be used to make quarterly distributions on our subordinated units before any increase in distributions to the common unitholders.

Cheniere Partners’ 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 Cheniere Partners Class B units are not entitled to cash distributions except in the event of a liquidation of Cheniere Partners, a merger, consolidation or other combination of Cheniere Partners with another person or the sale of all or substantially all of the assets of Cheniere Partners. On a quarterly basis beginning on the initial purchase 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 an additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere Holdings and Blackstone CQP Holdco LP (“Blackstone CQP Holdco”) was 1.80 and 1.77, respectively, as of September 30, 2016. We expect the Class B units to mandatorily convert into common units within 90 days of the substantial completion date of Train 3 of the SPL Project, which Cheniere Partners currently expects to occur before June 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. The holders of Class B units have a preference over the holders of the subordinated units 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.
  
The Class B units were issued at a discount to the market price of the Cheniere Partners common units into which they are convertible.  This discount, totaling $2,130.0 million, represents a beneficial conversion feature.  The beneficial conversion feature is similar to a dividend that will be distributed 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, including our equity interest in Cheniere Partners. Cheniere Partners amortizes the beneficial conversion feature assuming a conversion date of August 2017, although actual conversion may occur prior to or after this assumed date. Deemed dividends represented by the amortization of the beneficial conversion feature allocated to the Class B units held by Blackstone CQP Holdco are included in net loss attributable to non-controlling interest and result in a reduction of income available to common stockholders. The impact to net loss attributable to non-controlling interest due to the amortization of the beneficial conversion feature was $6.8 million and $9.3 million during the three and nine months ended September 30, 2016, respectively. The anticipated impact to net loss attributable to non-controlling interest due to the amortization of the beneficial conversion feature based on the assumed

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conversion date and ownership interest as of September 30, 2016, is approximately $33 million and $725 million, respectively, for the years ended December 31, 2016 and 2017.

LNG Terminal Business

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 SPL Project. SPL entered into a partial TUA assignment agreement with Total, whereby SPL will progressively gain access to Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement will provide SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Trains 5 and 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of Train 3 and permit SPL to more flexibly manage its LNG storage capacity with the commencement of Train 1. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA.

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

Liquefaction Facilities

The SPL Project is being developed and constructed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. 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. In May 2016 and September 2016, Trains 1 and 2 achieved substantial completion, respectively. Construction of Trains 3 and 4 and the related facilities commenced in May 2013. In June 2015, we commenced construction of Train 5 and the related facilities. In October 2016, the previously announced planned outage to improve performance of the flare systems at the SPL Project, as well as to perform scheduled maintenance to Train 1 and other facilities, was completed on schedule and budget.

The DOE has authorized the export of domestically produced LNG by vessel from Trains 1 through 4 of the Sabine Pass LNG terminal to FTA countries for a 30-year term, which commenced on May 15, 2016, and to non-FTA countries for a 20-year term, which commenced on June 3, 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas). The DOE further issued orders authorizing SPL to export domestically produced LNG by vessel from Trains 1 through 4 of the Sabine Pass LNG terminal to FTA countries for a 25-year term and non-FTA countries for a 20-year term, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas. Additionally, the DOE issued orders authorizing us to export domestically produced LNG by vessel from Trains 5 and 6 of the Sabine Pass LNG terminal to FTA countries and non-FTA countries for a 20-year term, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa). A party to the proceedings requested rehearings of the orders above related to the export of 803 Bcf/yr, 203 Bcf/yr and 503.3 Bcf/yr to non-FTA countries. The DOE issued orders denying rehearing of the orders related to 803 Bcf/yr and 503.3 Bcf/yr but has not yet issued a final ruling on the rehearing request related to the 203 Bcf/yr. In July 2016, the same party petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the DOE order related to the export of 503.3 Bcf/yr to non-FTA countries and the order denying the request for rehearing of the same. The appeal is pending. 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 five to 10 years from the date the order was issued. In addition, we have a three-year makeup period with respect to each of the non-FTA orders for LNG volumes we were unable to export during the initial 20-year export period of

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such order. Furthermore, in January 2016, the DOE issued an order authorizing us to export domestically produced LNG by vessel from the Sabine Pass LNG terminal to FTA countries and non-FTA countries over a two-year period commencing on January 15, 2016, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports to non-FTA countries under this order, when combined with exports to non-FTA countries under the orders related to Trains 1 through 4 above, may not exceed 1,006 Bcf/yr).

As of September 30, 2016, Trains 1 and 2 of the SPL Project had achieved substantial completion. As of September 30, 2016, the overall project completion percentage for Trains 3 and 4 of the SPL Project was approximately 91.8%.  As of September 30, 2016, the overall project completion percentage for Train 5 of the SPL Project was approximately 42.8% with engineering, procurement, subcontract work and construction approximately 90.8%, 62.0%, 41.9% and 4.6% complete, respectively.  As of September 30, 2016, the overall project completion of each of our Trains was ahead of the contractual schedule.  We produced our first LNG from Train 1 of the SPL Project in February 2016 and achieved substantial completion in May 2016. We produced our first LNG from Train 2 of the SPL Project in August 2016 and achieved substantial completion in September 2016. Based on our current construction schedule, Trains 3 and 4 are expected to achieve substantial completion in 2017 and Train 5 is expected to achieve substantial completion in 2019.

Customers

SPL has entered into six fixed price, 20-year SPAs with third parties to make available an aggregate amount of LNG that equates to approximately 19.75 mtpa of LNG, which is approximately 88% of the expected aggregate nominal production capacity of Trains 1 through 5. The obligation to make LNG available under the SPAs commences from the date of first commercial delivery for Trains 1 through 5, as specified in each SPA. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee (a portion of which is subject to annual adjustment for inflation) per MMBtu of LNG plus a variable fee equal to 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 the contracted volumes that are not delivered as a result of such cancellation or suspension. 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 a specified Train.

In aggregate, the fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion annually for Trains 1 through 5, with the applicable fixed fees starting from the date of first commercial delivery from 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 SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers.

Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing volatility in natural gas needs for the SPL Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the SPL Project. As of September 30, 2016, SPL has secured up to approximately 1,982.0 million MMBtu of natural gas feedstock through long-term natural gas supply contracts.

Construction

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“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, the EPC contract for Trains 3 and 4 and the EPC Contract for Train 5 of the SPL Project are approximately $4.1 billion, $3.9 billion and $3.0 billion, respectively, reflecting amounts incurred under change orders through September 30, 2016. Total expected capital costs for Trains 1 through 5 are estimated to be between

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$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.

Final Investment Decision on Train 6

We will contemplate making an FID to commence construction of Train 6 of the SPL 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 SPL Project will be financed through one or more of the following: borrowings, equity contributions from Cheniere Partners and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the 2015 SPL Credit Facilities, available commitments under the SPL Working Capital Facility (as defined below) and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 5 of the SPL Project and to meet our currently anticipated capital, operating and debt service requirements. SPL began generating cash flows from operations from the SPL Project in May 2016, when Train 1 achieved substantial completion and initiated operating activities. Additionally, during the three and nine months ended September 30, 2016, we realized offsets to LNG terminal costs of $68.3 million and $214.3 million, respectively, that were related to the sale of commissioning cargoes because these amounts were earned prior to the start of commercial operations, during the testing phase for the construction of Trains 1 and 2 of the SPL Project.
    
Senior Secured Notes

As of September 30, 2016, Cheniere Partners’ subsidiaries had nine series of senior secured notes outstanding:
$1.7 billion of 2016 SPLNG Senior Notes;
$0.4 billion of 2020 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”);
$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, the 2024 SPL Senior Notes, the 2026 SPL Senior Notes and the 2027 SPL Senior Notes, the “SPL Senior Notes”);
$1.5 billion of 2026 SPL Senior Notes; and
$1.5 billion of 2027 SPL Senior Notes.

Interest on the SPL 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.


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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.

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 (the “SPL Indenture”), 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.

On October 14, 2016, SPLNG issued a notice of redemption to redeem all of its outstanding 2020 SPLNG Senior Notes. The redemption date will be November 30, 2016 (the “Redemption Date”) and the price will be equal to 103.250% of the principal amount of the 2020 SPLNG Senior Notes, plus accrued and unpaid interest and additional interest, if any, on the 2020 SPLNG Senior Notes to, but not including, the Redemption Date. Concurrently with the redemption of the 2020 SPLNG Senior Notes, SPLNG intends to repay all of its outstanding 2016 SPLNG Senior Notes, which mature on the Redemption Date, at a price equal to 100% of the principal amount of the 2016 SPLNG Senior Notes, plus accrued and unpaid interest and additional interest, if any, on the 2016 SPLNG Senior Notes to, but not including, the Redemption Date. The redemption of the 2020 SPLNG Senior Notes and the repayment of the 2016 SPLNG Senior Notes will be funded with borrowings under the 2016 CQP Credit Facilities Cheniere Partners entered into in February 2016, as further described below.

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 SPL Indenture, SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied. During the nine months ended September 30, 2016 and 2015, SPLNG made distributions of $230.4 million and $267.9 million, respectively, after satisfying all the applicable conditions in the SPLNG Indentures.

The SPL Indenture includes 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 SPL 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. During 2016, in conjunction with the issuance of the 2026 SPL Senior Notes and the 2027 SPL Senior Notes, SPL prepaid outstanding borrowings and terminated commitments under the 2015 SPL Credit Facilities for approximately $2.6 billion. These prepayments and termination of commitments resulted in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $25.8 million and $51.8 million during the three and nine months ended September 30, 2016, respectively. As of September 30, 2016, SPL had $2.0 billion of available commitments and no 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 SPL

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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 SPL Working Capital Facility.

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. Additionally, SPL may not make any distributions until certain conditions have been met, including that deposits are made into debt service reserve accounts and a debt service coverage ratio test of 1.25:1.00 is satisfied.

2013 SPL Credit Facilities

 In May 2013, SPL entered into four credit facilities aggregating $5.9 billion (collectively, 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 SPL Project. 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

In May 2013, CTPL entered into the CTPL Term Loan, which was used to fund modifications to the Creole Trail Pipeline and for general business purposes. In February 2016, CTPL prepaid the full amount of $400.0 million outstanding under the CTPL Term Loan with capital contributions from Cheniere Partners, which in turn was funded with borrowings under the 2016 CQP Credit Facilities. This prepayment resulted in a write-off of unamortized discount and debt issuance costs of $1.5 million during the nine months ended September 30, 2016.

2016 CQP Credit Facilities

In February 2016, Cheniere Partners entered into the 2016 CQP Credit Facilities. The 2016 CQP Credit Facilities consist of: (1) a $450.0 million CTPL tranche term loan that was used to prepay the $400.0 million CTPL Term Loan in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that will be used to redeem or repay the approximately $2.1 billion of the 2016 SPLNG Senior Notes and the 2020 SPLNG Senior Notes (which must be redeemed or repaid concurrently under the terms of the 2016 CQP Credit Facilities ), (3) the $125.0 million DSR Facility that may be used to satisfy a six-month debt service reserve requirement and (4) a $115.0 million revolving credit facility that may be used for general business purposes. As of September 30, 2016, Cheniere Partners had $2.3 billion of available commitments, $7.5 million aggregate amount of issued letters of credit and $450.0 million of outstanding borrowings under the 2016 CQP Credit Facilities.

The 2016 CQP Credit Facilities accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and adjusted one month LIBOR plus 1.0%), plus the applicable margin. The applicable margin for LIBOR loans is 2.25% per annum, and the applicable margin for base rate loans is 1.25% per annum, in each case with a 0.50% step-up beginning on February 25, 2019. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

Cheniere Partners incurred $48.7 million of debt issuance costs during the nine months ended September 30, 2016, and will incur an additional $21.5 million of debt issuance costs when the SPLNG tranche is funded. Cheniere Partners pays a commitment fee equal to an annual rate of 40% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears. The DSR Facility and the revolving credit facility are both available for the issuance of letters of credit, which incur a fee equal to an annual rate of 2.25% of the undrawn portion with a 0.50% step-up beginning on February 25, 2019.

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The 2016 CQP Credit Facilities mature on February 25, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit Cheniere Partners’ ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the terms of the 2016 CQP Credit Facilities, Cheniere Partners is required to hedge not less than 50% of the variable interest rate exposure on its projected aggregate outstanding balance, maintain a minimum debt service coverage ratio of at least 1.15x at the end of each fiscal quarter beginning March 31, 2019 and have a projected debt service coverage ratio of 1.55x in order to incur additional indebtedness to refinance a portion of the existing obligations.

The 2016 CQP Credit Facilities are unconditionally guaranteed by each subsidiary of Cheniere Partners other than: (1) SPL, (2) SPLNG until funding of its tranche term loan and (3) certain of the subsidiaries of Cheniere Partners owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

SPL Working Capital Facility

In September 2015, 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 $325.0 million Senior Letter of Credit and Reimbursement Agreement that was entered into in April 2014. The SPL Working Capital Facility is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of 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 SPL 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 SPL Project, request an incremental increase in commitments of up to an additional $390 million. As of September 30, 2016, SPL had $764.5 million of available commitments, $337.0 million aggregate amount of issued letters of credit and $98.5 million of loans outstanding under the SPL Working Capital Facility. As of December 31, 2015, SPL had $1.1 billion of available commitments, $135.2 million aggregate amount of issued letters of credit and $15.0 million of loans outstanding under the SPL Working Capital Facility.

The SPL Working Capital Facility accrues 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 loans under the SPL Working Capital Facility is 1.75% per annum, and the applicable margin for base rate loans under the SPL Working Capital Facility is 0.75% per annum. Interest on Swing Line Loans and loans deemed made in connection with a draw upon a letter of credit (“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 pays (1) a commitment fee equal to an annual rate of 0.70% 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 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, 2016, 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.


40


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 the 2015 SPL Credit Facilities.

Corpus Christi LNG Terminal

Liquefaction Facilities

The CCL Project is being developed and constructed at the Corpus Christi LNG terminal, on nearly 2,000 acres of land that we own or control near Corpus Christi, Texas. In December 2014, we received authorization from the FERC to site, construct and operate Stages 1 and 2 of the CCL Project. In May 2015, we commenced construction of Stage 1 of the CCL Project.

Through the CCL Stage III entities, which are separate from the CCH Group, we are developing two additional Trains and one LNG storage tank at the Corpus Christi LNG terminal adjacent to the CCL Project, along with a second natural gas pipeline, and we commenced the regulatory approval process in June 2015.

The DOE has authorized the export of domestically produced LNG by vessel from the CCL Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term up to a combined total of the equivalent of 767 Bcf/yr (approximately 15 mtpa) of natural gas. Additionally, the DOE has authorized the export of domestically produced LNG by vessel from the two additional Trains being developed adjacent to the CCL Project to FTA countries for a 20-year term in an amount equivalent to 514 Bcf/yr (approximately 10 mtpa) of natural gas. The application for authorization to export that same 514 Bcf/yr of domestically produced LNG by vessel to non-FTA countries is currently pending at the DOE. 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 7 to 10 years from the date the order was issued.

As of September 30, 2016, the overall project completion percentage for Stage 1 of the CCL Project was approximately 43.0% with engineering, procurement and construction approximately 99.3%, 59.0% and 14.4% complete, respectively. The construction of the Corpus Christi Pipeline is planned to commence in early 2017. Based on our current construction schedule, we anticipate that Trains 1 and 2 of the CCL Project will achieve substantial completion in 2019.

Customers

CCL has entered into seven fixed price, 20-year SPAs with six third parties to make available an aggregate amount of LNG that equates to approximately 7.7 mtpa of LNG, which is approximately 86% of the expected aggregate nominal production capacity of Trains 1 and 2. The obligation to make LNG available under these SPAs commences from the date of first commercial delivery for Trains 1 and 2, as specified in each SPA. In addition, CCL has entered into one fixed price, 20-year SPA with a third party for another 0.8 mtpa of LNG that commences with the date of first commercial delivery for Train 3. Under these eight SPAs, the customers will purchase LNG from CCL for a price consisting of a fixed fee of $3.50 (a portion of which is subject to annual adjustment for inflation) per MMBtu of LNG plus a variable fee equal to 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 the contracted volumes that are not delivered as a result of such cancellation or suspension. 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 a specified Train.

In aggregate, the fixed fee portion to be paid by the third-party SPA customers is approximately $1.4 billion annually for Trains 1 and 2, and $1.5 billion if we make a positive FID with respect to Stage 2 of the CCL Project, with the applicable fixed fees starting from the date of first commercial delivery from the applicable Train. These fixed fees equal approximately $550 million, $846 million and $140 million for each of Trains 1 through 3, respectively.

In addition, Cheniere Marketing has entered into SPAs with CCL to purchase, at Cheniere Marketing’s option, any LNG produced by CCL that is not required for other customers.

41



Natural Gas Transportation, Storage and Supply

To ensure CCL is able to transport adequate natural gas feedstock to the Corpus Christi LNG terminal, it has entered into transportation precedent agreements to secure firm pipeline transportation capacity with CCP and certain third-party pipeline companies. CCL has entered into a firm storage services agreement with a third party to assist in managing volatility in natural gas needs for the CCL Project. CCL has also entered into enabling agreements with third parties, and will continue to enter into such agreements, in order to secure natural gas feedstock for the CCL Project. We expect to enter into gas supply contracts under these enabling agreements as and when required for the CCL Project.

Construction

CCL entered into separate lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of Stages 1 and 2 of the CCL Project 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 CCL to enter into a change order, or CCL agrees with Bechtel to a change order.

The total contract prices of the EPC contracts for Stages 1 and 2, which do not include the Corpus Christi Pipeline, are approximately $7.6 billion and $2.4 billion, respectively, reflecting amounts incurred under change orders through September 30, 2016. Total expected capital costs for Stages 1 and 2 are estimated to be between $12.0 billion and $13.0 billion before financing costs, and between $15.0 billion and $16.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies. Total expected capital costs for Stage 1 only are estimated to be between $9.0 billion and $10.0 billion before financing costs, and between $11.0 billion and $12.0 billion after financing costs including, in each case, estimated owner’s costs and contingencies.

Final Investment Decision on Stage 2

We will contemplate making an FID to commence construction of Stage 2 of the CCL Project based upon, among other things, entering into acceptable commercial arrangements and obtaining adequate financing to construct the facility.

Capital Resources

We expect to finance the construction costs of the CCL Project from one or more of the following: project financing, operating cash flow from CCL and CCP and equity contributions from Cheniere.

2025 CCH HoldCo II Convertible Senior Notes

In May 2015, CCH HoldCo II issued $1.0 billion aggregate principal amount of 11% Convertible Senior Secured Notes due 2025 (the “2025 CCH HoldCo II Convertible Senior Notes”) on a private placement basis. The $1.0 billion principal of the 2025 CCH HoldCo II Convertible Senior Notes will be used to partially fund costs associated with Stage 1 of the CCL Project and the Corpus Christi Pipeline. The 2025 CCH HoldCo II Convertible Senior Notes bear interest at a rate of 11.0% per annum, which is payable quarterly in arrears. Prior to the substantial completion of Train 2 of the CCL Project, interest on the 2025 CCH HoldCo II Convertible Senior Notes will be paid entirely in kind. Following this date, the interest generally must be paid in cash; however, a portion of the interest may be paid in kind under certain specified circumstances. The 2025 CCH HoldCo II Convertible Senior Notes are secured by a pledge by us of 100% of the equity interests in CCH HoldCo II, and a pledge by CCH HoldCo II of 100% of the equity interests in CCH HoldCo I.

At CCH HoldCo II’s option, the outstanding 2025 CCH HoldCo II Convertible Senior Notes are convertible into our common stock, provided that our total market capitalization at that time is not less than $10.0 billion, on or after the later of (1) 58 months from May 1, 2015, and (2) the substantial completion of Train 2 of the CCL Project (the “Eligible Conversion Date”). The conversion price for 2025 CCH HoldCo II Convertible Senior Notes converted at CCH HoldCo II’s option is the lower of (1) a 10% discount to the average of the daily volume-weighted average price (“VWAP”) of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided, and (2) a 10% discount to the closing price of our common stock on the trading day preceding the date on which notice of conversion is provided. At the option of the holders, the 2025 CCH HoldCo II Convertible Senior Notes are convertible on or after the six-month anniversary of the Eligible Conversion Date at a

42


conversion price equal to the average of the daily VWAP of our common stock for the 90 trading day period prior to the date on which notice of conversion is provided. Conversions are also subject to various limitations and conditions.

CCH HoldCo II is restricted from making distributions to Cheniere under agreements governing its indebtedness generally until, among other requirements, Trains 1 and 2 of the CCL Project are in commercial operation and a historical debt service coverage ratio and a projected fixed debt service coverage ratio of 1.20:1.00 are achieved.

2024 CCH Senior Notes

In May 2016, CCH issued an aggregate principal amount of $1.25 billion of the 2024 CCH Senior Notes. Borrowings under the 2024 CCH Senior Notes accrue interest at a fixed rate of 7.000%, and interest on the 2024 CCH Senior Notes is payable semi-annually in arrears.

The indenture governing the 2024 CCH Senior Notes (the “CCH Indenture”) contains customary terms and events of default and certain covenants that, among other things, limit CCH’s ability and the ability of CCH’s restricted subsidiaries to: incur additional indebtedness or issue preferred stock; make certain investments or pay dividends or distributions on membership interests or subordinated indebtedness or purchase, redeem or retire membership interests; sell or transfer assets, including membership or partnership interests of CCH’s restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries to CCH or any of CCH’s restricted subsidiaries; incur liens; enter into transactions with affiliates; dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of the properties or assets of CCH and its restricted subsidiaries taken as a whole; or permit any guarantor to dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of its properties and assets.

At any time prior to January 1, 2024, CCH may redeem all or a part of the 2024 CCH Senior Notes at a redemption price equal to the “make-whole” price set forth in the CCH Indenture, plus accrued and unpaid interest, if any, to the date of redemption. CCH also may at any time on or after January 1, 2024 through the maturity date of June 30, 2024, redeem the 2024 CCH Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2024 CCH Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

2015 CCH Credit Facility

In May 2015, CCH entered into the 2015 CCH Credit Facility, which is being used to fund a portion of the costs associated with the development, construction, operation and maintenance of Stage 1 of the CCL Project and the Corpus Christi Pipeline. Borrowings under the 2015 CCH Credit Facility 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. In May 2016, in conjunction with the issuance of the 2024 CCH Senior Notes, CCH prepaid approximately $1.1 billion of outstanding borrowings under the 2015 CCH Credit Facility. This prepayment resulted in a write-off of debt issuance costs associated with the 2015 CCH Credit Facility of $29.0 million during the nine months ended September 30, 2016. As of September 30, 2016, CCH had $4.1 billion of available commitments and $3.3 billion of outstanding borrowings under the 2015 CCH Credit Facility.

The principal of the loans made under the 2015 CCH Credit Facility must be repaid in quarterly installments, commencing on the earlier of (1) the first quarterly payment date occurring more than three calendar months following project completion and (2) a set date determined by reference to the date under which a certain LNG buyer linked to Train 2 of the CCL Project is entitled to terminate its SPA for failure to achieve the date of first commercial delivery for that agreement. Scheduled repayments will be based upon a 19-year tailored amortization, commencing the first full quarter after the project completion and designed to achieve a minimum projected fixed debt service coverage ratio of 1.55:1.

Loans under the 2015 CCH Credit Facility accrue interest at a variable rate per annum equal to, at CCH’s election, LIBOR or the base rate, plus the applicable margin. The applicable margins for LIBOR loans are 2.25% prior to completion of Trains 1 and 2 of the CCL Project and 2.50% on completion and thereafter. The applicable margins for base rate loans are 1.25% prior to completion Trains 1 and 2 of the CCL Project and 1.50% on completion and thereafter. Interest on LIBOR loans is due and payable at the end of each applicable interest period and interest on base rate loans is due and payable at the end of each quarter. The 2015 CCH Credit Facility also requires CCH to pay a commitment fee at a rate per annum equal to 40% of the margin for LIBOR loans, multiplied by the outstanding undrawn debt commitments.

The obligations of CCH under the 2015 CCH Credit Facility are secured by a first priority lien on substantially all of the assets of CCH and its subsidiaries and by a pledge by CCH HoldCo I of its limited liability company interests in CCH.

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Under the terms of the 2015 CCH Credit Facility, CCH is required to hedge not less than 65% of the variable interest rate exposure of its senior secured debt. CCH is restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, the completion of the construction of Trains 1 and 2 of the CCL Project, funding of a debt service reserve account equal to six months of debt service and achieving a historical debt service coverage ratio and fixed projected debt service coverage ratio of at least 1.25:1.00.
LNG and Natural Gas Marketing Business
 
Cheniere Marketing is engaged in the LNG and natural gas marketing business and is developing a portfolio of long-term, short-term and spot LNG SPAs. Cheniere Marketing has purchased, transported and unloaded commercial LNG cargoes into the Sabine Pass LNG terminal and other LNG terminals worldwide and has used trading strategies intended to maximize margins on these cargoes. Cheniere Marketing has secured the following rights and obligations to support its business:
pursuant to an SPA with SPL, the right to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers;
pursuant to SPAs with CCL, the right to purchase, at Cheniere Marketing’s option, any LNG produced by CCL that is not required for other customers; and
a portfolio of LNG vessel time charters.
In addition, as of September 30, 2016, Cheniere Marketing has sold approximately 500 million MMBtu of LNG to be delivered to counterparties between 2016 and 2023, with delivery obligations conditional in certain circumstances.  The cargoes have been sold with a portfolio of delivery points, either on a Free on Board basis (delivered to the counterparty at the Sabine Pass LNG terminal) or a Delivered at Terminal (“DAT”) basis (delivered to the counterparty at their LNG receiving terminal). Cheniere Marketing has chartered LNG vessels to be utilized in DAT transactions. In addition, Cheniere Marketing has entered into a long-term agreement to sell LNG cargoes on a DAT basis.  The agreement is conditioned upon the buyer achieving certain milestones, including reaching an FID related to certain projects and obtaining related financing.

Cheniere Marketing entered into uncommitted trade finance facilities for up to $470.0 million primarily for the purchase of natural gas, LNG or other energy products for ultimate resale in the course of its business. The finance facilities are intended to be used for advances, guarantees or the issuance of letters of credit or standby letters of credit on behalf of Cheniere Marketing. As of September 30, 2016, Cheniere Marketing had $18.8 million in loans and $5.8 million in standby letters of credit and guarantees outstanding under the finance facilities. Cheniere Marketing pays interest or fees on utilized commitments.

Corporate and Other Activities
 
We are required to maintain corporate and general and administrative functions to serve our business activities described above.  We are also in various stages of developing other projects which, among other things, will require acceptable commercial and financing arrangements before we make an FID. We have proposed the development of a pipeline with expected capacity of up to 1.4 Bcf/d connecting new gas production in the Anadarko Basin to Gulf Coast markets, including markets serving the SPL Project and the CCL Project. We expect the regulatory pre-filing process to commence imminently and to file formal applications for the required regulatory permits in 2017. We are also exploring the development of a midscale liquefaction project using electric drive modular Trains, with an expected aggregate nominal production capacity of approximately 9.5 mtpa of LNG.

44


Sources and Uses of Cash

The following table (in thousands) summarizes the sources and uses of our cash, cash equivalents and restricted cash for the nine months ended September 30, 2016 and 2015. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table. 
 
Nine Months Ended September 30,
 
2016
 
2015
Operating cash flows
 
 
 
Net cash used in operating activities
$
(199,027
)
 
$
(274,577
)
Changes in restricted cash for certain operating activities
(119,831
)
 
(92,589
)
Cash, cash equivalents and restricted cash used in operating activities
(318,858
)

(367,166
)
 
 
 
 
Investing cash flows
 
 
 
Net cash used in investing activities
(12,206
)
 
(528,588
)
Use of restricted cash for the acquisition of property, plant and equipment
(3,488,263
)
 
(5,330,526
)
Cash, cash equivalents and restricted cash used in investing activities
(3,500,469
)
 
(5,859,114
)
 
 
 
 
Financing cash flows
 

 
 

Net cash provided by financing activities
253

 
395,844

Investment in restricted cash
3,931,648

 
5,161,701

Cash, cash equivalents and restricted cash provided by financing activities
3,931,901

 
5,557,545

 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
112,574


(668,735
)
Cash, cash equivalents and restricted cash—beginning of period
1,736,231

 
2,780,131

Cash, cash equivalents and restricted cash—end of period
$
1,848,805

 
$
2,111,396


Operating Cash Flows

Operating cash flows during the nine months ended September 30, 2016 and 2015 were $318.9 million and $367.2 million, respectively. The decrease in operating cash outflows in 2016 compared to 2015 primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the commencement of operations of Trains 1 and 2 of the SPL Project in May and September 2016, respectively, and increased cash payout for phantom unit awards.

Investing Cash Flows

Investing cash flows during the nine months ended September 30, 2016 and 2015 were $3.5 billion and $5.9 billion, respectively, and are primarily used to fund the construction costs for Trains 1 through 5 of the SPL Project and Trains 1 and 2 of the CCL Project. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally, during the nine months ended September 30, 2016 and 2015, we used $51.3 million and $111.5 million, respectively, primarily to pay municipal water districts for water system enhancements that will increase potable water supply to our export terminals, payments made for capital assets purchased pursuant to information technology services agreements, collateral payments for the CCL Project and for investments made in unconsolidated entities.

Financing Cash Flows

Financing cash flows during the nine months ended September 30, 2016 were $3.9 billion, primarily as a result of:
$450.0 million of borrowings under the 2016 CQP Credit Facilities, which was entered into in February 2016 to prepay the $400.0 million CTPL Term Loan;
$1.6 billion of borrowings under the 2015 CCH Credit Facility;
issuance of an aggregate principal amount of $1.3 billion of the 2024 CCH Senior Notes in May 2016, which were used to prepay $1.1 billion of the outstanding borrowings under the 2015 CCH Credit Facility;
$1.7 billion of borrowings under the 2015 SPL Credit Facilities;

45


issuance of an aggregate principal amount of $1.5 billion of the 2026 SPL Senior Notes in June 2016, which was used to prepay $1.3 billion of the outstanding borrowings under the 2015 SPL Credit Facilities;
issuance of an aggregate principal amount of $1.5 billion of the 2027 SPL Senior Notes in September 2016, which was used to prepay $1.2 billion of the outstanding borrowings under the 2015 SPL Credit Facilities and pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the SPL Project;
$18.8 million of borrowings under the Cheniere Marketing trade finance facilities;
$313.5 million of borrowings and a $230.0 million repayment made under the SPL Working Capital Facility;
$116.7 million of debt issuance and deferred financing costs related to up-front fees paid upon the closing of these transactions;
$60.2 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings; and
$18.6 million paid for tax withholdings for share-based compensation.

Financing cash flows during the nine months ended September 30, 2015 were $5.6 billion, primarily as a result of:
issuance of an aggregate principal amount of $2.0 billion of the 2025 SPL Senior Notes in March 2015;
issuance of an aggregate principal amount of $625.0 million of the 2045 Cheniere Convertible Senior Notes in March 2015, with an original issue discount of 20% for net proceeds of $495.7 million;
issuance of an aggregate principal amount of $1.0 billion of the 2025 CCH HoldCo II Convertible Senior Notes in May 2015;
entering into the 2015 CCH Credit Facility in May 2015 and borrowing $2.4 billion under this facility during the nine months ended September 30, 2015;
entering into the 2015 SPL Credit Facilities in June 2015 and borrowing $250.0 million under this facility during the nine months ended September 30, 2015;
$519.7 million of debt issuance and deferred financing costs related to up-front fees paid upon the closing of these transactions;
$60.2 million of distributions and dividends to non-controlling interest by Cheniere Partners and Cheniere Holdings; and
$44.3 million paid for tax withholdings for share-based compensation.

Results of Operations

Our consolidated net loss attributable to common stockholders was $100.4 million, or $0.44 per share (basic and diluted), in the three months ended September 30, 2016, compared to a net loss attributable to common stockholders of $297.8 million, or $1.31 per share (basic and diluted), in the three months ended September 30, 2015. This $197.4 million decrease in net loss in 2016 was primarily a result of decreased derivative loss, net, and increased income from operations, which was partially offset by increased interest expense, net of amounts capitalized, and restructuring expense.

Our consolidated net loss attributable to common stockholders was $719.7 million, or $3.15 per share (basic and diluted), in the nine months ended September 30, 2016, compared to a net loss attributable to common stockholders of $684.0 million, or $3.02 per share (basic and diluted), in the nine months ended September 30, 2015. This $35.7 million increase in net loss in 2016 was primarily a result of increased interest expense, net of amounts capitalized, and restructuring expense, which was partially offset by decreased loss from operations.

Revenues
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2016
 
2015
 
Change
 
2016
 
2015
 
Change
Regasification revenues
$
66,970

 
$
66,597

 
$
373

 
$
198,143

 
$
199,888

 
$
(1,745
)
LNG revenues (losses)
398,554

 
(1,557
)
 
400,111

 
511,993

 
(1,601
)
 
513,594

Other revenues
149

 
1,019

 
(870
)
 
1,445

 
4,166

 
(2,721
)
Total revenues
$
465,673

 
$
66,059

 
$
399,614

 
$
711,581

 
$
202,453

 
$
509,128


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We began recognizing LNG revenues from the SPL Project following the substantial completion of Trains 1 and 2 in May and September 2016, respectively. Prior to these dates, amounts received from the sale of commissioning cargoes were offset against LNG terminal construction-in-process because these amounts were earned during the testing phase for the construction of those Trains of the SPL Project. During the three and nine months ended September 30, 2016, we loaded a total of 60.3 million MMBtu and 113.8 million MMBtu of LNG, respectively, of which 50.8 million MMBtu and 69.0 million MMBtu, respectively, resulted in the recognition of revenues related to this volume. The remaining 9.5 million MMBtu and 44.8 million MMBtu of LNG loaded during the three and nine months ended September 30, 2016, respectively, were recognized as offsets to LNG terminal costs as they related to the sale of commissioning cargoes. Additionally, LNG revenues included revenues from Cheniere Marketing of $123.5 million and $163.3 million for the three and nine months ended September 30, 2016, respectively, as well as derivative gains and losses related to commodity and foreign currency exchange derivatives.

Operating costs and expenses
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2016
 
2015
 
Change
 
2016
 
2015
 
Change
Cost (cost recovery) of sales
$
252,343

 
$
(24,214
)
 
$
276,557

 
$
352,559

 
$
(22,077
)
 
$
374,636

Operating and maintenance expense
61,610

 
17,963

 
43,647

 
143,489

 
71,396

 
72,093

Development expense
1,546

 
4,935

 
(3,389
)
 
4,709

 
37,640

 
(32,931
)
Selling, general and administrative expense
59,418

 
97,332

 
(37,914
)
 
196,999

 
263,205

 
(66,206
)
Depreciation and amortization expense
49,212

 
21,638

 
27,574

 
106,082

 
59,561

 
46,521

Restructuring expense
26,241

 

 
26,241

 
49,196

 

 
49,196

Impairment expense

 
396

 
(396
)
 
10,095

 
572

 
9,523

Other
27

 
83

 
(56
)
 
189

 
348

 
(159
)
Total operating costs and expenses
$
450,397

 
$
118,133

 
$
332,264

 
$
863,318

 
$
410,645

 
$
452,673


Our total operating costs and expenses increased $332.3 million and $452.7 million during the three and nine months ended September 30, 2016 compared to the three and nine months ended September 30, 2015, respectively, primarily as a result of the commencement of operations of Trains 1 and 2 of the SPL Project in May and September 2016, respectively, compared to a significant cost recovery recorded during the three and nine months ended September 30, 2015. This cost recovery was due to a $32.2 million increase in fair value for our natural gas supply contracts recorded for the period, which we recognized following the completion and placement into service of certain modifications to the underlying pipeline infrastructure and the resulting development of a market for physical gas delivery at locations specified in a portion of our natural gas supply contracts. Cost of sales includes costs incurred directly for the production and delivery of LNG from the SPL Project such as natural gas feedstock, variable transportation and storage costs, derivative gains and losses associated with economic hedges to secure natural gas feedstock for the SPL Project, and other related costs to convert natural gas into LNG, all to the extent not utilized for the commissioning process, as well as cost of sales related to our LNG and natural gas marketing business by Cheniere Marketing. Included in cost of sales during the three and nine months ended September 30, 2016 was vessel charter costs of $20.8 million and $36.9 million, respectively, which were incurred throughout the period, including the period prior to substantial completion of Trains 1 and 2 of the SPL Project. Operating and maintenance expense includes costs associated with operating and maintaining the SPL Project such as third-party service and maintenance contract costs, payroll and benefit costs of operations personnel, natural gas transportation and storage capacity demand charges, derivative gains and losses related to the sale and purchase of LNG associated with the regasification terminal, insurance and regulatory costs. Depreciation and amortization expense increased during the three and nine months ended September 30, 2016 as we began depreciation of our assets related to Trains 1 and 2 of the SPL Project upon reaching substantial completion. Additionally, in 2015, we initiated certain organizational changes to simplify our corporate structure, improve our operational efficiencies and implement a strategy for sustainable, long-term stockholder value creation through financially disciplined development, construction, operation and investment.  As a result of these efforts, we recorded $26.2 million and $49.2 million of restructuring charges and other costs associated with restructuring and operational efficiency initiatives during the three and nine months ended September 30, 2016, respectively.

Offsetting the increases above was a decrease in selling, general and administrative expense, which was primarily due to the timing of share-based compensation recognition and the recognition of certain employee-related costs within restructuring expense during the three and nine months ended September 30, 2016 historically reported in selling, general and administrative expense, a reduction in certain professional services fees and reallocation of costs from selling, general and administrative activities to operating and maintenance activities following commencement of operations at the SPL Project. Development expense also decreased during the three and nine months ended September 30, 2016 compared to the three and nine months ended September 30, 2015, due to an FID made on Train 5 of the SPL Project in June 2015 and an FID made on Trains 1 and 2 of the CCL Project in May 2015.


47


Other expense (income)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2016
 
2015
 
Change
 
2016
 
2015
 
Change
Interest expense, net of capitalized interest
$
148,053

 
$
93,566

 
$
54,487

 
$
330,357

 
$
238,664

 
$
91,693

Loss on early extinguishment of debt
25,765

 

 
25,765

 
82,537

 
96,273

 
(13,736
)
Derivative loss (gain), net
(29,327
)
 
161,482

 
(190,809
)
 
242,228

 
242,123

 
105

Other expense (income)
(437
)
 
39

 
(476
)
 
5,564

 
(616
)
 
6,180

Total other expense
$
144,054

 
$
255,087

 
$
(111,033
)
 
$
660,686

 
$
576,444

 
$
84,242


Interest expense, net of capitalized interest, increased $54.5 million and $91.7 million in the three and nine months ended September 30, 2016, as compared to the three and nine months ended September 30, 2015, primarily as a result of an increase in our indebtedness outstanding (before premium, discount and unamortized debt issuance costs), from $16.3 billion as of September 30, 2015 to $21.5 billion as of September 30, 2016, and the decrease in the portion of total interest costs that could be capitalized as Trains 1 and 2 of the SPL Project were no longer in construction. For the three and nine months ended September 30, 2016, we incurred $340.8 million and $951.3 million of total interest cost, respectively, of which we capitalized $192.7 million and $620.9 million, respectively, which were directly related to the construction of the SPL Project and the CCL Project. For the three and nine months ended September 30, 2015, we incurred $286.0 million and $707.8 million of total interest cost, respectively, of which we capitalized $192.4 million and $469.2 million, respectively, which were directly related to the construction of the SPL Project and the CCL Project.

Loss on early extinguishment of debt increased $25.8 million in the three months ended September 30, 2016, as compared to the three months ended September 30, 2015 whereas it decreased $13.7 million in the nine months ended September 30, 2016, as compared to the nine months ended September 30, 2015. Loss on early extinguishment of debt during the three months ended September 30, 2016 was attributable to the $25.8 million write-off of debt issuance costs related to the prepayment of outstanding borrowings and termination of commitments under the 2015 SPL Credit Facilities of approximately $1.4 billion in September 2016 in connection with the issuance of the 2027 SPL Senior Notes. Loss on early extinguishment of debt during the nine months ended September 30, 2016 further included a $29.0 million write-off of debt issuance costs related to the prepayment of approximately $1.1 billion of outstanding borrowings under the 2015 CCH Credit Facility in May 2016 in connection with the issuance of the 2024 CCH Senior Notes, a $26.0 million write-off of debt issuance costs related to the prepayment of approximately $1.3 billion of outstanding borrowings under the 2015 SPL Credit Facilities in June 2016 in connection with the issuance of the 2026 SPL Senior Notes, and a $1.5 million write-off of debt issuance costs and unamortized discount in connection with the prepayment of the CTPL Term Loan in February 2016. Loss on early extinguishment of debt during the nine months ended September 30, 2015 was attributable to a $7.3 million write-off of debt issuance costs and deferred commitment fees related to the termination and replacement of the 2013 SPL Credit Facilities with the 2015 SPL Credit Facilities in June 2015 and a $89.0 million write-off of debt issuance costs and deferred commitment fees related to the termination of approximately $1.8 billion of commitments under the 2013 SPL Credit Facilities in March 2015.

Derivative loss (gain), net decreased $190.8 million from a loss of $161.5 million in the three months ended September 30, 2015 to a gain of $29.3 million in the three months ended September 30, 2016, primarily due to a relative increase in the forward LIBOR curve in the three months ended September 30, 2016 as compared to the three months ended September 30, 2015. Derivative loss, net did not significantly change between the nine months ended September 30, 2016 and 2015. Derivative loss, net during the nine months ended September 30, 2016 was primarily due to a decrease in the forward LIBOR curve during the period and an increase in the notional amounts of our interest rate derivatives. Derivative loss, net recognized during the nine months ended September 30, 2015 was primarily due to a decrease in the forward LIBOR curve during the period, the loss incurred upon meeting the contingency related to the CCH Interest Rate Derivatives and the loss recognized upon the termination of interest rate swaps associated with approximately $1.8 billion of commitments that were terminated under the 2013 SPL Credit Facilities.

Other
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2016
 
2015
 
Change
 
2016
 
2015
 
Change
Income tax provision (benefit)
$
1,638

 
$
(69
)
 
$
1,707

 
$
1,911

 
$
102

 
$
1,809

Net loss attributable to non-controlling interest
(29,974
)
 
(9,284
)
 
(20,690
)
 
(94,636
)
 
(100,726
)
 
6,090


Net loss attributable to non-controlling interest increased $20.7 million in the three months ended September 30, 2016 as compared to the three months ended September 30, 2015, primarily as a result of the increase in consolidated net loss recognized by Cheniere Partners in which the non-controlling interest is held. The consolidated net loss recognized by Cheniere Partners increased from $24.1 million in the three months ended September 30, 2015 to $81.5 million in the three months ended September

48


30, 2016 primarily due to increased interest expense, net of amounts capitalized, and increased loss on early extinguishment of debt, partially offset by decreased derivative loss and increased income from operations primarily as a result of the commencement of operations of Trains 1 and 2 of the SPL Project. Net loss attributable to non-controlling interest decreased $6.1 million in the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015, primarily due to increased income from operations, decreased loss on early extinguishment of debt and decreased derivative loss, net, which were partially offset by increased interest expense, net of amounts capitalized.

Off-Balance Sheet Arrangements
 
As of September 30, 2016, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results. 

Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes.  There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the year ended December 31, 2015.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 19—Recent Accounting Standards of our Notes to Consolidated Financial Statements.

ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Cash Investments
 
We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation of capital. Such cash investments are stated at historical cost, which approximates fair market value on our Consolidated Balance Sheets.
 
Marketing and Trading Commodity Price Risk

We have entered into commodity derivatives consisting of natural gas supply contracts to secure natural gas feedstock for the SPL Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the basis price for natural gas for each delivery location. As of September 30, 2016, we estimated the fair value of the Liquefaction Supply Derivatives to be $12.1 million. Based on actual derivative contractual volumes, a 10% increase or decrease in the underlying basis prices would have resulted in a change in the fair value of the Liquefaction Supply Derivatives of $0.2 million as of September 30, 2016, compared to $0.9 million as of December 31, 2015. See Note 6—Derivative Instruments for additional details about our derivative instruments.

We have also entered into financial derivatives to hedge the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (“LNG Trading Derivatives”). In order to test the sensitivity of the fair value of the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the basis price for LNG. As of September 30, 2016, we estimated the fair value of the LNG Trading Derivatives to be a liability of $0.3 million. Based on actual derivative contractual volumes, a 10% increase or decrease in the underlying basis price would have resulted in a change in the fair value of the LNG Trading Derivatives of $4.4 million as of September 30, 2016, whereas it was immaterial as of December 31, 2015. See Note 6—Derivative Instruments for additional details about our derivative instruments.

Interest Rate Risk

SPL has entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 SPL Credit Facilities (“SPL Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the SPL Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining term of the SPL Interest Rate Derivatives. As of September 30, 2016, we estimated the fair value of the SPL Interest Rate Derivatives to be a liability of $15.9 million. This 10% change in interest rates would have resulted in a change in the fair value of the SPL Interest Rate Derivatives of $1.6 million as of September 30, 2016, compared to $3.1 million as of

49


December 31, 2015. The decrease in the effect of change in interest rates was due to a decrease in the forward 1-month LIBOR curve during the nine months ended September 30, 2016.

Cheniere Partners has entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2016 CQP Credit Facilities (“CQP Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the CQP Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining term of the CQP Interest Rate Derivatives. As of September 30, 2016, we estimated the fair value of the CQP Interest Rate Derivatives to be a liability of $12.2 million. This 10% change in interest rates would have resulted in a change in the fair value of the CQP Interest Rate Derivatives of $3.9 million as of September 30, 2016.

CCH has entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 CCH Credit Facility (“CCH Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the CCH Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining term of the CCH Interest Rate Derivatives. As of September 30, 2016, we estimated the fair value of the CCH Interest Rate Derivatives to be a liability of $297.5 million. This 10% change in interest rates would have resulted in a change in the fair value of the CCH Interest Rate Derivatives of $38.8 million as of September 30, 2016, compared to $55.6 million as of December 31, 2015. The decrease in the effect of change in interest rates was due to a decrease in the forward 1-month LIBOR curve during the nine months ended September 30, 2016.

Foreign Currency Exchange Risk

We have entered into foreign currency exchange (“FX”) contracts to hedge exposure to currency risk associated with operations in countries outside of the United States (“FX Derivatives”). In order to test the sensitivity of the fair value of the FX Derivatives to changes in FX rates, management modeled a 10% change in FX rate between the U.S. dollar and the applicable foreign currencies. As of September 30, 2016, we estimated the fair value of the FX Derivatives to be a liability of $1.2 million. This 10% change in FX rates would have resulted in a change in the fair value of the FX Derivatives of $0.1 million as of September 30, 2016.

ITEM 4.
CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


50


PART II. OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.

Louisiana Department of Environmental Quality (“LDEQ”) Matter

Please see Part II, Item 1, “Legal Proceedings - LDEQ Matter” in the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2016.

Parallax Litigation

In 2015, Cheniere Energy Inc.’s (“CEI”) wholly owned subsidiary, Cheniere LNG Terminals, LLC (“CLNGT”), entered into discussions with Parallax Enterprises, LLC (“Parallax Enterprises”) regarding the potential joint development of two liquefaction plants in Louisiana (the “Potential Liquefaction Transactions”). While the parties negotiated regarding the Potential Liquefaction Transactions, CLNGT loaned Parallax Enterprises approximately $46 million, as reflected in a secured note dated April 23, 2015, as amended on June 30, 2015, September 30, 2015 and November 4, 2015 (the “Secured Note”). The Secured Note was secured by all assets of Parallax Enterprises and its subsidiary entities. On June 30, 2015, Parallax Enterprises’ parent entity, Parallax Energy LLC (“Parallax Energy”), executed a Pledge and Guarantee Agreement further securing repayment of the Secured Note by providing a parent guaranty and a pledge of all of the equity of Parallax Enterprises in satisfaction of the Secured Note (the “Pledge Agreement”). CLNGT and Parallax Enterprises never executed a definitive agreement to pursue the Potential Liquefaction Transactions. The Secured Note matured on December 11, 2015, and Parallax Enterprises failed to make payment. On February 3, 2016, CLNGT filed an action against Parallax Energy, Parallax Enterprises, and certain of Parallax Enterprises’ subsidiary entities, styled Cause No. 4:16-cv-00286, Cheniere LNG Terminals, LLC v. Parallax Energy LLC, et al., in the United States District Court for the Southern District of Texas (the “Texas Suit”). CLNGT asserted claims in the Texas Suit for (1) recovery of all amounts due under the Secured Note and (2) declaratory relief establishing that CLNGT is entitled to enforce its rights under the Secured Note and Pledge Agreement in accordance with each instrument’s terms and that CLNGT has no obligations of any sort to Parallax Enterprises concerning the Potential Liquefaction Transactions. On March 11, 2016, Parallax Enterprises and the other defendants in the Texas Suit moved to dismiss the suit for lack of subject matter jurisdiction. On August 2, 2016, the court denied the defendants’ motion to dismiss without prejudice and permitted the parties to pursue jurisdictional discovery, which is ongoing.

On March 11, 2016, Parallax Enterprises filed a suit against CEI and CLNGT styled Civil Action No. 62-810, Parallax Enterprises LLP v. Cheniere Energy, Inc. and Cheniere LNG Terminals, LLC, in the 25th Judicial District Court of Plaquemines Parish, Louisiana (the “Louisiana Suit”), wherein Parallax Enterprises asserted claims for breach of contract, fraudulent inducement, negligent misrepresentation, detrimental reliance, unjust enrichment and violation of the Louisiana Unfair Trade Practices Act. Parallax Enterprises predicated its claims in the Louisiana Suit on an allegation that CEI and CLNGT breached a purported agreement to jointly develop the Potential Liquefaction Transactions. Parallax Enterprises sought $400 million in alleged economic damages and rescission of the Secured Note. On April 15, 2016, CEI and CLNGT removed the Louisiana Suit to the United States District Court for the Eastern District of Louisiana, which subsequently transferred the Louisiana Suit to the United States District Court for the Southern District of Texas, where it was assigned Civil Action No. 4:16-cv-01628 and transferred to the same judge presiding over the Texas Suit for coordinated handling. On August 22, 2016, Parallax Enterprises voluntarily dismissed all claims asserted against CLNGT and CEI in the Louisiana Suit without prejudice to refiling. CEI does not expect that the resolution of this litigation will have a material adverse impact on its financial results.

ITEM 1A.
RISK FACTORS
 
There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2015.


51


ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended September 30, 2016:
Period
 
Total Number of Shares Purchased (1)
 
Average Price Paid Per Share (2)
 
Total Number of Shares Purchased as a Part of Publicly Announced Plans
 
Maximum Number of Units That May Yet Be Purchased Under the Plans
July 1 - 31, 2016
 
13,307

 
$38.71
 
 
August 1 - 31, 2016
 
345,200

 
$42.13
 
 
September 1 - 30, 2016
 

 
$—
 
 
Total
 
358,507

 
 
 
 
 
(1)
Represents shares surrendered to us by participants in our share-based compensation plans to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under these plans.
(2)
The price paid per share was based on the closing trading price of our common stock on the dates on which we repurchased shares from the participants under our share-based compensation plans.

ITEM 5.
OTHER INFORMATION

Compliance Disclosure

Pursuant to Section 13(r) of the Exchange Act, if during the quarter ended September 30, 2016, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our quarterly report on Form 10-Q as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012. During the quarter ended September 30, 2016, we did not engage in any transactions with Iran or with persons or entities related to Iran.


52


ITEM 6.
EXHIBITS
Exhibit No.
 
Description
3.1
 
Amendment No. 1 to the Amended and Restated Bylaws of Cheniere Energy, Inc., dated September 15, 2016 (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on September 19, 2016)
4.1
 
Eighth Supplemental Indenture, dated as of September 19, 2016, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 23, 2016)
4.2
 
Ninth Supplemental Indenture, dated as of September 23 2016, between Sabine Pass Liquefaction, LLC and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.2 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 23, 2016)
10.1†
 
Release Agreement between Cheniere Energy, Inc. and Meg A. Gentle, dated August 26, 2016 (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 001-16383), filed on August 26, 2016)
10.2
 
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00048 N2 Supply for High Pressure Tightness Test During Commissioning and Startup, dated July 12, 2016, (ii) the Change Order CO-00050 Train 2 N2 Dryout, dated July 29, 2016, (iii) the Change Order CO-00051 Six-Day Work Week for Insulation Scope — Subproject 2, dated August 9, 2016, and (iv) the Change Order CO-00052 Process Flares Modification Provisional Sum, dated September 1, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.1 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on November 2, 2016)
10.3
 
Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00024 Additional Support for FERC Document Requests, dated June 20, 2016, (ii) the Change Order CO-00025 N2 Supply for High Pressure Tightness Test During Commissioning and Startup, dated July 12, 2016, (iii) the Change Order CO-00027 Addition of Check Valves to Condensate Lines, dated July 29, 2016, (iv) the Change Order CO-00028 Additional Professional Services Support Hours for the Flare System Evaluation, dated August 3, 2016, and (v) the Change Order CO-00029 Lump Sum Process Flares Modification, dated September 1, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.) (Incorporated by reference to Exhibit 10.2 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on November 2, 2016)
10.4
 
Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00011 Site Drainage Design Change: Professional Service Hours, dated July 26, 2016 (Incorporated by reference to Exhibit 10.3 to SPL’s Quarterly Report on Form 10-Q (SEC File No. 333-192373), filed on November 2, 2016)
10.5*
 
Change orders to the Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Stage 1 Liquefaction Facility, dated as of December 6, 2013, between Corpus Christi Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00022 Permanent Plant Building Modifications, dated June 20, 2016 and (ii) the Change Order CO-00024 N2 Dewar Interface, Temporary Power to Air Cooler, Condensate Pipeline Maximum Allowable Operating Pressure, dated June 28, 2016 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)
10.6
 
Registration Rights Agreement, dated as of September 23, 2016, between Sabine Pass Liquefaction, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated (Incorporated by reference to Exhibit 10.1 to Cheniere Partners’ Current Report on Form 8-K (SEC File No. 001-33366), filed on September 23, 2016)
31.1*
 
Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*
 
Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**
 
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**
 
Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*
 
XBRL Instance Document
101.SCH*
 
XBRL Taxonomy Extension Schema Document
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document

53


Exhibit No.
 
Description
101.DEF*
 
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
 
XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*
 
XBRL Taxonomy Extension Presentation Linkbase Document
 
*
Filed herewith.
**
Furnished herewith.
Management contract or compensatory plan or arrangement.


54



SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
 
CHENIERE ENERGY, INC.
 
 
 
 
Date:
November 2, 2016
By:
/s/ Michael J. Wortley
 
 
 
Michael J. Wortley
 
 
 
Executive Vice President and Chief Financial Officer
 
 
 
(on behalf of the registrant and
as principal financial officer)
 
 
 
 
Date:
November 2, 2016
By:
/s/ Leonard Travis
 
 
 
Leonard Travis
 
 
 
Vice President and Chief Accounting Officer
 
 
 
(on behalf of the registrant and
as principal accounting officer)


55