Exhibit 99.1


ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
CHENIERE ENERGY PARTNERS, L.P.



1


Report of Independent Registered Public Accounting Firm

To the Unitholders of Cheniere Energy Partners, L.P. and
Board of Directors of Cheniere Energy Partners GP, LLC:

Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Cheniere Energy Partners, L.P. and subsidiaries (the Partnership) as of December 31, 2017 and 2016, the related consolidated statements of operations, partners’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2017, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 20, 2018 (not included herein) expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 3 to the consolidated financial statements, the Partnership has changed its method of accounting for revenue recognition in 2017, 2016 and 2015 due to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto.
Basis for Opinion
These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP

We have served as the Partnership’s auditor since 2014.

Houston, Texas
February 20, 2018, except as to Notes 12 and 20 which are as of June 15, 2018


2


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES


CONSOLIDATED BALANCE SHEETS
(in millions, except unit data)
 
 
December 31,
 
 
2017
 
2016
ASSETS
 

 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$

 
$

Restricted cash
 
1,589

 
605

Accounts and other receivables
 
191

 
90

Accounts receivable—affiliate
 
163

 
99

Advances to affiliate
 
36

 
38

Inventory
 
95

 
97

Other current assets
 
65

 
29

Total current assets
 
2,139

 
958

 
 
 
 
 
Property, plant and equipment, net
 
15,139

 
14,158

Debt issuance costs, net
 
38

 
121

Non-current derivative assets
 
31

 
83

Other non-current assets, net
 
206

 
222

Total assets
 
$
17,553

 
$
15,542

 
 
 
 
 
LIABILITIES AND PARTNERS’ EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
12

 
$
27

Accrued liabilities
 
637

 
418

Current debt
 

 
224

Due to affiliates
 
68

 
99

Deferred revenue
 
111

 
73

Deferred revenue—affiliate
 
1

 
1

Derivative liabilities
 

 
14

Total current liabilities
 
829

 
856

 
 
 
 
 
Long-term debt, net
 
16,046

 
14,209

Non-current deferred revenue
 
1

 
5

Non-current derivative liabilities
 
3

 
2

Other non-current liabilities
 
10

 

Other non-current liabilities—affiliate
 
25

 
27

 
 
 
 
 
Commitments and contingencies (see Note 16)
 

 

 
 
 
 
 
Partners’ equity
 
 
 
 
Common unitholders’ interest (348.6 million units and 57.1 million units issued and outstanding at December 31, 2017 and 2016, respectively)
 
1,670

 
130

Class B unitholders’ interest (zero and 145.3 million units issued and outstanding at December 31, 2017 and 2016, respectively)
 

 
62

Subordinated unitholders’ interest (135.4 million units issued and outstanding at December 31, 2017 and 2016)
 
(1,043
)
 
240

General partner’s interest (2% interest with 9.9 million units and 6.9 million units issued and outstanding at December 31, 2017 and 2016, respectively)
 
12

 
11

Total partners’ equity
 
639


443

Total liabilities and partners’ equity
 
$
17,553

 
$
15,542


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

3


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per unit data)
 
Year Ended December 31,
 
2017
 
2016
 
2015
Revenues
 
 
 
 
 
LNG revenues
$
2,635

 
$
539

 
$

LNG revenues—affiliate
1,389

 
294

 

Regasification revenues
260

 
259

 
259

Other revenues
20

 
4

 
7

Other revenues—affiliate

 
4

 
4

Total revenues
4,304

 
1,100

 
270

 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)
2,320

 
410

 
(31
)
Cost of sales—affiliate

 
2

 

Operating and maintenance expense
292

 
127

 
62

Operating and maintenance expense—affiliate
100

 
52

 
29

Development expense
3

 

 
3

Development expense—affiliate

 

 
1

General and administrative expense
12

 
13

 
15

General and administrative expense—affiliate
80

 
90

 
122

Depreciation and amortization expense
339

 
156

 
66

Other
2

 

 

Total operating costs and expenses
3,148

 
850

 
267

 
 
 
 
 
 
Income from operations
1,156

 
250

 
3

 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
Interest expense, net of capitalized interest
(614
)
 
(357
)
 
(185
)
Loss on early extinguishment of debt
(67
)
 
(72
)
 
(96
)
Derivative gain (loss), net
4

 
6

 
(42
)
Other income
11

 
2

 
1

Total other expense
(666
)
 
(421
)
 
(322
)
 
 
 
 
 
 
Net income (loss)
$
490

 
$
(171
)
 
$
(319
)
 
 
 
 
 
 
Basic and diluted net loss per common unit
$
(1.32
)
 
$
(0.20
)
 
$
(0.43
)
 
 
 
 
 
 
Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation
178.5

 
57.1

 
57.1





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

4


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY
(in millions)
 
Common Unitholders’ Interest
 
Class B Unitholders’ Interest
 
Subordinated Unitholder’s Interest
 
General Partner’s Interest
 
Total Partners’ Equity
 
Units
 
Amount
 
Units
 
Amount
 
Units
 
Amount
 
Units
 
Amount
 
Balance at December 31, 2014
57.1

 
$
496

 
145.3

 
$
(38
)
 
135.4

 
$
648

 
6.9

 
$
25

 
$
1,131

Net loss

 
(93
)
 

 

 

 
(220
)
 

 
(6
)
 
(319
)
Distributions

 
(97
)
 

 

 

 

 

 
(2
)
 
(99
)
Amortization of beneficial conversion feature of Class B units

 

 

 
1

 

 
(1
)
 

 

 

Balance at December 31, 2015
57.1

 
306

 
145.3

 
(37
)
 
135.4

 
427

 
6.9

 
17

 
713

Net loss

 
(50
)
 

 

 

 
(117
)
 

 
(4
)
 
(171
)
Distributions

 
(97
)
 

 

 

 

 

 
(2
)
 
(99
)
Amortization of beneficial conversion feature of Class B units

 
(29
)
 

 
99

 

 
(70
)
 

 

 

Balance at December 31, 2016
57.1

 
130

 
145.3

 
62

 
135.4

 
240

 
6.9

 
11

 
443

Net income

 
294

 

 

 

 
186

 

 
10

 
490

Distributions

 
(226
)
 

 

 

 
(59
)
 

 
(9
)
 
(294
)
Conversion of Class B units into common units
291.5

 
2,066

 
(145.3
)
 
(2,066
)
 

 

 
3.0

 

 

Amortization of beneficial conversion feature of Class B units

 
(594
)
 

 
2,004

 

 
(1,410
)
 

 

 

Balance at December 31, 2017
348.6

 
$
1,670

 

 
$

 
135.4

 
$
(1,043
)
 
9.9

 
$
12

 
$
639




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

5


CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
Year Ended December 31,
 
2017
 
2016
 
2015
Cash flows from operating activities
 
 
 
 
 
Net income (loss)
$
490

 
$
(171
)
 
$
(319
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
 
 
Non-cash LNG inventory write-downs

 

 
18

Depreciation and amortization expense
339

 
156

 
66

Amortization of debt issuance costs, deferred commitment fees, premium and discount
36

 
30

 
12

Loss on early extinguishment of debt
67

 
72

 
96

Total losses (gains) on derivatives, net
20

 
(48
)
 
7

Net cash used for settlement of derivative instruments
(16
)
 
(8
)
 
(41
)
Other
8

 
1

 

Changes in operating assets and liabilities:
 
 
 
 
 
Accounts and other receivables
(101
)
 
(90
)
 

Accounts receivable—affiliate
(62
)
 
(98
)
 
1

Advances to affiliate
(12
)
 

 
(13
)
Inventory
13

 
(58
)
 
(25
)
Accounts payable and accrued liabilities
210

 
167

 
(1
)
Due to affiliates
(42
)
 
11

 
15

Deferred revenue
34

 
42

 
(4
)
Other, net
(5
)
 
(7
)
 
(11
)
Other, net—affiliate
(2
)
 
1

 
28

Net cash provided by (used in) operating activities
977

 

 
(171
)
 
 
 
 
 
 
Cash flows from investing activities
 

 
 

 
 
Property, plant and equipment, net
(1,290
)
 
(2,315
)
 
(2,913
)
Other

 
(38
)
 
(62
)
Net cash used in investing activities
(1,290
)
 
(2,353
)
 
(2,975
)
 
 
 
 
 
 
Cash flows from financing activities
 

 
 

 
 
Proceeds from issuances of debt
3,814

 
8,003

 
2,860

Repayments of debt
(2,173
)
 
(5,251
)
 

Debt issuance and deferred financing costs
(50
)
 
(115
)
 
(170
)
Debt extinguishment costs

 
(14
)
 

Distributions to owners
(294
)
 
(99
)
 
(99
)
Net cash provided by financing activities
1,297

 
2,524

 
2,591

 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
984

 
171

 
(555
)
Cash, cash equivalents and restricted cash—beginning of period
605

 
434

 
989

Cash, cash equivalents and restricted cash—end of period
$
1,589

 
$
605

 
$
434



Balances per Consolidated Balance Sheets:
 
December 31,
 
2017
 
2016
Cash and cash equivalents
$

 
$

Restricted cash
1,589

 
605

Total cash, cash equivalents and restricted cash
$
1,589

 
$
605




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

6


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




 
NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We are a publicly traded Delaware limited partnership (NYSE American: CQP) formed by Cheniere. Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. Through our wholly owned subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We also own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through CTPL.

As of December 31, 2017, Cheniere owned 100% of our general partner interest and 82.7% of Cheniere Holdings, which owned 104.5 million of our common units and 135.4 million of our subordinated units.

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

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

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights (“IDRs”), which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus after the initial quarterly distributions have been achieved and as additional target levels are met, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.
 
During 2012, Blackstone CQP Holdco and Cheniere completed their purchases of a new class of equity interests representing limited partner interests in us (“Class B units”) for total consideration of $1.5 billion and $500 million, respectively. Proceeds from the financings were used to fund a portion of the costs of developing, constructing and placing into service the first two Trains of the Liquefaction Project. In May 2013, Cheniere purchased an additional 12.0 million Class B units for consideration of $180 million in connection with our acquisition of CTPL and Cheniere Pipeline GP Interests, LLC.  In 2013, Cheniere formed Cheniere Holdings to hold its limited partner interests in us. On a quarterly basis beginning on the date of the initial purchase date of the Class B units, the conversion value of the Class B units increased at a compounded rate of 3.5% per quarter.

On August 2, 2017, the 45.3 million Class B units held by Cheniere Holdings and 100.0 million Class B units held by Blackstone CQP Holdco mandatorily converted into our common units in accordance with the terms of our partnership agreement. Upon conversion of the Class B units, Cheniere Holdings, Blackstone CQP Holdco and the public owned a 48.6%, 40.3% and 9.1% interest in us, respectively. Cheniere Holdings’ ownership percentage includes its subordinated units and Blackstone CQP Holdco’s ownership percentage excludes any common units that may be deemed to be beneficially owned by Blackstone Group, an affiliate of Blackstone CQP Holdco.

7


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




NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Cheniere Partners and its majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto (“ASC 606”) using the full retrospective method. We have elected to adopt the new accounting standard retrospectively and have recast the accompanying consolidated financial statements to reflect the adoption of ASC 606 for all periods presented. The adoption of ASC 606 did not impact our previously reported consolidated financial statements in any prior period nor did it result in a cumulative effect adjustment to retained earnings.

Use of Estimates
 
The preparation of 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. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, derivative instruments, asset retirement obligations (“AROs”) and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 8—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 11—Debt, are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial assets and liabilities initially measured at fair value include intangible assets and AROs.
 
Revenue Recognition
 
We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale of LNG are recognized as LNG revenues. LNG regasification capacity payments are recognized as regasification revenues. We also recognize tug services fees, which were historically included in regasification revenues but are now included within other revenues on our Consolidated Statements of Operations, that are received by Sabine Pass Tug Services, LLC (“Tug Services”), a wholly owned subsidiary of SPLNG. See Note 12—Revenues from Contracts with Customers for further discussion of revenues.


8


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



Cash and Cash Equivalents
 
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
 
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.

Accounts Receivable

Accounts receivable is reported net of allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses.  The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral.  We did not recognize any bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

Inventory

LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued. During the year ended December 31, 2015, we recognized $18 million as operating and maintenance expense as a result of write-down for LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. We did not recognize any operating and maintenance expense related to inventory write-downs during the years ended December 31, 2017 and 2016.

Accounting for LNG Activities
 
Generally, we begin capitalizing the costs of our LNG terminals and related pipelines once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminals and related pipelines.
 
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.
 
We capitalize interest and other related debt costs during the construction period of our LNG terminal and related pipeline. Upon commencement of operations, capitalized interest, as a component of the total cost, is amortized over the estimated useful life of the asset.

Property, Plant and Equipment 

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in other operating costs and expenses.
 
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for

9


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



which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.  We did not record any impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 and 2015, respectively.

Regulated Natural Gas Pipelines 

The Creole Trail Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities. 

Items that may influence our assessment are: 
inability to recover cost increases due to rate caps and rate case moratoriums;  
inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;  
excess capacity;  
increased competition and discounting in the markets we serve; and  
impacts of ongoing regulatory initiatives in the natural gas industry.
Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2017, 2016 and 2015. See Note 8—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk
 
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.


10


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



The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. Certain of our commodity derivative transactions 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. Collateral deposited for such contracts is recorded as other current asset. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

SPL has entered into six fixed price SPAs with terms of at least 20 years with six unaffiliated third parties. SPL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 17—Customer Concentration for additional details about our customer concentration.
 
SPLNG has entered into two long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal. SPLNG is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective TUAs. SPLNG has mitigated this credit risk by securing TUAs for a significant portion of its regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of A.

Debt

Our debt consists of current and long-term secured debt securities and credit facilities with banks and other lenders.  Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.  

Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment of debt are recorded in gains and losses on the extinguishment of debt on our Consolidated Statements of Operations.

Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are recorded as a direct deduction from the debt liability unless incurred in connection with a line of credit arrangement, in which case they are presented as an asset on our Consolidated Balance Sheet. Debt issuance costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on early extinguishment of debt.

Asset Retirement Obligations
 
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our assessment of AROs is described below.
 
We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.

We have not recorded an ARO associated with the Creole Trail Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.

11


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




Income Taxes 

We are not subject to federal or state income taxes, as our partners are taxed individually on their allocable share of our taxable income. At December 31, 2017, the tax basis of our assets and liabilities was $3.1 billion less than the reported amounts of our assets and liabilities. See Note 13—Related Party Transactions for details about income taxes under our tax sharing agreements.

Business Segment

Our liquefaction and regasification operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of Cheniere Partners in total when evaluating financial performance and for purposes of allocating resources.

NOTE 4—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 December 31, 2017 and 2016, restricted cash consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Current restricted cash
 
 
 
 
Liquefaction Project
 
$
544

 
$
358

CQP and cash held by guarantor subsidiaries
 
1,045

 
247

Total current restricted cash
 
$
1,589

 
$
605


NOTE 5—ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2017 and 2016, accounts and other receivables consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
SPL trade receivable
 
$
185

 
$
88

Other accounts receivable
 
6

 
2

Total accounts and other receivables
 
$
191

 
$
90


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 Liquefaction Project and other restricted payments.

NOTE 6—INVENTORY

As of December 31, 2017 and 2016, inventory consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Natural gas
 
$
17

 
$
15

LNG
 
26

 
45

Materials and other
 
52

 
37

Total inventory
 
$
95

 
$
97



12


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



NOTE 7—PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in millions):
 
 
December 31,
 
 
2017
 
2016
LNG terminal costs
 
 
 
 
LNG terminal
 
$
12,703

 
$
7,976

LNG terminal construction-in-process
 
3,310

 
6,728

Accumulated depreciation
 
(880
)
 
(553
)
Total LNG terminal costs, net
 
15,133

 
14,151

Fixed assets
 
 

 
 

Fixed assets
 
23

 
20

Accumulated depreciation
 
(17
)
 
(13
)
Total fixed assets, net
 
6

 
7

Property, plant and equipment, net
 
$
15,139

 
$
14,158

 

Depreciation expense was $331 million, $148 million and $65 million in the years ended December 31, 2017, 2016 and 2015, respectively.

We realized offsets to LNG terminal costs of $301 million and $201 million in the years ended December 31, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction.

LNG Terminal Costs

The Sabine Pass LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows:
Components
 
Useful life (yrs)
LNG storage tanks
 
50
Natural gas pipeline facilities
 
40
Marine berth, electrical, facility and roads
 
35
Regasification processing equipment
 
30
Sendout pumps
 
20
Liquefaction processing equipment
 
6-50
Other
 
15-30

Fixed Assets and Other

Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 8—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 credit facilities (“Interest Rate Derivatives”) and
commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”).


13


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



We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. 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 to the extent not utilized for the commissioning process.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2017 and 2016, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).
 
Fair Value Measurements as of
 
December 31, 2017
 
December 31, 2016
 
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
$

 
$

 
$

 
$

 
$

 
$
(6
)
 
$

 
$
(6
)
CQP Interest Rate Derivatives asset

 
21

 

 
21

 

 
13

 

 
13

Liquefaction Supply Derivatives asset (liability)
2

 
10

 
43

 
55

 
(4
)
 
(2
)
 
79

 
73


We value our Interest Rate Derivatives using an income-based approach, utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using market based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.

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 satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.

We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace. 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 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.

The Level 3 fair value measurements of our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2017:
 
 
Net Fair Value Asset
(in millions)
 
Valuation Approach
 
Significant Unobservable Input
 
Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives
 
$43
 
Market approach incorporating present value techniques
 
Basis Spread
 
$(0.503) - $0.432


14


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



The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Balance, beginning of period
 
$
79

 
$
32

 
$

Realized and mark-to-market gains (losses):
 
 
 
 
 
 
Included in cost of sales (1)
 
(37
)
 
48

 
32

Purchases and settlements:
 
 
 
 
 
 
Purchases
 
14

 
1

 

Settlements (1)
 
(12
)
 
(2
)
 

Transfers out of Level 3
 
(1
)
 

 

Balance, end of period
 
$
43

 
$
79

 
$
32

Change in unrealized gains relating to instruments still held at end of period
 
$
(37
)
 
$
49

 
$
32

 
    
(1)
Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016.

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.  Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

SPL had 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”), based on a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities. In March 2017, SPL settled the SPL Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the 2015 SPL Credit Facilities, as discussed in Note 11—Debt.

We have 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 our $2.8 billion credit facilities (the “2016 CQP Credit Facilities”), based on a portion of the expected outstanding borrowings over the term of the 2016 CQP Credit Facilities.

As of December 31, 2017, 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
CQP Interest Rate Derivatives
 
$225 million
 
$1.3 billion
 
March 22, 2016
 
February 29, 2020
 
1.19%
 
One-month LIBOR


15


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



The following table shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets (in millions):
 
 
December 31, 2017
 
December 31, 2016
 
 
SPL Interest Rate Derivatives
 
CQP Interest Rate Derivatives
 
Total
 
SPL Interest Rate Derivatives
 
CQP Interest Rate Derivatives
 
Total
Balance Sheet Location
 
 
 
 
 
 
 
 
 
 
 
 
Other current assets
 
$

 
$
7

 
$
7

 
$

 
$

 
$

Non-current derivative assets
 

 
14

 
14

 

 
16

 
16

Total derivative assets
 

 
21

 
21

 

 
16

 
16

 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative liabilities
 

 

 

 
(4
)
 
(3
)
 
(7
)
Non-current derivative liabilities
 

 

 

 
(2
)
 

 
(2
)
Total derivative liabilities
 

 

 

 
(6
)
 
(3
)
 
(9
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative asset (liability), net
 
$

 
$
21

 
$
21

 
$
(6
)
 
$
13

 
$
7


The following table 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 years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
SPL Interest Rate Derivatives loss
 
$
(2
)
 
$
(6
)
 
$
(42
)
CQP Interest Rate Derivatives gain
 
6

 
12

 


Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges, if applicable, to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the noncurrent physical natural gas supply contracts range from approximately one to seven years, most of which commence upon the satisfaction of certain conditions precedent, if not already met, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.

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.

SPL had secured up to approximately 2,214 TBtu and 1,994 TBtu of natural gas feedstock through natural gas supply contracts as of December 31, 2017 and 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,520 TBtu and 1,117 TBtu as of December 31, 2017 and 2016, respectively.

The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):
 
 
 
Fair Value Measurements as of (1)
 
Balance Sheet Location
 
December 31, 2017
 
December 31, 2016
Liquefaction Supply Derivatives
Other current assets
 
$
41

 
$
13

Liquefaction Supply Derivatives
Non-current derivative assets
 
17

 
67

Liquefaction Supply Derivatives
Derivative liabilities
 

 
(7
)
Liquefaction Supply Derivatives
Non-current derivative liabilities
 
(3
)
 

 
(1)
Does not include a collateral call of $1 million and a collateral deposit of $6 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2017 and 2016, respectively.




16


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



The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
 
Year Ended December 31,
 
Statement of Operations Location (1)
 
2017
 
2016
 
2015
Liquefaction Supply Derivatives loss (gain) (2)
Cost of sales
 
$
24

 
$
(42
)
 
$
(33
)
 
(1)
Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
(2)
Does not include the realized value associated with derivative instruments that settle through physical delivery.

Consolidated Balance Sheet Presentation

Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):
 
 
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 December 31, 2017
 
 
 
 
 
 
CQP Interest Rate Derivatives
 
$
21

 
$

 
$
21

Liquefaction Supply Derivatives
 
64

 
(6
)
 
58

Liquefaction Supply Derivatives
 
(3
)
 

 
(3
)
As of December 31, 2016
 
 
 
 
 
 
SPL Interest Rate Derivatives
 
$
(6
)
 
$

 
$
(6
)
CQP Interest Rate Derivatives
 
16

 

 
16

CQP Interest Rate Derivatives
 
(3
)
 

 
(3
)
Liquefaction Supply Derivatives
 
82

 
(2
)
 
80

Liquefaction Supply Derivatives
 
(11
)
 
4

 
(7
)

NOTE 9—OTHER NON-CURRENT ASSETS

As of December 31, 2017 and 2016, other non-current assets, net consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Advances made under EPC and non-EPC contracts
 
$
26

 
$
23

Advances made to municipalities for water system enhancements
 
93

 
95

Advances and other asset conveyances to third parties to support LNG terminals
 
30

 
31

Tax-related payments and receivables
 
25

 
28

Information technology service assets
 
24

 
27

Other
 
8

 
18

Total other non-current assets, net
 
$
206

 
$
222


NOTE 10—ACCRUED LIABILITIES
 
As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Interest costs and related debt fees
 
$
253

 
$
205

Sabine Pass LNG terminal and related pipeline costs
 
384

 
211

Other accrued liabilities
 

 
2

Total accrued liabilities
 
$
637

 
$
418



17


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



NOTE 11—DEBT
 
As of December 31, 2017 and 2016, our debt consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Long-term debt:
 
 
 
 
SPL
 
 
 
 
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $6 and $7
 
$
2,006

 
$
2,007

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

 
1,000

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

 
1,506

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

 
2,000

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

 
2,000

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

 
1,500

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

 
1,500

4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero
 
1,349

 

5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)
 
800

 

2015 SPL Credit Facilities
 

 
314

Cheniere Partners
 
 
 
 
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)
 
1,500

 

2016 CQP Credit Facilities
 
1,090

 
2,560

Unamortized debt issuance costs
 
(204
)
 
(178
)
Total long-term debt, net
 
16,046

 
14,209

 
 
 
 
 
Current debt:
 
 
 
 
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)
 

 
224

 
 
 
 
 
Total debt, net
 
$
16,046

 
$
14,433


Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2017 (in millions): 
Years Ending December 31,
 
Principal Payments
2018
 
$

2019
 
55

2020
 
1,035

2021
 
2,000

2022
 
1,000

Thereafter
 
12,150

Total
 
$
16,240


Senior Notes

SPL Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes, after provisioning for incremental interest required during construction, were used to prepay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the

18


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



construction of Trains 1 through 5 of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.
  
In connection with the issuance of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $42 million during the year ended December 31, 2017.

The terms of the 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes and 2028 SPL Senior Notes (collectively with the 2037 SPL Senior Notes, the “SPL Senior Notes”) are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain customary terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. 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. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025. Interest on the SPL Senior Notes is payable semi-annually in arrears.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), 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.

2025 CQP Senior Notes

In September 2017, we issued an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing the release of its guarantee, Sabine Pass LNG-LP, LLC (collectively, the “CQP Guarantors”). Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2016 CQP Credit Facilities of $25 million during the year ended December 31, 2017.

Borrowings under the 2025 CQP Senior Notes accrue interest at a fixed rate of 5.250%, and interest on the 2025 CQP Senior Notes is payable semi-annually in arrears. The 2025 CQP Senior Notes are governed by an indenture (the “CQP Indenture”), which contains customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

At any time prior to October 1, 2020, we may redeem all or a part of the 2025 CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the 2025 CQP Senior Notes redeemed, plus the “applicable premium” set forth in the CQP Indenture, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020, we may redeem up to 35% of the aggregate principal amount of the 2025 CQP Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 105.250% of the aggregate principal amount of the 2025 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. We also may

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at any time on or after October 1, 2020 through the maturity date of October 1, 2025, redeem the 2025 CQP Senior Notes, in whole or in part, at the redemption prices set forth in the CQP Indenture.

The 2025 CQP Senior Notes are our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of our future subordinated debt. The 2025 CQP Senior Notes will be secured alongside the 2016 CQP Credit Facilities on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and our rights and the rights of the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2016 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the 2016 CQP Credit Facilities). The liens securing the 2025 CQP Senior Notes would be released if (1) the aggregate principal amount of all indebtedness then outstanding under the term loans under the 2016 CQP Credit Facilities secured by such liens does not exceed $1.0 billion and (2) the aggregate amount of our secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the 2025 CQP Senior Notes or any other series of notes issued under the CQP Indenture) outstanding at any one time, together with all Attributable Indebtedness (as defined in the CQP Indenture) from sale-leaseback transactions (subject to certain exceptions), does not exceed the greater of (1) $1.5 billion and (2) 10% of net tangible assets. Upon the release of the liens securing the 2025 CQP Senior Notes, the limitation on liens covenant under the CQP Indenture will continue to govern the incurrence of liens by us and the CQP Guarantors.

In connection with the closing of the sale of the 2025 CQP Senior Notes, we and the CQP Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, we and the CQP Guarantors have agreed to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2025 CQP Senior Notes for a like aggregate principal amount of our debt securities with terms identical in all material respects to the 2025 CQP 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 September 18, 2017. Under specified circumstances, we and the CQP Guarantors have also agreed to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2025 CQP Senior Notes. We will be obligated to pay additional interest on the 2025 CQP Senior Notes if we fail to comply with our obligation to register the 2025 CQP Senior Notes within the specified time period.

Credit Facilities

Below is a summary of our credit facilities outstanding as of December 31, 2017 (in millions):
 
 
SPL Working Capital Facility
 
2016 CQP Credit Facilities
Original facility size
 
$
1,200

 
$
2,800

Less:
 
 
 
 
Outstanding balance
 

 
1,090

Commitments prepaid or terminated
 

 
1,470

Letters of credit issued
 
730

 
20

Available commitment
 
$
470


$
220

 
 
 
 
 
Interest rate
 
LIBOR plus 1.75% or base rate plus 0.75%
 
LIBOR plus 2.25% or base rate plus 1.25% (1)
Maturity date
 
December 31, 2020, with various terms for underlying loans
 
February 25, 2020, with principal payments due quarterly commencing on March 31, 2019
 
(1)
There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to an additional $390 million.


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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
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Loans under the SPL Working Capital Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR 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 loans is due and payable at the end of each applicable LIBOR period, and interest on base rate loans is due and payable at the end of each fiscal quarter. However, if such base rate loan is converted into a LIBOR 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 December 31, 2017, no LC Draws had been made upon any letters of credit issued under the SPL Working Capital Facility.

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

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

2016 CQP Credit Facilities

In February 2016, we entered into the 2016 CQP Credit Facilities. The 2016 CQP Credit Facilities consist of: (1) a $450 million CTPL tranche term loan that was used to prepay the $400 million term loan facility (the “CTPL Term Loan”) in February 2016, (2) an approximately $2.1 billion SPLNG tranche term loan that was used to repay and redeem the approximately $2.1 billion of the senior notes previously issued by SPLNG in November 2016, (3) a $125 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 million revolving credit facility that may be used for general business purposes. In September 2017, we issued the 2025 CQP Senior Notes and the net proceeds of the issuance were used to prepay $1.5 billion of the outstanding indebtedness 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.

We pay 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, with principal payments due quarterly commencing on March 31, 2019. 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,

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



as well as customary affirmative and negative covenants and limit our ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the 2016 CQP Credit Facilities, we are 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 of our subsidiaries other than (1) SPL and (2) certain of our subsidiaries owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

Restrictive Debt Covenants

As of December 31, 2017, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

Total interest expense consisted of the following (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Total interest cost
 
$
902

 
$
841

 
$
708

Capitalized interest
 
(288
)
 
(484
)
 
(523
)
Total interest expense, net
 
$
614

 
$
357

 
$
185


Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our debt (in millions):
 
 
December 31, 2017
 
December 31, 2016
 
 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
Senior notes, net of premium or discount (1)
 
$
14,360

 
$
15,485

 
$
11,513

 
$
12,309

2037 SPL Senior Notes (2)
 
800

 
871

 

 

Credit facilities (3)
 
1,090

 
1,090

 
3,098

 
3,098

 
(1)
Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2025 CQP Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
(2)
The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 
(3)
Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty. 


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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
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NOTE 12—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
LNG revenues
 
$
2,615

 
$
535

 
$

LNG revenues—affiliate
 
1,389

 
294

 

Regasification revenues
 
260

 
259

 
259

Other revenues
 
20

 
4

 
7

Other revenues—affiliate
 

 
4

 
4

Total revenues from customers
 
4,284

 
1,096

 
270

Revenues from derivative instruments (1)
 
20

 
4

 

Total revenues
 
$
4,304

 
$
1,100

 
$
270

 
(1)
Relates to the realized value associated with a portion of derivative instruments that settle through physical delivery.

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a Free on Board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the sale was negotiated. We have concluded that the variable fees meet the optional exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the optional exception, variable consideration related to the sale of LNG is also not included in the transaction price.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We

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



have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the optional exception for allocating variable consideration and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6.

Upon substantial completion of Train 3, which was in June 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. 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 and we continue to recognize the payments received from Total as revenue. During the year ended December 31, 2017, SPL recorded $23 million as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” and “Non-current deferred revenue” on our Consolidated Balance Sheets (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Deferred revenues, beginning of period
 
$
78

 
$
36

 
$
40

Cash received but not yet recognized
 
110

 
71

 
25

Revenue recognized from prior period deferral
 
(76
)
 
(29
)
 
(29
)
Deferred revenues, end of period
 
$
112

 
$
78

 
$
36


We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2017 and 2016 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs. Changes in deferred revenue during the years ended December 31, 2017, 2016 and 2015 are also attributable to differences between the timing of revenue recognition and the receipt of advance payments under our TUAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:
 
 
Unsatisfied
Transaction Price
(in billions)
 
Weighted Average Recognition Timing (years) (1)
LNG revenues
 
$
55.7

 
10.2
Regasification revenues
 
2.9

 
5.7
Total revenues
 
$
58.6

 
 
 
    
(1)
The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.


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We have elected the following optional exemptions which omit certain potential future sources of revenue from the table above:
(1)
We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)
We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. During the year ended December 31, 2017, approximately 58% of our LNG revenues, 100% of our LNG revenues—affiliate and approximately 2% of our Regasification revenues were related to variable consideration received from customers.

We have entered into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

NOTE 13—RELATED PARTY TRANSACTIONS
 
Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015 (in millions):
 
Year Ended December 31,
 
2017
 
2016
 
2015
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA
$
1,389

 
$
294

 
$

 
 
 
 
 
 
Other revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG

 
1

 
1

Terminal Marine Services Agreement

 
3

 
3

Total other revenues—affiliate


4

 
4

 
 
 
Cost of sales—affiliate
Fees under the Pre-commercial LNG Marketing Agreement

 
2

 

 
 
 
 
 
 
Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG

 
1

 
1

Services Agreements
94

 
51

 
28

Other agreements
6

 

 

Total operating and maintenance expense—affiliate
100


52

 
29

 
 
 
Development expense—affiliate
Services Agreements

 

 
1

 
 
 
General and administrative expense—affiliate
Services Agreements
80

 
90

 
122



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



LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0 Bcf/d of regasification capacity under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least 20 years after May 2016.

In connection with this TUA, SPL is required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is recorded as operating and maintenance expense on our Consolidated Statements of Operations.

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

In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. Cheniere Investments recorded no revenues—affiliate from Cheniere Marketing during the years ended December 31, 2017, 2016 and 2015, respectively, related to the Amended and Restated VCRA.

Cheniere Marketing SPA

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

Cheniere Marketing Master SPA

SPL has an agreement with Cheniere Marketing that allows the parties to sell and purchase LNG with each other by executing and delivering confirmations under this agreement.

Commissioning Confirmation

Under the Cheniere Marketing Master SPA, SPL executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. had control of, and was commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

SPL has an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on SPL’s behalf to market and sell certain quantities of pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC, one of SPL’s SPA customers. SPL pays a fee to Cheniere Marketing for marketing and transportation, which is based on volume sold under this agreement.

Services Agreements
As of December 31, 2017 and 2016, we had $36 million and $38 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under the services agreements described below are recorded in general and administrative expense—affiliate.


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



Cheniere Partners Services Agreement

We have a services agreement with Cheniere Terminals, a wholly owned subsidiary of Cheniere, pursuant to which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $3 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.

SPLNG O&M Agreement

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

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

SPL O&M Agreement

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

SPL has a management services agreement (the “SPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the SPL O&M Agreement. The services include, among other services, exercising the day-to-day management of SPL’s affairs and business, managing SPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of SPL’s business and operations, entering into financial derivatives on SPL’s behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction Project, SPL pays

27


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



a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, SPL will pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train.

CTPL O&M Agreement

CTPL has an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the CTPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the CTPL O&M Agreement are required to be remitted to such subsidiary.
 
Agreement to Fund SPLNG’s Cooperative Endeavor Agreements (“CEAs”)
 
SPLNG has executed CEAs with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This ten-year initiative represented an aggregate commitment of $25 million in order to aid in their reconstruction efforts following Hurricane Rita, which SPLNG fulfilled in the first quarter of 2016. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to, and in the year the Cameron Parish dollar-for-dollar credit is applied against, ad valorem tax levied on our LNG terminal.

On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of both December 31, 2017 and 2016, we had $25 million of both other non-current assets resulting from SPLNG’s ad valorem tax payments and non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.
 
Contracts for Sale and Purchase of Natural Gas and LNG
 
SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the years ended December 31, 2017, 2016 and 2015.

State Tax Sharing Agreements

SPLNG has a state tax sharing agreement with Cheniere.  Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which SPLNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, SPLNG will pay to Cheniere an amount equal to the state and local tax that SPLNG would be required to pay if its state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment

28


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



from SPLNG under this agreement; therefore, Cheniere has not demanded any such payments from SPLNG. The agreement is effective for tax returns due on or after January 1, 2008.

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

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

NOTE 14—NET LOSS PER COMMON UNIT
 
Net loss per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net loss based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statement of Partners’ Equity. On January 23, 2018, we declared a $0.50 distribution per common unit and subordinated unit and the related distribution to our general partner and IDRs, which was paid on February 14, 2018 to unitholders of record as of February 2, 2018 for the period from October 1, 2017 to December 31, 2017.

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

The Class B units, which were mandatorily converted into our common units in accordance with the terms of our partnership agreement on August 2, 2017, were issued at a discount to the market price of the common units into which they were convertible.  This discount, totaling $2,130 million, represented a beneficial conversion feature and was reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at issuance on our Consolidated Statement of Partners’ Equity.  The beneficial conversion feature was considered a dividend that was distributed ratably with respect to any Class B unit from its issuance date through its conversion date, which resulted in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortized the beneficial conversion feature through the mandatory conversion date of August 2, 2017 using the effective yield method, with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units, respectively. The impact of the beneficial conversion feature was also included in earnings per unit for the years ended December 31, 2017, 2016 and 2015.


29


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



The following table provides a reconciliation of net income (loss) and the allocation of net income (loss) to the common units, the subordinated units, the general partner units and IDRs for purposes of computing net loss per unit (in millions, except per unit data).
 
 
 
 
Limited Partner Units
 
 
 
 
 
 
Total
 
Common Units
 
Class B Units
 
Subordinated Units
 
General Partner Units
 
IDR
Year Ended December 31, 2017
 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
$
490

 
 
 
 
 
 
 
 
 
 
Declared distributions
 
514

 
376

 

 
127

 
10

 
1

Amortization of beneficial conversion feature of Class B units
 

 
(594
)
 
2,004

 
(1,410
)
 

 

Assumed allocation of undistributed net loss (1)
 
$
(24
)
 
(17
)
 

 
(7
)
 

 

Assumed allocation of net income
 
 
 
$
(235
)
 
$
2,004

 
$
(1,290
)
 
$
10

 
$
1

 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average units outstanding
 
 
 
178.5

 
84.8

 
135.4

 
 
 
 
Net loss per unit (2)
 
 
 
$
(1.32
)
 


 
$
(9.52
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 
$
(171
)
 
 
 
 
 
 
 
 
 
 
Declared distributions
 
99

 
97

 

 

 
2

 

Amortization of beneficial conversion feature of Class B units
 

 
(29
)
 
100

 
(71
)
 

 

Assumed allocation of undistributed net loss
 
$
(270
)
 
(79
)
 

 
(186
)
 
(5
)
 

Assumed allocation of net loss
 
 
 
$
(11
)
 
$
100

 
$
(257
)
 
$
(3
)
 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average units outstanding
 
 
 
57.1

 
145.3

 
135.4

 
 
 
 
Net loss per unit (2)
 
 
 
$
(0.20
)
 


 
$
(1.90
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Net loss
 
$
(319
)
 
 
 
 
 
 
 
 
 
 
Declared distributions
 
99

 
97

 

 

 
2

 

Assumed allocation of undistributed net loss
 
$
(418
)
 
(121
)
 

 
(288
)
 
(8
)
 

Assumed allocation of net loss
 
 
 
$
(24
)
 
$

 
$
(288
)
 
$
(6
)
 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average units outstanding
 
 
 
57.1

 
145.3

 
135.4

 
 
 
 
Net loss per unit (2)
 
 
 
$
(0.43
)
 


 
$
(2.13
)
 
 
 
 
 
 
(1)
Under our partnership agreement, the IDRs participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss).
(2)
Earnings per unit in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

NOTE 15—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $13 million, $11 million and $10 million, respectively, related primarily to office space and land sites. Our land site leases for the Sabine Pass LNG terminal have initial terms varying up to 30 years with multiple options to renew up to an additional 60 years.


30


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



Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in millions): 
Years Ending December 31,
Operating Leases (1)
2018
$
2

2019
2

2020
2

2021
2

2022
2

Thereafter
45

Total
$
55

 
(1)
Includes certain lease option renewals that are reasonably assured.

NOTE 16—COMMITMENTS AND CONTINGENCIES
 
We have 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 December 31, 2017, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contract

SPL has a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of Train 5 of the Liquefaction Project. The EPC contract for Train 5 provides that SPL will pay Bechtel a contract price of $3.1 billion, subject to adjustment by change order.  SPL has the right to terminate the EPC contract for its convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date.

Obligations under SPAs

SPL has third-party SPAs which obligate SPL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project.

Obligations under LNG TUAs
 
SPLNG has third-party TUAs with Total Gas & Power North America, Inc. and Chevron U.S.A. Inc. to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG terminal.
 
Obligations under Natural Gas Supply, Transportation and Storage Service Agreements

SPL has index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The terms of these contracts primarily range from approximately one to six years and commence upon the occurrence of conditions precedent, including SPL’s declaration to the respective natural gas supplier that it is ready to commence the term of the supply arrangement in anticipation of the date of first commercial operation of the applicable, specified Trains of the Liquefaction Project. As of December 31, 2017, SPL has secured up to approximately 2,214 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent were met.

Additionally, SPL has transportation and storage service agreements for the Liquefaction Project. The initial terms of the transportation agreements range from one to 20 years, with renewal options for certain contracts, and commences upon the occurrence of conditions precedent. The terms of the SPL storage service agreements range from three to ten years.

31


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




As of December 31, 2017, SPL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions): 
Years Ending December 31,
Payments Due (1)
2018
$
2,274

2019
1,527

2020
1,397

2021
981

2022
336

Thereafter
1,169

Total
$
7,684

 
(1)
Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on prices and basis spreads as of December 31, 2017.

Services Agreements
 
We have certain services agreements with affiliates. See Note 13—Related Party Transactions for information regarding such agreements.
 
Restricted Net Assets
 
At December 31, 2017, our restricted net assets of consolidated subsidiaries were approximately $2.1 billion.

Other Commitments
 
State Tax Sharing Agreements
 
SPLNG, SPL and CTPL have state tax sharing agreements with Cheniere. See Note 13—Related Party Transactions for information regarding such agreements.

Other Agreements

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. Additionally, we have various lease commitments, as disclosed in Note 15—Leases.
 
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. In the opinion of management, as of December 31, 2017, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.


32


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



NOTE 17—CUSTOMER CONCENTRATION
  
The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:
 
 
Percentage of Total Third-Party Revenues
 
Percentage of Accounts Receivable from Third Parties
 
 
Year Ended December 31,
 
December 31,
 
 
2017
 
2016
 
2015
 
2017
 
2016
Customer A
 
39%
 
52%
 
—%
 
39%
 
47%
Customer B
 
27%
 
*
 
—%
 
32%
 
50%
Customer C
 
23%
 
—%
 
—%
 
26%
 
—%
 
* Less than 10%

During the year ended December 31, 2017, revenues from external customers that were derived from domestic customers was $1.4 billion and from customers outside of the United States was $1.5 billion, of which $787 million and $666 million were from customers in Ireland and South Korea, respectively. During the year ended December 31, 2016, revenues from external customers that were derived from domestic customers was $677 million and from customers outside of the United States was $125 million. 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.

NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION
 
The following table provides supplemental disclosure of cash flow information (in millions):
 
Year Ended December 31,
 
2017
 
2016
 
2015
Cash paid during the period for interest, net of amounts capitalized
$
510

 
$
242

 
$
136

Non-cash conveyance of assets

 

 
13


The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $273 million, $267 million and $231 million as of December 31, 2017, 2016 and 2015, respectively.


33


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



NOTE 19—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:
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 provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).
 
January 1, 2018
 
We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Consolidated Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 12—Revenues from Contracts with Customers.
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto
 
This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.
 
January 1, 2019

 
We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases upon our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.
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.

34


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




Additionally, the following table provides a brief description of a recent accounting standard that was adopted by us during the reporting period:
Standard
 
Description
 
Date of Adoption
 
Effect on our Consolidated Financial Statements or Other Significant Matters
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
 
The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.



35


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



NOTE 20—SUPPLEMENTAL GUARANTOR INFORMATION

Our 2025 CQP Senior Notes are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing the release of its guarantee, Sabine Pass LNG-LP, LLC (the “CQP Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the CQP Indenture. See Note 11—Debt for additional information regarding the 2025 CQP Senior Notes.

The following is condensed consolidating financial information for CQP (“Parent Issuer”), the CQP Guarantors on a combined basis and SPL (“Non-Guarantor”). We have accounted for investments in subsidiaries using the equity method.


36


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



Condensed Consolidating Balance Sheet
December 31, 2017
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Parent Issuer
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$

 
$

 
$

 
$

 
$

Restricted cash
1,033

 
12

 
544

 

 
1,589

Accounts and other receivables

 
2

 
189

 

 
191

Accounts receivable—affiliate

 
36

 
163

 
(36
)
 
163

Advances to affiliate

 
20

 
26

 
(10
)
 
36

Inventory

 
10

 
85

 

 
95

Other current assets
8

 
3

 
54

 

 
65

Other current assets—affiliate

 

 
21

 
(21
)
 

Total current assets
1,041

 
83

 
1,082

 
(67
)
 
2,139

 
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
80

 
2,164

 
12,920

 
(25
)
 
15,139

Debt issuance costs, net
20

 

 
18

 

 
38

Non-current derivative assets
14

 

 
17

 

 
31

Investments in subsidiaries
2,076

 
(63
)
 

 
(2,013
)
 

Other non-current assets, net

 
37

 
169

 

 
206

Total assets
$
3,231

 
$
2,221

 
$
14,206

 
$
(2,105
)
 
$
17,553

 
 
 
 
 
 
 
 
 
 
LIABILITIES AND PARTNERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
 
 
Accounts payable
$

 
$
4

 
$
8

 
$

 
$
12

Accrued liabilities
23

 
8

 
606

 

 
637

Due to affiliates

 
47

 
66

 
(45
)
 
68

Deferred revenue

 
27

 
84

 

 
111

Deferred revenue—affiliate

 
22

 

 
(21
)
 
1

Other current liabilities—affiliate

 
1

 

 
(1
)
 

Total current liabilities
23

 
109

 
764

 
(67
)
 
829

 
 
 
 
 
 
 
 
 
 
Long-term debt, net
2,569

 

 
13,477

 

 
16,046

Non-current deferred revenue

 
1

 

 

 
1

Non-current derivative liabilities

 

 
3

 

 
3

Other non-current liabilities

 
10

 

 

 
10

Other non-current liabilities—affiliate

 
25

 

 

 
25

 
 
 
 
 
 
 
 
 
 
Partners’ equity (deficit)
639

 
2,076

 
(38
)
 
(2,038
)
 
639

Total liabilities and partners’ equity (deficit)
$
3,231

 
$
2,221

 
$
14,206

 
$
(2,105
)
 
$
17,553



37


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



Condensed Consolidating Balance Sheet
December 31, 2016
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Parent Issuer
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$

 
$

 
$

 
$

 
$

Restricted cash
234

 
13

 
358

 

 
605

Accounts and other receivables

 

 
90

 

 
90

Accounts receivable—affiliate

 
24

 
100

 
(25
)
 
99

Advances to affiliate

 
12

 
26

 

 
38

Inventory

 
8

 
89

 

 
97

Other current assets

 
4

 
25

 

 
29

Other current assets—affiliate

 

 
10

 
(10
)
 

Total current assets
234

 
61

 
698

 
(35
)
 
958

 
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
79

 
2,219

 
11,875

 
(15
)
 
14,158

Debt issuance costs, net
63

 

 
58

 

 
121

Non-current derivative assets
16

 

 
67

 

 
83

Investments in subsidiaries
2,617

 
471

 

 
(3,088
)
 

Other non-current assets, net

 
37

 
185

 

 
222

Total assets
$
3,009

 
$
2,788

 
$
12,883

 
$
(3,138
)
 
$
15,542

 
 
 
 
 
 
 
 
 
 
LIABILITIES AND PARTNERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
 
 
 
Accounts payable
$
1

 
$
3

 
$
23

 
$

 
$
27

Accrued liabilities
2

 
9

 
407

 

 
418

Current debt

 

 
224

 

 
224

Due to affiliates

 
89

 
33

 
(23
)
 
99

Deferred revenue

 
27

 
46

 

 
73

Deferred revenue—affiliate

 
11

 

 
(10
)
 
1

Derivative liabilities
3

 

 
11

 

 
14

Total current liabilities
6

 
139

 
744

 
(33
)
 
856

 
 
 
 
 
 
 
 
 
 
Long-term debt, net
2,560

 

 
11,649

 

 
14,209

Non-current deferred revenue

 
5

 

 

 
5

Non-current derivative liabilities

 

 
2

 

 
2

Other non-current liabilities—affiliate

 
27

 
2

 
(2
)
 
27

 
 
 
 
 
 
 
 
 
 
Partners’ equity
443

 
2,617

 
486

 
(3,103
)
 
443

Total liabilities and partners’ equity
$
3,009

 
$
2,788

 
$
12,883

 
$
(3,138
)
 
$
15,542



38


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



Condensed Consolidating Statement of Operations
Year Ended December 31, 2017
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Parent Issuer
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
 
LNG revenues
$

 
$

 
$
2,635

 
$

 
$
2,635

LNG revenues—affiliate

 

 
1,389

 

 
1,389

Regasification revenues

 
260

 

 

 
260

Regasification revenues—affiliate

 
190

 

 
(190
)
 

Other revenues

 
20

 

 

 
20

Other revenues—affiliate

 
218

 

 
(218
)
 

Total revenues

 
688

 
4,024

 
(408
)
 
4,304

 
 
 
 
 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
 
 
 
 
Cost of sales (excluding depreciation and amortization expense shown separately below)

 
1

 
2,317

 
2

 
2,320

Cost of sales—affiliate

 

 
23

 
(23
)
 

Operating and maintenance expense
4

 
45

 
243

 

 
292

Operating and maintenance expense—affiliate
6

 
137

 
329

 
(372
)
 
100

Development expense

 
1

 
2

 

 
3

General and administrative expense
4

 
1

 
7

 

 
12

General and administrative expense—affiliate
11

 
15

 
58

 
(4
)
 
80

Depreciation and amortization expense
2

 
74

 
264

 
(1
)
 
339

Other

 
2

 

 

 
2

Total operating costs and expenses
27

 
276

 
3,243

 
(398
)
 
3,148

 
 
 
 
 
 
 
 
 
 
Income (loss) from operations
(27
)
 
412

 
781

 
(10
)
 
1,156

 
 
 
 
 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
(111
)
 
(9
)
 
(494
)
 

 
(614
)
Loss on early extinguishment of debt
(25
)
 

 
(42
)
 

 
(67
)
Derivative gain (loss), net
6

 

 
(2
)
 

 
4

Equity earnings of subsidiaries
643

 
250

 

 
(893
)
 

Other income
4

 

 
7

 

 
11

Total other income (expense)
517

 
241

 
(531
)
 
(893
)
 
(666
)
 
 
 
 
 
 
 
 
 
 
Net income
$
490

 
$
653

 
$
250

 
$
(903
)
 
$
490



39


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



Condensed Consolidating Statement of Operations
Year Ended December 31, 2016
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Parent Issuer
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
 
LNG revenues
$

 
$

 
$
539

 
$

 
$
539

LNG revenues—affiliate

 

 
294

 

 
294

Regasification revenues

 
259

 

 

 
259

Regasification revenues—affiliate

 
61

 

 
(61
)
 

Other revenues

 
4

 

 

 
4

Other revenues—affiliate

 
163

 

 
(159
)
 
4

Total revenues

 
487

 
833

 
(220
)
 
1,100

 
 
 
 
 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
 
 
 
 
Cost of sales (excluding depreciation and amortization expense shown separately below)

 

 
416

 
(6
)
 
410

Cost of sales—affiliate

 

 
7

 
(5
)
 
2

Operating and maintenance expense
5

 
48

 
72

 
2

 
127

Operating and maintenance expense—affiliate

 
113

 
129

 
(190
)
 
52

Development expense—affiliate

 

 
1

 
(1
)
 

General and administrative expense
4

 
2

 
7

 

 
13

General and administrative expense—affiliate
12

 
15

 
68

 
(5
)
 
90

Depreciation and amortization expense
1

 
72

 
83

 

 
156

Total operating costs and expenses
22

 
250

 
783

 
(205
)
 
850

 
 
 
 
 
 
 
 
 
 
Income (loss) from operations
(22
)
 
237

 
50

 
(15
)
 
250

 
 
 
 
 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest
(23
)
 
(148
)
 
(186
)
 

 
(357
)
Loss on early extinguishment of debt

 
(20
)
 
(52
)
 

 
(72
)
Derivative gain (loss), net
12

 

 
(6
)
 

 
6

Equity losses of subsidiaries
(138
)
 
(193
)
 

 
331

 

Other income

 
1

 
1

 

 
2

Total other expense
(149
)
 
(360
)
 
(243
)
 
331

 
(421
)
 
 
 
 
 
 
 
 
 
 
Net loss
$
(171
)
 
$
(123
)
 
$
(193
)
 
$
316

 
$
(171
)


40


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



Condensed Consolidating Statement of Operations
Year Ended December 31, 2015
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Parent Issuer
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
 
Regasification revenues
$

 
$
259

 
$

 
$

 
$
259

Other revenues

 
7

 

 

 
7

Other revenues—affiliate

 
108

 

 
(104
)
 
4

Total revenues

 
374

 

 
(104
)
 
270

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

 
1

 
(32
)
 

 
(31
)
Operating and maintenance expense
3

 
36

 
23

 

 
62

Operating and maintenance expense—affiliate

 
94

 
1

 
(66
)
 
29

Development expense

 

 
3

 

 
3

Development expense—affiliate

 
1

 
1

 
(1
)
 
1

General and administrative expense
3

 
6

 
6

 

 
15

General and administrative expense—affiliate
11

 
60

 
88

 
(37
)
 
122

Depreciation and amortization expense

 
64

 
2

 

 
66

Total operating costs and expenses
17

 
262

 
92

 
(104
)
 
267

 
 
 
 
 
 
 
 
 
 
Income (loss) from operations
(17
)
 
112

 
(92
)
 

 
3

 
 
 
 
 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
 
 
 
 
Interest expense, net of capitalized interest

 
(175
)
 
(36
)
 
26

 
(185
)
Loss on early extinguishment of debt

 

 
(96
)
 

 
(96
)
Derivative loss, net

 

 
(42
)
 

 
(42
)
Equity losses of subsidiaries
(302
)
 
(266
)
 

 
568

 

Other income

 
1

 

 

 
1

Total other expense
(302
)
 
(440
)
 
(174
)
 
594

 
(322
)
 
 
 
 
 
 
 
 
 
 
Net loss
$
(319
)
 
$
(328
)
 
$
(266
)
 
$
594

 
$
(319
)


41


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



Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2017
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Parent Issuer
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
Cash flows provided by (used in) operating activities
$
(101
)
 
$
431

 
$
657

 
$
(10
)
 
$
977

 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net

 
(21
)
 
(1,279
)
 
10

 
(1,290
)
Investments in subsidiaries
(245
)
 
(7
)
 

 
252

 

Distributions received from affiliates, net
1,431

 
782

 

 
(2,213
)
 

Net cash provided by (used in) investing activities
1,186

 
754

 
(1,279
)
 
(1,951
)
 
(1,290
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
 
 
 
 
Proceeds from issuances of debt
1,500

 

 
2,314

 

 
3,814

Repayments of debt
(1,470
)
 

 
(703
)
 

 
(2,173
)
Debt issuance and deferred financing costs
(22
)
 

 
(28
)
 

 
(50
)
Distributions to parent

 
(1,431
)
 
(782
)
 
2,213

 

Contributions from parent

 
245

 
7

 
(252
)
 

Distributions to owners
(294
)
 

 

 

 
(294
)
Net cash provided by (used in) financing activities
(286
)
 
(1,186
)
 
808

 
1,961

 
1,297

 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
799

 
(1
)
 
186

 

 
984

Cash, cash equivalents and restricted cash—beginning of period
234

 
13

 
358

 

 
605

Cash, cash equivalents and restricted cash—end of period
$
1,033

 
$
12

 
$
544

 
$

 
$
1,589



Balances per Condensed Consolidating Balance Sheet:
 
December 31, 2017
 
Parent Issuer
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
Cash and cash equivalents
$

 
$

 
$

 
$

 
$

Restricted cash
1,033

 
12

 
544

 

 
1,589

Total cash, cash equivalents and restricted cash
$
1,033

 
$
12

 
$
544

 
$

 
$
1,589



42


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



Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2016
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Parent Issuer
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
Cash flows provided by (used in) operating activities
$
(53
)
 
$
181

 
$
(130
)
 
$
2

 
$

 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net

 
(7
)
 
(2,306
)
 
(2
)
 
(2,315
)
Investments in subsidiaries
(2,429
)
 
(1
)
 

 
2,430

 

Distributions received from affiliates, net
218

 

 

 
(218
)
 

Other

 
(6
)
 
(32
)
 

 
(38
)
Net cash used in investing activities
(2,211
)
 
(14
)
 
(2,338
)
 
2,210

 
(2,353
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
 
 
 
 
Proceeds from issuances of debt
2,560

 

 
5,443

 

 
8,003

Repayments of debt

 
(2,486
)
 
(2,765
)
 

 
(5,251
)
Debt issuance and deferred financing costs
(73
)
 

 
(42
)
 

 
(115
)
Debt extinguishment costs

 
(14
)
 

 

 
(14
)
Distributions to parent

 
(218
)
 

 
218

 

Contributions from parent

 
2,429

 
1

 
(2,430
)
 

Distributions to owners
(99
)
 

 

 

 
(99
)
Net cash provided by (used in) financing activities
2,388

 
(289
)
 
2,637

 
(2,212
)
 
2,524

 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
124

 
(122
)
 
169

 

 
171

Cash, cash equivalents and restricted cash—beginning of period
110

 
135

 
189

 

 
434

Cash, cash equivalents and restricted cash—end of period
$
234

 
$
13

 
$
358

 
$

 
$
605



Balances per Condensed Consolidating Balance Sheet:
 
December 31, 2016
 
Parent Issuer
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
Cash and cash equivalents
$

 
$

 
$

 
$

 
$

Restricted cash
234

 
13

 
358

 

 
605

Total cash, cash equivalents and restricted cash
$
234

 
$
13

 
$
358

 
$

 
$
605



43


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



Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2015
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Parent Issuer
 
Guarantors
 
Non-Guarantor
 
Eliminations
 
Consolidated
 
 
 
 
 
 
 
 
 
 
Cash flows provided by (used in) operating activities
$
(43
)
 
$
53

 
$
(207
)
 
$
26

 
$
(171
)
 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
(1
)
 
(25
)
 
(2,861
)
 
(26
)
 
(2,913
)
Investments in subsidiaries
(53
)
 
(15
)
 

 
68

 

Distributions received from affiliates, net
84

 

 

 
(84
)
 

Other

 

 
(62
)
 

 
(62
)
Net cash provided by (used in) investing activities
30

 
(40
)
 
(2,923
)
 
(42
)
 
(2,975
)
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 
 
 
 
 
Proceeds from issuances of debt

 

 
2,860

 

 
2,860

Debt issuance and deferred financing costs

 
(1
)
 
(169
)
 

 
(170
)
Distributions to parent

 
(84
)
 

 
84

 

Contributions from parent

 
53

 
15

 
(68
)
 

Distributions to owners
(99
)
 

 

 

 
(99
)
Net cash provided by (used in) financing activities
(99
)
 
(32
)
 
2,706

 
16

 
2,591

 
 
 
 
 
 
 
 
 
 
Net decrease in cash, cash equivalents and restricted cash
(112
)
 
(19
)
 
(424
)
 

 
(555
)
Cash, cash equivalents and restricted cash—beginning of period
222

 
154

 
613

 

 
989

Cash, cash equivalents and restricted cash—end of period
$
110

 
$
135

 
$
189

 
$

 
$
434



44


PART IV

ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(c) Financial statements of affiliates whose securities are pledged as collateral — See Index to Financial Statements on page S-1.

The accompanying financial statements of our subsidiaries, Cheniere Energy Investments, LLC, Sabine Pass LNG-LP, LLC, Sabine Pass LNG, L.P. and Cheniere Creole Trail Pipeline, L.P., are being provided pursuant to Rule 3-16 of Regulation S-X, which requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities.




CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS OF SUBSIDIARIES INCLUDED
PURSUANT TO RULE 3-16 OF REGULATION S-X


 
 
 
 
 
 


S-1













Cheniere Energy Investments, LLC
Consolidated Financial Statements
As of December 31, 2017 and 2016
and for the years ended December 31, 2017, 2016 and 2015







S-2


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES


DEFINITIONS
As used in these Consolidated Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms
Bcf/d
 
billion cubic feet per day
Bcfe
 
billion cubic feet equivalent
EPC
 
engineering, procurement and construction
FERC
 
Federal Energy Regulatory Commission
GAAP
 
generally accepted accounting principles in the United States
Henry Hub
 
the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR
 
London Interbank Offered Rate
LNG
 
liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu
 
million British thermal units, an energy unit
mtpa
 
million tonnes per annum
SPA
 
LNG sale and purchase agreement
TBtu
 
trillion British thermal units, an energy unit
Train
 
an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA
 
terminal use agreement



S-3


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES



Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2017, including our ownership of certain subsidiaries, and the references to these entities used in these Consolidated Financial Statements:
orgcharta57.jpg

Unless the context requires otherwise, references to “Cheniere Investments,” “the Company,” “we,” “us” and “our” refer to Cheniere Energy Investments, LLC and its consolidated subsidiaries, including SPLNG, SPL and CTPL



S-4


Independent Auditors’ Report
To the Member of Cheniere Energy Investments, LLC:

We have audited the accompanying consolidated financial statements of Cheniere Energy Investments, LLC and its subsidiaries (the Company), which comprise the consolidated balance sheets as of December 31, 2017 and 2016, and the related consolidated statements of operations, member’s equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the consolidated financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cheniere Energy Investments, LLC and its subsidiaries as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2017 in accordance with U.S. generally accepted accounting principles.
Emphasis of Matter
As discussed in Note 2 to the consolidated financial statements, in 2017, 2016 and 2015, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. Our opinion is not modified with respect to this matter.

S-5


Other Matter
Our audit was conducted for the purpose of forming an opinion on the consolidated financial statements as a whole. The financial statement schedule I is presented for purposes of additional analysis and is not a required part of the consolidated financial statements. Such information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the consolidated financial statements. The information has been subjected to the auditing procedures applied in the audit of the consolidated financial statements and certain additional procedures, including comparing and reconciling such information directly to the underlying accounting and other records used to prepare the consolidated financial statements or to the consolidated financial statements themselves, and other additional procedures in accordance with auditing standards generally accepted in the United States of America. In our opinion, the information is fairly stated in all material respects in relation to the consolidated financial statements as a whole.

/s/ KPMG LLP

Houston, Texas
June 15, 2018


S-6


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES


CONSOLIDATED BALANCE SHEETS
(in millions)
 
 
December 31,
 
 
2017
 
2016
ASSETS
 

 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$

 
$

Restricted cash
 
557

 
371

Accounts and other receivables
 
190

 
90

Accounts receivable—affiliate
 
163

 
99

Advances to affiliate
 
36

 
38

Inventory
 
95

 
97

Other current assets
 
56

 
27

Other current assets—affiliate
 
1

 
1

Total current assets
 
1,098

 
723

 
 
 
 
 
Property, plant and equipment, net
 
15,059

 
14,079

Debt issuance costs, net
 
18

 
59

Non-current derivative assets
 
17

 
67

Other non-current assets, net
 
206

 
222

Total assets
 
$
16,398

 
$
15,150

 
 
 
 
 
LIABILITIES AND MEMBER’S EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
12

 
$
27

Accrued liabilities
 
614

 
415

Current debt
 

 
224

Due to affiliates
 
68

 
73

Deferred revenue
 
111

 
73

Derivative liabilities
 

 
11

Other current liabilities—affiliate
 
1

 
1

Total current liabilities
 
806

 
824

 
 
 
 
 
Long-term debt, net
 
13,477

 
11,649

Non-current deferred revenue
 
1

 
5

Non-current derivative liabilities
 
3

 
2

Other non-current liabilities
 
10

 

Other non-current liabilities—affiliate
 
25

 
27

 
 
 
 
 
Commitments and contingencies (see Note 14)
 
 
 
 
 
 
 
 
 
Member’s equity
 
2,076

 
2,643

Total liabilities and member’s equity
 
$
16,398

 
$
15,150



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

S-7


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
 
Year Ended December 31,
 
2017
 
2016
 
2015
Revenues
 
 
 
 
 
LNG revenues
$
2,635

 
$
539

 
$

LNG revenues—affiliate
1,389

 
294

 

Regasification revenues
260

 
259

 
259

Other revenues
20

 
4

 
7

Other revenues—affiliate

 
4

 
4

Total revenues
4,304

 
1,100

 
270

 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)
2,320

 
410

 
(31
)
Cost of sales—affiliate

 
2

 

Operating and maintenance expense
287

 
122

 
60

Operating and maintenance expense—affiliate
93

 
52

 
29

Development expense
3

 

 
3

Development expense—affiliate

 

 
1

General and administrative expense
8

 
9

 
13

General and administrative expense—affiliate
68

 
78

 
110

Depreciation and amortization expense
338

 
155

 
65

Other
2

 

 

Total operating costs and expenses
3,119

 
828

 
250

 
 
 
 
 
 
Income from operations
1,185

 
272

 
20

 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
Interest expense, net of capitalized interest
(503
)
 
(334
)
 
(211
)
Loss on early extinguishment of debt
(42
)
 
(72
)
 
(96
)
Derivative loss, net
(2
)
 
(6
)
 
(42
)
Other income
7

 
1

 
1

Total other expense
(540
)
 
(411
)
 
(348
)
 
 
 
 
 
 
Net income (loss)
$
645

 
$
(139
)
 
$
(328
)



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

S-8


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
(in millions)
 
Cheniere Energy Partners, L.P.
 
Total Member’s Equity
Balance at December 31, 2014
$
880

 
$
880

Net loss
(328
)
 
(328
)
Contributions
91

 
91

Distributions
(84
)
 
(84
)
Balance at December 31, 2015
559

 
559

Net loss
(139
)
 
(139
)
Contributions
2,439

 
2,439

Distributions
(216
)
 
(216
)
Balance at December 31, 2016
2,643

 
2,643

Net income
645

 
645

Contributions
219

 
219

Distributions
(1,431
)
 
(1,431
)
Balance at December 31, 2017
$
2,076

 
$
2,076



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

S-9


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
Year Ended December 31,
 
2017
 
2016
 
2015
Cash flows from operating activities
 
 
 
 
 
Net income (loss)
$
645

 
$
(139
)
 
$
(328
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
 
 
Non-cash LNG inventory write-downs

 

 
18

Depreciation and amortization expense
338

 
155

 
65

Amortization of debt issuance costs, deferred commitment fees, premium and discount
19

 
20

 
12

Loss on early extinguishment of debt
42

 
72

 
96

Total losses (gains) on derivatives, net
26

 
(36
)
 
7

Net cash used for settlement of derivative instruments
(14
)
 
(7
)
 
(41
)
Other
11

 

 
1

Changes in operating assets and liabilities:
 
 
 
 
 
Accounts and other receivables
(100
)
 
(90
)
 

Accounts receivable—affiliate
(62
)
 
(98
)
 
1

Advances to affiliate
(12
)
 

 
(13
)
Inventory
13

 
(58
)
 
(25
)
Accounts payable and accrued liabilities
190

 
167

 
(3
)
Due to affiliates
(16
)
 

 
18

Deferred revenue
34

 
42

 
(4
)
Other, net
(6
)
 
(5
)
 
(10
)
Other, net—affiliate
(2
)
 
1

 
14

Net cash provided by (used in) operating activities
1,106

 
24

 
(192
)
 
 
 
 
 
 
Cash flows from investing activities
 

 
 

 
 
Property, plant and equipment, net
(1,290
)
 
(2,298
)
 
(2,885
)
Other

 
(38
)
 
(63
)
Net cash used in investing activities
(1,290
)
 
(2,336
)
 
(2,948
)
 
 
 
 
 
 
Cash flows from financing activities
 

 
 

 
 
Proceeds from issuances of debt
2,314

 
5,443

 
2,860

Repayments of debt
(703
)
 
(5,251
)
 

Debt issuance and deferred financing costs
(29
)
 
(42
)
 
(170
)
Debt extinguishment costs

 
(14
)
 

Capital contributions
219

 
2,439

 
91

Distributions
(1,431
)
 
(216
)
 
(84
)
Net cash provided by financing activities
370

 
2,359

 
2,697

 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
186

 
47

 
(443
)
Cash, cash equivalents and restricted cash—beginning of period
371

 
324

 
767

Cash, cash equivalents and restricted cash—end of period
$
557

 
$
371

 
$
324



Balances per Consolidated Balance Sheets:
 
December 31,
 
2017
 
2016
Cash and cash equivalents
$

 
$

Restricted cash
557

 
371

Total cash, cash equivalents and restricted cash
$
557

 
$
371




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

S-10


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We are a Delaware limited liability company formed in 2006 by our sole member, Cheniere Partners, a publicly traded limited partnership. Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. Through SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We also own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”) through CTPL.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Cheniere Investments and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto using the full retrospective method. We have elected to adopt the new accounting standard retrospectively for all periods presented.

We have evaluated subsequent events through June 15, 2018, the date the Consolidated Financial Statements were available to be issued.

Use of Estimates
 
The preparation of 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. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, derivative instruments, asset retirement obligations (“AROs”) and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted

S-11


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial assets and liabilities initially measured at fair value include intangible assets and AROs.
 
Revenue Recognition
 
We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale of LNG are recognized as LNG revenues. LNG regasification capacity payments are recognized as regasification revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues.

Cash and Cash Equivalents
 
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
 
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.

Accounts Receivable

Accounts receivable is reported net of allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses.  The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral.  We did not recognize any bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

Inventory

LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued. During the year ended December 31, 2015, we recognized $18 million as operating and maintenance expense as a result of write-down for LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. We did not recognize any operating and maintenance expense related to inventory write-downs during the years ended December 31, 2017 and 2016.

Accounting for LNG Activities
 
Generally, we begin capitalizing the costs of our LNG terminals and related pipelines once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminals and related pipelines.
 
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.
 
We capitalize interest and other related debt costs during the construction period of our LNG terminal and related pipeline. Upon commencement of operations, capitalized interest, as a component of the total cost, is amortized over the estimated useful life of the asset.


S-12


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



Property, Plant and Equipment 

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in other operating costs and expenses.
 
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.  We did not record any impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 and 2015.

Regulated Natural Gas Pipelines 

The Creole Trail Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Consolidated Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities. 

Items that may influence our assessment are: 
inability to recover cost increases due to rate caps and rate case moratoriums;  
inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;  
excess capacity;  
increased competition and discounting in the markets we serve; and  
impacts of ongoing regulatory initiatives in the natural gas industry.
Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases

S-13


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2017, 2016 and 2015. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk
 
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. Certain of our commodity derivative transactions 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. Collateral deposited for such contracts is recorded as other current asset. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

SPL has entered into six fixed price SPAs with terms of at least 20 years with six unaffiliated third parties. SPL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 15—Customer Concentration for additional details about our customer concentration.
 
SPLNG has entered into two long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal. SPLNG is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective TUAs.

Debt

Our debt consists of current and long-term secured debt securities and credit facilities with banks and other lenders.  Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.  

Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment of debt are recorded in gains and losses on the extinguishment of debt on our Consolidated Statements of Operations.

Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are recorded as a direct deduction from the debt liability unless incurred in connection with a line of credit arrangement, in which case they are presented as an asset on our Consolidated Balance Sheets. Debt issuance costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on early extinguishment of debt.

Asset Retirement Obligations
 
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our assessment of AROs is described below.

S-14


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



 
We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.

We have not recorded an ARO associated with the Creole Trail Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.

Income Taxes 

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which directly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.

At December 31, 2017, the tax basis of our assets and liabilities was $3.1 billion less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our subsidiaries’ tax sharing agreements.

Business Segment

Our liquefaction and regasification operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of Cheniere Investments in total when evaluating financial performance and for purposes of allocating resources.

NOTE 3—RESTRICTED CASH
 
Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of December 31, 2017 and 2016, restricted cash consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Current restricted cash
 
 
 
 
Liquefaction Project
 
$
544

 
$
358

Cash held by Cheniere Partners’ guarantor subsidiaries, including us
 
13

 
13

Total current restricted cash
 
$
557

 
$
371


Under the terms of the credit and guaranty agreement aggregating $2.8 billion that Cheniere Partners entered into in February 2016 (the “2016 CQP Credit Facilities”), Cheniere Partners’ guarantor subsidiaries are required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities. See Note 17—Guarantees for information regarding Cheniere Partners’ guarantor subsidiaries.


S-15


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2017 and 2016, accounts and other receivables consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
SPL trade receivable
 
$
185

 
$
88

Other accounts receivable
 
5

 
2

Total accounts and other receivables
 
$
190

 
$
90


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 Liquefaction Project and other restricted payments.

NOTE 5—INVENTORY

As of December 31, 2017 and 2016, inventory consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Natural gas
 
$
17

 
$
15

LNG
 
26

 
45

Materials and other
 
52

 
37

Total inventory
 
$
95

 
$
97


NOTE 6—PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in millions):
 
 
December 31,
 
 
2017
 
2016
LNG terminal costs
 
 
 
 
LNG terminal
 
$
12,663

 
$
7,956

LNG terminal construction-in-process
 
3,269

 
6,670

Accumulated depreciation
 
(879
)
 
(553
)
Total LNG terminal costs, net
 
15,053

 
14,073

Fixed assets
 
 

 
 

Fixed assets
 
23

 
19

Accumulated depreciation
 
(17
)
 
(13
)
Total fixed assets, net
 
6

 
6

Property, plant and equipment, net
 
$
15,059

 
$
14,079

 

Depreciation expense was $329 million, $147 million and $64 million in the years ended December 31, 2017, 2016 and 2015, respectively.

We realized offsets to LNG terminal costs of $301 million and $201 million in the years ended December 31, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction.


S-16


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



LNG Terminal Costs

The Sabine Pass LNG terminal and pipeline are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows:
Components
 
Useful life (yrs)
LNG storage tanks
 
50
Natural gas pipeline facilities
 
40
Marine berth, electrical, facility and roads
 
35
Regasification processing equipment
 
30
Sendout pumps
 
20
Liquefaction processing equipment
 
6-50
Other
 
15-30

Fixed Assets

Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”). SPL had previously entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under one of its credit facilities (“Interest Rate Derivatives”), which were settled in March 2017.
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. 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 to the extent not utilized for the commissioning process.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2017 and 2016, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).
 
Fair Value Measurements as of
 
December 31, 2017
 
December 31, 2016
 
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
Interest Rate Derivatives liability
$

 
$

 
$

 
$

 
$

 
$
(6
)
 
$

 
$
(6
)
Liquefaction Supply Derivatives asset (liability)
2

 
10

 
43

 
55

 
(4
)
 
(2
)
 
79

 
73


We value our Interest Rate Derivatives using an income-based approach, utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using a market based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.

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 satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.


S-17


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace. 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 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.

The Level 3 fair value measurements of our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2017:
 
 
Net Fair Value Asset
(in millions)
 
Valuation Approach
 
Significant Unobservable Input
 
Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives
 
$43
 
Market approach incorporating present value techniques
 
Basis Spread
 
$(0.503) - $0.432

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Balance, beginning of period
 
$
79

 
$
32

 
$

Realized and mark-to-market gains (losses):
 
 
 
 
 
 
Included in cost of sales (1)
 
(37
)
 
48

 
32

Purchases and settlements:
 
 
 
 
 
 
Purchases
 
14

 
1

 

Settlements (1)
 
(12
)
 
(2
)
 

Transfers out of Level 3
 
(1
)
 

 

Balance, end of period
 
$
43

 
$
79

 
$
32

Change in unrealized gains relating to instruments still held at end of period
 
$
(37
)
 
$
49

 
$
32

 
    
(1)
Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016.

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.  Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.

Interest Rate Derivatives

SPL had entered into 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”), based on a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities. In March 2017, SPL settled the Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the 2015 SPL Credit Facilities, as discussed in Note 10—Debt.


S-18


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



The following table shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets (in millions):

 
 
 
 
Fair Value Measurements as of
 
 
Consolidated Balance Sheet Location
 
December 31, 2017
 
December 31, 2016
Interest Rate Derivatives
 
Derivative liabilities
 
$

 
$
(4
)
Interest Rate Derivatives
 
Non-current derivative liabilities
 

 
(2
)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Interest Rate Derivatives loss
 
$
(2
)
 
$
(6
)
 
$
(42
)

Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges, if applicable, to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the noncurrent physical natural gas supply contracts range from approximately one to seven years, most of which commence upon the satisfaction of certain conditions precedent, if not already met, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.

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.

SPL had secured up to approximately 2,214 TBtu and 1,994 TBtu of natural gas feedstock through natural gas supply contracts as of December 31, 2017 and 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,520 TBtu and 1,117 TBtu as of December 31, 2017 and 2016, respectively.

The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):
 
 
Fair Value Measurements as of (1)
Consolidated Balance Sheet Location
 
December 31, 2017
 
December 31, 2016
Other current assets
 
$
41

 
$
13

Non-current derivative assets
 
17

 
67

Total derivative assets
 
58

 
80

 
 
 
 
 
Derivative liabilities
 

 
(7
)
Non-current derivative liabilities
 
(3
)
 

Total derivative liabilities
 
(3
)
 
(7
)
 
 
 
 
 
Derivative asset, net
 
$
55

 
$
73

 
(1)
Does not include a collateral call of $1 million and a collateral deposit of $6 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2017 and 2016, respectively.

The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
 
Year Ended December 31,
 
Consolidated Statement of Operations Location (1)
 
2017
 
2016
 
2015
Liquefaction Supply Derivatives loss (gain) (2)
Cost (cost recovery) of sales
 
$
24

 
$
(42
)
 
$
(33
)
 

S-19


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



(1)
Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
(2)
Does not include the realized value associated with derivative instruments that settle through physical delivery.

Consolidated Balance Sheet Presentation

Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):
 
 
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 December 31, 2017
 
 
 
 
 
 
Liquefaction Supply Derivatives
 
$
64

 
$
(6
)
 
$
58

Liquefaction Supply Derivatives
 
(3
)
 

 
(3
)
As of December 31, 2016
 
 
 
 
 
 
Interest Rate Derivatives
 
$
(6
)
 
$

 
$
(6
)
Liquefaction Supply Derivatives
 
82

 
(2
)
 
80

Liquefaction Supply Derivatives
 
(11
)
 
4

 
(7
)

NOTE 8—OTHER NON-CURRENT ASSETS

As of December 31, 2017 and 2016, other non-current assets, net consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Advances made under EPC and non-EPC contracts
 
$
26

 
$
23

Advances made to municipalities for water system enhancements
 
93

 
95

Advances and other asset conveyances to third parties to support LNG terminals
 
30

 
31

Tax-related payments and receivables
 
25

 
28

Information technology service assets
 
24

 
27

Other
 
8

 
18

Total other non-current assets, net
 
$
206

 
$
222


NOTE 9—ACCRUED LIABILITIES
 
As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Interest costs and related debt fees
 
$
229

 
$
204

Sabine Pass LNG terminal and related pipeline costs
 
384

 
211

Other accrued liabilities
 
1

 

Total accrued liabilities
 
$
614

 
$
415



S-20


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



NOTE 10—DEBT
 
As of December 31, 2017 and 2016, our debt consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Long-term debt:
 
 
 
 
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $6 and $7
 
$
2,006

 
$
2,007

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

 
1,000

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

 
1,506

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

 
2,000

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

 
2,000

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

 
1,500

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

 
1,500

4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero
 
1,349

 

5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)
 
800

 

2015 SPL Credit Facilities
 

 
314

Unamortized debt issuance costs
 
(183
)
 
(178
)
Total long-term debt, net
 
13,477

 
11,649

 
 
 
 
 
Current debt:
 
 
 
 
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)
 

 
224

 
 
 
 
 
Total debt, net
 
$
13,477

 
$
11,873


Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2017 (in millions): 
Years Ending December 31,
 
Principal Payments
2018
 
$

2019
 

2020
 

2021
 
2,000

2022
 
1,000

Thereafter
 
10,650

Total
 
$
13,650


SPL Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes, after provisioning for incremental interest required during construction, were used to prepay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.
  
In connection with the issuance of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $42 million during the year ended December 31, 2017.


S-21


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



The terms of the 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes and 2028 SPL Senior Notes (collectively with the 2037 SPL Senior Notes, the “SPL Senior Notes”) are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain customary terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. 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. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025. As of December 31, 2017, SPL was in compliance with all covenants related to the SPL Senior Notes. Interest on the SPL Senior Notes is payable semi-annually in arrears.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), 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.

SPL Working Capital Facility

Below is a summary of the SPL Working Capital Facility as of December 31, 2017 (in millions):
 
 
SPL Working Capital Facility
Original facility size
 
$
1,200

Less:
 
 
Outstanding balance
 

Letters of credit issued
 
730

Available commitment
 
$
470

 
 
 
Interest rate
 
LIBOR plus 1.75% or base rate plus 0.75%
Maturity date
 
December 31, 2020, with various terms for underlying loans

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to an additional $390 million.

Loans under the SPL Working Capital Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR 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 loans is due

S-22


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



and payable at the end of each applicable LIBOR period, and interest on base rate loans is due and payable at the end of each fiscal quarter. However, if such base rate loan is converted into a LIBOR 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 December 31, 2017, no LC Draws had been made upon any letters of credit issued under the SPL Working Capital Facility.

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

The SPL Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. As of December 31, 2017, SPL was in compliance with all covenants related to the SPL Working Capital Facility. 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.

Interest Expense

Total interest expense consisted of the following (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Total interest cost
 
$
788

 
$
797

 
$
704

Capitalized interest
 
(285
)
 
(463
)
 
(493
)
Total interest expense, net
 
$
503

 
$
334

 
$
211


Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our debt (in millions):
 
 
December 31, 2017
 
December 31, 2016
 
 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
Senior notes, net of premium or discount (1)
 
$
12,860

 
$
13,955

 
$
11,513

 
$
12,309

2037 SPL Senior Notes (2)
 
800

 
871

 

 

Credit facilities (3)
 

 

 
538

 
538

 
(1)
Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes and 2028 SPL Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
(2)
The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 
(3)
Includes 2015 SPL Credit Facilities and SPL Working Capital Facility. 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. 

S-23


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED




NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
LNG revenues
 
$
2,615

 
$
535

 
$

LNG revenues—affiliate
 
1,389

 
294

 

Regasification revenues
 
260

 
259

 
259

Other revenues
 
20

 
4

 
7

Other revenues—affiliate
 

 
4

 
4

Total revenues from customers
 
4,284

 
1,096

 
270

Revenues from derivative instruments (1)
 
20

 
4

 

Total revenues
 
$
4,304

 
$
1,100

 
$
270

 
(1)
Relates to the realized value associated with a portion of derivative instruments that settle through physical delivery.

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a Free on Board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the sale was negotiated. We have concluded that the variable fees meet the optional exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the optional exception, variable consideration related to the sale of LNG is also not included in the transaction price.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.


S-24


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the optional exception for allocating variable consideration and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6.

Upon substantial completion of Train 3, which was in June 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. 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 and we continue to recognize the payments received from Total as revenue. During the year ended December 31, 2017, SPL recorded $23 million as operating and maintenance expense under this partial TUA assignment agreement.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” and “Non-current deferred revenue” on our Consolidated Balance Sheets (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Deferred revenues, beginning of period
 
$
78

 
$
36

 
$
40

Cash received but not yet recognized
 
110

 
71

 
25

Revenue recognized from prior period deferral
 
(76
)
 
(29
)
 
(29
)
Deferred revenues, end of period
 
$
112

 
$
78

 
$
36


We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2017 and 2016 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs. Changes in deferred revenue during the years ended December 31, 2017, 2016 and 2015 are also attributable to differences between the timing of revenue recognition and the receipt of advance payments under our TUAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:
 
 
Unsatisfied
Transaction Price
(in billions)
 
Weighted Average Recognition Timing (years) (1)
LNG revenues
 
$
55.7

 
10.2

Regasification revenues
 
2.9

 
5.7

Total revenues
 
$
58.6

 
 
 
    
(1)
The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.


S-25


CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



We have elected the following optional exemptions which omit certain potential future sources of revenue from the table above:
(1)
We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)
We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. During the year ended December 31, 2017, approximately 58% of our LNG revenues, 100% of our LNG revenues—affiliate and approximately 2% of our Regasification revenues were related to variable consideration received from customers.

We have entered into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

NOTE 12—RELATED PARTY TRANSACTIONS
 
Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015 (in millions):
 
Year Ended December 31,
 
2017
 
2016
 
2015
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA
$
1,389

 
$
294

 
$

 
 
 
 
 
 
Other revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG

 
1

 
1

Terminal Marine Services Agreement

 
3

 
3

Total other revenues—affiliate


4

 
4

 
 
 
Cost of sales—affiliate
Fees under the Pre-commercial LNG Marketing Agreement

 
2

 

 
 
 
 
 
 
Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG

 
1

 
1

Services Agreements
93

 
51

 
28

Total operating and maintenance expense—affiliate
93


52

 
29

 
 
 
Development expense—affiliate
Services Agreements

 

 
1

 
 
 
General and administrative expense—affiliate
Services Agreements
68

 
78

 
111


LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0 Bcf/d of regasification capacity and other liquefaction support services under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least 20 years after May 2016.

In connection with this TUA, SPL is required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is recorded as operating and maintenance expense on our Consolidated Statements of Operations.

Cheniere Investments, SPL and SPLNG entered into the terminal use rights assignment and agreement (the “TURA”) pursuant to which Cheniere Investments had the right to use SPL’s reserved capacity under the TUA and had the obligation to pay the TUA Fees required by the TUA to SPLNG. However, the revenue earned by SPLNG from the TUA Fees and the loss incurred by Cheniere Investments under the TURA are eliminated upon consolidation of our Consolidated Financial Statements. Cheniere Partners has guaranteed the obligations of SPL under its TUA and the obligations of Cheniere Investments under the TURA.

In an effort to utilize Cheniere Investments’ reserved capacity under the TURA during construction of the Liquefaction Project, Cheniere Marketing, LLC (“Cheniere Marketing US”) has entered into an amended and restated variable capacity rights agreement with Cheniere Investments (the “Amended and Restated VCRA”) pursuant to which Cheniere Marketing US is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing US arranges for delivery to the Sabine Pass LNG terminal. Cheniere Investments recorded no revenues—affiliate from Cheniere Marketing US during the years ended December 31, 2017, 2016 and 2015 related to the Amended and Restated VCRA.

Cheniere Marketing SPA

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

Cheniere Marketing Master SPA

SPL has an agreement with Cheniere Marketing that allows the parties to sell and purchase LNG with each other by executing and delivering confirmations under this agreement.

Commissioning Confirmation

Under the Cheniere Marketing Master SPA, SPL executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. had control of, and was commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

SPL has an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on SPL’s behalf to market and sell certain quantities of pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC, one of SPL’s SPA customers. SPL pays a fee to Cheniere Marketing for marketing and transportation, which is based on volume sold under this agreement.

Services Agreements
As of December 31, 2017 and 2016, we had $36 million and $38 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere. On a quarterly basis, our subsidiaries receiving the benefit are invoiced by Cheniere according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.


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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



SPLNG O&M Agreement

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

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

SPL O&M Agreement

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

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

CTPL O&M Agreement

CTPL has an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the CTPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the CTPL O&M Agreement are required to be remitted to such subsidiary.
 
Agreement to Fund SPLNG’s Cooperative Endeavor Agreements
 
SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This ten-

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



year initiative represented an aggregate commitment of $25 million in order to aid in their reconstruction efforts following Hurricane Rita, which SPLNG fulfilled in the first quarter of 2016. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to, and in the year the Cameron Parish dollar-for-dollar credit is applied against, ad valorem tax levied on our LNG terminal.

On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of both December 31, 2017 and 2016, we had $25 million of both other non-current assets resulting from SPLNG’s ad valorem tax payments and other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.
 
Contracts for Sale and Purchase of Natural Gas and LNG
 
SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing US. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing US at a sales price equal to the actual purchase price paid by Cheniere Marketing US to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing US with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing US have an LNG Terminal Export Agreement that provides Cheniere Marketing US the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the years ended December 31, 2017, 2016 and 2015.

State Tax Sharing Agreements

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

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

CTPL has a state tax sharing agreement with Cheniere. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which CTPL and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, CTPL will pay to Cheniere an amount equal to the state and local tax that CTPL would be required to pay if CTPL’s state and local tax liability were calculated on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from CTPL

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



under this agreement; therefore, Cheniere has not demanded any such payments from CTPL. The agreement is effective for tax returns due on or after May 2013.

NOTE 13—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $13 million, $11 million and $10 million, respectively, related primarily to office space and land sites. Our land site leases for the Sabine Pass LNG terminal have initial terms varying up to 30 years with multiple options to renew up to an additional 60 years.

Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in millions): 
Years Ending December 31,
Operating Leases (1)
2018
$
2

2019
2

2020
2

2021
2

2022
2

Thereafter
45

Total
$
55

 
(1)
Includes certain lease option renewals that are reasonably assured.

NOTE 14—COMMITMENTS AND CONTINGENCIES
 
We have 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 December 31, 2017, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies

Obligations under EPC Contract

SPL has a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of Train 5 of the Liquefaction Project. The EPC contract for Train 5 provides that SPL will pay Bechtel a contract price of $3.1 billion, subject to adjustment by change order.  SPL has the right to terminate the EPC contract for its convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date.

Obligations under SPAs

SPL has third-party SPAs which obligate SPL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project.

Obligations under LNG TUAs
 
SPLNG has third-party TUAs with Total and Chevron U.S.A. Inc. to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG terminal.
 
Obligations under Natural Gas Supply, Transportation and Storage Service Agreements

SPL has index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The terms of these contracts primarily range from approximately one to seven years and commence upon the occurrence of conditions precedent, including SPL’s declaration to the respective natural gas supplier that it is ready to commence the term of the supply arrangement in anticipation of the date of first commercial operation of the applicable, specified Trains of the Liquefaction Project. As of December 31, 2017, SPL has secured up to approximately 2,214 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent were met.

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED




Additionally, SPL has transportation and storage service agreements for the Liquefaction Project. The initial terms of the transportation agreements range from one to 20 years, with renewal options for certain contracts, and commence upon the occurrence of conditions precedent. The terms of the SPL storage service agreements range from three to ten years.

As of December 31, 2017, SPL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions): 
Years Ending December 31,
Payments Due (1)
2018
$
2,274

2019
1,527

2020
1,397

2021
981

2022
336

Thereafter
1,169

Total
$
7,684

 
(1)
Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on prices and basis spreads as of December 31, 2017.

Obligations under LNG TUA

SPL has a partial TUA assignment agreement with Total, another TUA customer, whereby upon substantial completion of Train 3 in March 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6. 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.

Services Agreements
 
We have certain services agreements with affiliates. See Note 12—Related Party Transactions for information regarding such agreements.
 
Restricted Net Assets
 
At December 31, 2017, our restricted net assets of consolidated subsidiaries were approximately $2.0 billion.

Other Commitments
 
State Tax Sharing Agreements
 
SPLNG, SPL and CTPL have state tax sharing agreements with Cheniere. See Note 12—Related Party Transactions for information regarding such agreements.

Other Agreements

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. Additionally, we have various lease commitments, as disclosed in Note 13—Leases.
 

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



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. In the opinion of management, as of December 31, 2017, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.

NOTE 15—CUSTOMER CONCENTRATION
  
The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:
 
 
Percentage of Total Third-Party Revenues
 
Percentage of Accounts Receivable from Third Parties
 
 
Year Ended December 31,
 
December 31,
 
 
2017
 
2016
 
2015
 
2017
 
2016
Customer A
 
39%
 
52%
 
—%
 
39%
 
47%
Customer B
 
27%
 
*
 
—%
 
32%
 
50%
Customer C
 
23%
 
—%
 
—%
 
26%
 
—%
 
* Less than 10%

During the year ended December 31, 2017, revenues from external customers that were derived from domestic customers was $1.4 billion and from customers outside of the United States was $1.5 billion, of which $787 million and $666 million were from customers in Ireland and South Korea, respectively. During the year ended December 31, 2016, revenues from external customers that were derived from domestic customers was $677 million and from customers outside of the United States was $125 million. During the year ended December 31, 2015, all revenues from external customers were derived from domestic customers. 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.

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION
 
The following table provides supplemental disclosure of cash flow information (in millions):
 
Year Ended December 31,
 
2017
 
2016
 
2015
Cash paid during the period for interest, net of amounts capitalized
$
438

 
$
231

 
$
135

Non-cash conveyance of assets

 

 
13


The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $271 million, $265 million and $231 million as of December 31, 2017, 2016 and 2015, respectively.

NOTE 17—GUARANTEES

In February 2016, Cheniere Partners entered into the 2016 CQP Credit Facilities, which included an approximately $2.1 billion SPLNG tranche term loan and a $450.0 million CTPL tranche term loan that were used to satisfy our subsidiaries’ outstanding debt obligations in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (“the 2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with Sabine Pass LP subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of December 31, 2017, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us but not including our non-guarantor subsidiary’s assets and rights, and our real property (except for certain excluded properties). As of December 31, 2017, the collateralized net assets of the CQP Guarantors was $2.1 billion.

NOTE 18—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:
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 provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).
 
January 1, 2018
 
We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Consolidated Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 11—Revenues from Contracts with Customers.

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CHENIERE ENERGY INVESTMENTS, LLC AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



Standard
 
Description
 
Expected Date of Adoption
 
Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto
 
This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.
 
January 1, 2019

 
We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases on our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.
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.

Additionally, the following table provides a brief description of a recent accounting standard that was adopted by us during the reporting period:
Standard
 
Description
 
Date of Adoption
 
Effect on our Consolidated Financial Statements or Other Significant Matters
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
 
The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.



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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY INVESTMENTS, LLC

CONDENSED BALANCE SHEETS
(in millions) 

 
 
December 31,
 
 
2017
 
2016
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$

 
$

Restricted cash
 
1

 
12

Accounts receivable—affiliate
 
31

 
21

Other current assets—affiliate
 

 
10

Total current assets
 
32

 
43

 
 
 
 
 
Investment in affiliates
 
2,011

 
2,591

Total assets
 
$
2,043

 
$
2,634

 
 
 
 
 
LIABILITIES AND MEMBER’S EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Due to affiliates
 
$
31

 
$
63

 
 
 
 
 
Other non-current liabilities—affiliate
 

 
2

 
 
 
 
 
Member’s equity
 
2,012

 
2,569

Total liabilities and member’s equity
 
$
2,043

 
$
2,634




























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

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY INVESTMENTS, LLC

CONDENSED STATEMENTS OF OPERATIONS
(in millions) 

 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Revenues—affiliate
 
$
155

 
$
135

 
$
167

 
 
 
 
 
 
 
Operating and maintenance expense—affiliate
 
219

 
328

 
421

 
 
 
 
 
 
 
Loss from operations
 
(64
)

(193
)

(254
)
 
 
 
 
 
 
 
Equity income (loss) of affiliates
 
718

 
70

 
(74
)
 
 
 
 
 
 
 
Net income (loss)
 
$
654


$
(123
)

$
(328
)




































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

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SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY INVESTMENTS, LLC

CONDENSED STATEMENTS OF CASH FLOWS
(in millions) 
 
Year Ended December 31,
 
2017
 
2016
 
2015
Cash provided by (used in) operating activities
$
475

 
$
(178
)
 
$
(245
)
 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
Investments in subsidiaries
(130
)
 
(2,422
)
 
(91
)
Distributions received from affiliates, net
856

 
360

 
337

Net cash provided by (used in) investing activities
726


(2,062
)

246

 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 

Capital contributions
219

 
2,439

 
91

Distributions
(1,431
)
 
(216
)
 
(84
)
Net cash provided by (used in) financing activities
(1,212
)

2,223


7

 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
(11
)

(17
)

8

Cash, cash equivalents and restricted cash—beginning of period
12

 
29

 
21

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


$
12


$
29




Balances per Condensed Balance Sheets:
 
December 31
 
2017
 
2016
Cash and cash equivalents
$

 
$

Restricted cash
1

 
12

Total cash, cash equivalents and restricted cash
$
1


$
12






















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

S-37


SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CHENIERE ENERGY INVESTMENTS, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
The Condensed Financial Statements represent the financial information required by Securities and Exchange Commission Regulation S-X 5-04 for Cheniere Investments.
 
A substantial amount of Cheniere Investments’ operating, investing and financing activities are conducted by its affiliates. In the Condensed Financial Statements, Cheniere Investments’ investments in affiliates are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are recorded on the Condensed Balance Sheets. The gain (loss) from operations of the affiliates is reported on a net basis as equity loss of affiliates.

We use the cumulative earnings approach for classifying distributions received from our equity method investees on the Condensed Statements of Cash Flows. The cumulative earnings approach dictates that distributions received by an investor are viewed as a return on investment and classified as cash flows from operating activities unless the cumulative distributions received exceed the cumulative equity in earnings recognized by the investor. Distributions received in excess of cumulative earnings are viewed as a return of investment and classified as cash flows from investing activities.

The Condensed Financial Statements should be read in conjunction with Cheniere Investments’ Consolidated Financial Statements.

NOTE 2—REVENUES FROM CONTRACTS WITH CUSTOMERS

Revenues—affiliate

Cheniere Investments has operation and maintenance agreements with SPLNG, SPL and CTPL whereby Cheniere Investments provides the services required to operate and maintain the regasification facilities at the Sabine Pass LNG terminal, the natural gas liquefaction facilities at the Sabine Pass LNG terminal (the “Liquefaction Project”) and the pipeline owned and operated by CTPL, respectively.

SPLNG pays a fixed monthly fee of $130,000 (indexed for inflation) under its operation and maintenance agreement and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between SPLNG and Cheniere Investments at the beginning of each operating year. In addition, SPLNG is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses.

Under the operation and maintenance agreement with SPL, before each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on behalf of SPL, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing staffing reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, SPL is required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, SPL will pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the Train.

CTPL is required to only reimburse Cheniere Investments for its operating expenses under its operation and maintenance agreement, which consist primarily of labor expenses.

Cheniere Investments provides the services required under each of the operation and maintenance agreements pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. Cheniere Investments is generally required to remit all fees received from its customers to such subsidiary. We have determined that Cheniere Investments is acting as a principal in each of these transactions given its control of the services prior to the transfer to the customers. Because Cheniere Investments is acting

S-38


as a principal to the transactions, it recognizes consideration earned from customers within revenues—affiliate while it records operating and maintenance expense—affiliate when such fees are due to the subsidiary under the secondment agreement.

Because Cheniere Investments is providing operation and maintenance services to SPLNG and CTPL on a daily basis with the same pattern of transfer, we have concluded that Cheniere Investments provides a single performance obligation to each of these customers on a continuous basis over time. However, as the service Cheniere Investment provides SPL increases over time as Trains are constructed and enter service, we have determined that Cheniere Investments provides a separate performance obligation to SPL for each Train during both the construction and operational phases, each of which is also transferred to SPL on a continuous basis over time with the same pattern of transfer. For each customer, we have determined that an output method of recognition based on elapsed time best reflects the benefits of each of the services to the customers. We have concluded that the variable consideration within each contract, including inflation, the SPLNG bonus, the SPL fee based on capital expenditures and the operating expense reimbursements from each customer, meet the optional exception to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:
 
 
Unsatisfied
Transaction Price
(in millions)
 
Weighted Average Recognition Timing (years) (1)
Revenues—affiliate
 
$
124

 
10.1

 
    
(1)
The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We have elected omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.



S-39
















Sabine Pass LNG-LP, LLC
Consolidated Financial Statements
As of December 31, 2017 and 2016
and for the years ended December 31, 2017, 2016 and 2015







S-40


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES


DEFINITIONS
As used in these Consolidated Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms
Bcf/d
 
billion cubic feet per day
Bcfe
 
billion cubic feet equivalent
EPC
 
engineering, procurement and construction
GAAP
 
generally accepted accounting principles in the United States
Henry Hub
 
the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR
 
London Interbank Offered Rate
LNG
 
liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu
 
million British thermal units, an energy unit
mtpa
 
million tonnes per annum
SPA
 
LNG sale and purchase agreement
TBtu
 
trillion British thermal units, an energy unit
Train
 
an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA
 
terminal use agreement



S-41


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES


Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2017, including our ownership of certain subsidiaries, and the references to these entities used in these Consolidated Financial Statements:

orgcharta60.jpg

Unless the context requires otherwise, references to “Sabine Pass LP,” “the Company,” “we,” “us” and “our” refer to Sabine Pass LNG-LP, LLC and its consolidated subsidiaries, including SPL, SPLNG and Tug Services.


S-42


Independent Auditors’ Report
To the Member of Sabine Pass LNG-LP, LLC:

We have audited the accompanying consolidated financial statements of Sabine Pass LNG-LP, LLC and its subsidiaries (the Company), which comprise the consolidated balance sheets as of December 31, 2017 and 2016, and the related consolidated statements of operations, member’s equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the consolidated financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sabine Pass LNG-LP, LLC and its subsidiaries as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2017 in accordance with U.S. generally accepted accounting principles.
Emphasis of Matter
As discussed in Note 2 to the consolidated financial statements, in 2017, 2016 and 2015, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. Our opinion is not modified with respect to this matter.

S-43


Other Matter
Our audit was conducted for the purpose of forming an opinion on the consolidated financial statements as a whole. The financial statement schedule I is presented for purposes of additional analysis and is not a required part of the consolidated financial statements. Such information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the consolidated financial statements. The information has been subjected to the auditing procedures applied in the audit of the consolidated financial statements and certain additional procedures, including comparing and reconciling such information directly to the underlying accounting and other records used to prepare the consolidated financial statements or to the consolidated financial statements themselves, and other additional procedures in accordance with auditing standards generally accepted in the United States of America. In our opinion, the information is fairly stated in all material respects in relation to the consolidated financial statements as a whole.

/s/ KPMG LLP

Houston, Texas
June 15, 2018


S-44


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES


CONSOLIDATED BALANCE SHEETS
(in millions)
 
 
December 31,
 
 
2017
 
2016
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$

 
$

Restricted cash
 
556

 
359

Accounts and other receivables
 
190

 
90

Accounts receivable—affiliate
 
163

 
100

Advances to affiliate
 
32

 
32

Inventory
 
94

 
96

Other current assets
 
55

 
26

Other current assets—affiliate
 
1

 
1

Total current assets
 
1,091

 
704

 
 
 
 
 
Property, plant and equipment, net
 
14,518

 
13,512

Debt issuance costs, net
 
18

 
59

Non-current derivative assets
 
17

 
67

Other non-current assets, net
 
197

 
214

Total assets
 
$
15,841

 
$
14,556

 
 
 
 
 
LIABILITIES AND MEMBER’S EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
11

 
$
26

Accrued liabilities
 
613

 
415

Current debt
 

 
224

Due to affiliates
 
72

 
35

Deferred revenue
 
111

 
73

Deferred revenue—affiliate
 
1

 
11

Derivative liabilities
 

 
11

Total current liabilities
 
808

 
795

 
 
 
 
 
Long-term debt, net
 
13,477

 
11,649

Non-current deferred revenue
 
1

 
5

Non-current derivative liabilities
 
3

 
2

Other non-current liabilities
 
10

 

Other non-current liabilities—affiliate
 
25

 
26

 
 
 
 
 
Commitments and contingencies (see Note 14)
 
 
 
 
 
 
 
 
 
Member’s equity
 
1,517

 
2,079

Total liabilities and member’s equity
 
$
15,841

 
$
14,556












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

S-45


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)

 
Year Ended December 31,
 
2017
 
2016
 
2015
Revenues
 
 
 
 
 
LNG revenues
$
2,635

 
$
539

 
$

LNG revenues—affiliate
1,389

 
294

 

Regasification revenues
260

 
259

 
259

Regasification revenues—affiliate
64

 
193

 
254

Other revenues
20

 
4

 
7

Other revenues—affiliate

 
4

 
3

Total revenues
4,368

 
1,293

 
523

 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
Cost (cost recovery) of sales (excluding depreciation and amortization expense shown separately below)
2,317

 
410

 
(31
)
Cost of sales—affiliate

 
2

 

Operating and maintenance expense
279

 
116

 
57

Operating and maintenance expense—affiliate
157

 
86

 
24

Development expense
3

 

 
3

Development expense—affiliate

 

 
1

General and administrative expense
7

 
8

 
9

General and administrative expense—affiliate
67

 
77

 
102

Depreciation and amortization expense
319

 
136

 
47

Other
2

 

 

Total operating costs and expenses
3,151

 
835

 
212

 
 
 
 
 
 
Income from operations
1,217

 
458

 
311

 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
Interest expense, net of capitalized interest
(503
)
 
(333
)
 
(197
)
Loss on early extinguishment of debt
(42
)
 
(70
)
 
(96
)
Derivative loss, net
(2
)
 
(6
)
 
(42
)
Other income
7

 
1

 

Total other expense
(540
)
 
(408
)
 
(335
)
 
 
 
 
 
 
Net income (loss)
$
677

 
$
50

 
$
(24
)















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

S-46


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
(in millions)


 
Cheniere Energy Investments, LLC
 
Total Member’s Equity
Balance at December 31, 2014
$
626

 
$
626

Contributions
74

 
74

Distributions
(347
)
 
(347
)
Net loss
(24
)
 
(24
)
Balance at December 31, 2015
329

 
329

Contributions
2,011

 
2,011

Distributions
(311
)
 
(311
)
Net income
50

 
50

Balance at December 31, 2016
2,079

 
2,079

Contributions
111

 
111

Distributions
(1,350
)
 
(1,350
)
Net income
677

 
677

Balance at December 31, 2017
$
1,517

 
$
1,517



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

S-47


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

 
Year Ended December 31,
 
2017
 
2016
 
2015
Cash flows from operating activities
 
 
 
 
 
Net income (loss)
$
677

 
$
50

 
$
(24
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
Non-cash LNG inventory write-downs

 

 
18

Depreciation and amortization expense
319

 
136

 
47

Amortization of debt issuance costs, deferred commitment fees, premium and discount
19

 
20

 
11

Loss on early extinguishment of debt
42

 
70

 
96

Total losses (gains) on derivatives, net
26

 
(36
)
 
7

Net cash used for settlement of derivative instruments
(14
)
 
(7
)
 
(41
)
Other
13

 
9

 
8

Changes in operating assets and liabilities:
 
 
 
 
 
Accounts and other receivables
(100
)
 
(90
)
 

Accounts receivable—affiliate
(62
)
 
(98
)
 
1

Advances to affiliate
(14
)
 
2

 
(10
)
Inventory
12

 
(58
)
 
(24
)
Accounts payable and accrued liabilities
190

 
168

 
(3
)
Due to affiliates
26

 
(6
)
 
11

Deferred revenue
34

 
42

 
(4
)
Other, net
(2
)
 
(5
)
 
(10
)
Other, net—affiliate
(12
)
 
(9
)
 
3

Net cash provided by operating activities
1,154

 
188


86

 
 
 
 
 
 
Cash flows from investing activities
 

 
 

 
 
Property, plant and equipment, net
(1,298
)
 
(2,307
)
 
(2,866
)
Other

 
(37
)
 
(62
)
Net cash used in investing activities
(1,298
)

(2,344
)

(2,928
)
 
 
 
 
 
 
Cash flows from financing activities
 

 
 

 
 
Proceeds from issuances of debt
2,314

 
5,443

 
2,860

Repayments of debt
(703
)
 
(4,851
)
 

Debt issuance and deferred financing costs
(29
)
 
(42
)
 
(169
)
Debt extinguishment costs

 
(14
)
 

Capital contributions
109

 
2,002

 
67

Distributions
(1,350
)
 
(311
)
 
(337
)
Net cash provided by financing activities
341

 
2,227


2,421

 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
197


71


(421
)
Cash, cash equivalents and restricted cash—beginning of period
359

 
288

 
709

Cash, cash equivalents and restricted cash—end of period
$
556


$
359


$
288


Balances per Consolidated Balance Sheets:
 
December 31,
 
2017
 
2016
Cash and cash equivalents
$

 
$

Restricted cash
556

 
359

Total cash, cash equivalents and restricted cash
$
556

 
$
359



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

S-48


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We are a Delaware limited liability company formed in 2005 with one member, Cheniere Investments. Through SPL, we are developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. We plan to construct up to six Trains, which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 mtpa and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. Through SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Sabine Pass LP and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto using the full retrospective method. We have elected to adopt the new accounting standard retrospectively for all periods presented.

We have evaluated subsequent events through June 15, 2018, the date the Consolidated Financial Statements were available to be issued.

Use of Estimates
 
The preparation of 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. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, derivative instruments, asset retirement obligations (“AROs”) and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 7—Derivative Instruments. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 10—Debt, are based on quoted

S-49


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Non-financial assets and liabilities initially measured at fair value include intangible assets and AROs.
 
Revenue Recognition
 
We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. Revenues from the sale of LNG are recognized as LNG revenues. LNG regasification capacity payments are recognized as regasification revenues. See Note 11—Revenues from Contracts with Customers for further discussion of revenues.

Cash and Cash Equivalents
 
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
 
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.

Accounts Receivable

Accounts receivable is reported net of allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses.  The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral.  We did not recognize any bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

Inventory

LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued. During the year ended December 31, 2015, we recognized $18 million as operating and maintenance expense as a result of write-down for LNG inventory purchased to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal. We did not recognize any operating and maintenance expense related to inventory write-downs during the years ended December 31, 2017 and 2016.

Accounting for LNG Activities
 
Generally, we begin capitalizing the costs of our LNG terminals once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminals.
 
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as other non-current assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.
 
We capitalize interest and other related debt costs during the construction period of our LNG terminal. Upon commencement of operations, capitalized interest, as a component of the total cost, is amortized over the estimated useful life of the asset.

Property, Plant and Equipment 

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are

S-50


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



generally expensed as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in other operating costs and expenses.
 
Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.  We did not record any impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 and 2015.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for and we elect the normal purchases and sales exception. When we have the contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria, including completing contemporaneous hedge documentation. We did not have any derivative instruments designated as cash flow hedges during the years ended December 31, 2017, 2016 and 2015. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Concentration of Credit Risk
 
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. Certain of our commodity derivative transactions 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. Collateral deposited for such contracts is recorded as other current asset. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

SPL has entered into six fixed price SPAs with terms of at least 20 years with six unaffiliated third parties. SPL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 15—Customer Concentration for additional details about our customer concentration.
 
SPLNG has entered into two long-term TUAs with unaffiliated third parties for regasification capacity at the Sabine Pass LNG terminal. SPLNG is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective TUAs.

Debt

Our debt consists of current and long-term secured debt securities and credit facilities with banks and other lenders.  Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.  


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Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment of debt are recorded in gains and losses on the extinguishment of debt on our Consolidated Statements of Operations.

Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are recorded as a direct deduction from the debt liability unless incurred in connection with a line of credit arrangement, in which case they are presented as an asset on our Consolidated Balance Sheets. Debt issuance costs are amortized to interest expense or property, plant and equipment over the term of the related debt facility. Upon early retirement of debt or amendment to a debt agreement, certain fees are written off to loss on early extinguishment of debt.

Asset Retirement Obligations
 
We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our assessment of AROs is described below.
 
We have not recorded an ARO associated with the Sabine Pass LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.

Income Taxes 

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.

At December 31, 2017, the tax basis of our assets and liabilities was $3.0 billion less than the reported amounts of our assets and liabilities. See Note 12—Related Party Transactions for details about income taxes under our subsidiaries’ tax sharing agreements.

Business Segment

Our liquefaction and regasification operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of Sabine Pass LP in total when evaluating financial performance and for purposes of allocating resources.

NOTE 3—RESTRICTED CASH

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of December 31, 2017 and 2016, restricted cash consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Current restricted cash
 
 
 
 
Liquefaction Project
 
$
544

 
$
358

Cash held by Cheniere Partners’ guarantor subsidiaries, including us
 
12

 
1

Total current restricted cash
 
$
556

 
$
359



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



Under the terms of the credit and guaranty agreement aggregating $2.8 billion that Cheniere Partners entered into in February 2016 (the “2016 CQP Credit Facilities”), Cheniere Partners’ guarantor subsidiaries are required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities. See Note 17—Guarantees for information regarding Cheniere Partners’ guarantor subsidiaries.

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of December 31, 2017 and 2016, accounts and other receivables consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
SPL trade receivable
 
$
185

 
$
88

Other accounts receivable
 
5

 
2

Total accounts and other receivables
 
$
190

 
$
90


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 Liquefaction Project and other restricted payments.

NOTE 5—INVENTORY

As of December 31, 2017 and 2016, inventory consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Natural gas
 
$
17

 
$
15

LNG
 
26

 
45

Materials and other
 
51

 
36

Total inventory
 
$
94

 
$
96


NOTE 6—PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in millions):
 
 
December 31,
 
 
2017
 
2016
LNG terminal costs
 
 
 
 
LNG terminal
 
$
11,956

 
$
7,250

LNG terminal construction-in-process
 
3,289

 
6,680

Accumulated depreciation
 
(732
)
 
(424
)
Total LNG terminal costs, net
 
14,513


13,506

Fixed assets
 
 

 
 

Fixed assets
 
14

 
12

Accumulated depreciation
 
(9
)
 
(6
)
Total fixed assets, net
 
5


6

Property, plant and equipment, net
 
$
14,518


$
13,512


Depreciation expense was and $311 million, $129 million and $47 million in the years ended December 31, 2017, 2016 and 2015, respectively.

We realized offsets to LNG terminal costs of $301 million and $201 million in the years ended December 31, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Train of the Liquefaction Project, during the testing phase for its construction.


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LNG Terminal Costs

The Sabine Pass LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 6 and 50 years, as follows:
Components
 
Useful life (yrs)
LNG storage tanks
 
50
Marine berth, electrical, facility and roads
 
35
Regasification processing equipment
 
30
Sendout pumps
 
20
Liquefaction processing equipment
 
6-50
Other
 
15-30

Fixed Assets

Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”). SPL had previously entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under one of its credit facilities (“Interest Rate Derivatives”), which were settled in March 2017.
We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. 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 to the extent not utilized for the commissioning process.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of December 31, 2017 and 2016, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).
 
Fair Value Measurements as of
 
December 31, 2017
 
December 31, 2016
 
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
Interest Rate Derivatives liability
$

 
$

 
$

 
$

 
$

 
$
(6
)
 
$

 
$
(6
)
Liquefaction Supply Derivatives asset (liability)
2

 
10

 
43

 
55

 
(4
)
 
(2
)
 
79

 
73


We value our Interest Rate Derivatives using an income-based approach, utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using a market based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.

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 satisfaction of conditions precedent, including completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow, we recognize a gain or loss based on the fair value of the respective natural gas supply contracts.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace. 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 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.

The Level 3 fair value measurements of our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of December 31, 2017:
 
 
Net Fair Value Asset
(in millions)
 
Valuation Approach
 
Significant Unobservable Input
 
Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives
 
$43
 
Market approach incorporating present value techniques
 
Basis Spread
 
$(0.503) - $0.432

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Balance, beginning of period
 
$
79

 
$
32

 
$

Realized and mark-to-market gains (losses):
 
 
 
 
 
 
Included in cost of sales (1)
 
(37
)
 
48

 
32

Purchases and settlements:
 
 
 
 
 
 
Purchases
 
14

 
1

 

Settlements (1)
 
(12
)
 
(2
)
 

Transfers out of Level 3
 
(1
)
 

 

Balance, end of period
 
$
43

 
$
79

 
$
32

Change in unrealized gains relating to instruments still held at end of period
 
$
(37
)
 
$
49

 
$
32

 
    
(1)
Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the year ended December 31, 2016.
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. Additionally, we evaluate our own ability to meet our commitments in instances where our derivative instruments are in a liability position. Our derivative instruments are subject to contractual provisions which provide for the unconditional right of set-off for all derivative assets and liabilities with a given counterparty in the event of default.
 
Interest Rate Derivatives

SPL had entered into 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”), based on a portion of the expected outstanding borrowings over the term of the 2015 SPL Credit Facilities. In March 2017, SPL settled the Interest Rate Derivatives and recognized a derivative loss of $7 million in conjunction with the termination of approximately $1.6 billion of commitments under the 2015 SPL Credit Facilities, as discussed in Note 10—Debt.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



The following table shows the fair value and location of our Interest Rate Derivatives on our Consolidated Balance Sheets (in millions):
 
 
 
 
Fair Value Measurements as of
 
 
Consolidated Balance Sheet Location
 
December 31, 2017
 
December 31, 2016
Interest Rate Derivatives
 
Derivative liabilities
 
$

 
$
(4
)
Interest Rate Derivatives
 
Non-current derivative liabilities
 

 
(2
)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative loss, net on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Interest Rate Derivatives loss
 
$
(2
)
 
$
(6
)
 
$
(42
)

Liquefaction Supply Derivatives

SPL has entered into index-based physical natural gas supply contracts and associated economic hedges, if applicable, to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the noncurrent physical natural gas supply contracts range from approximately one to seven years, most of which commence upon the satisfaction of certain conditions precedent, if not already met, such as the date of first commercial delivery of specified Trains of the Liquefaction Project.

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.

SPL had secured up to approximately 2,214 TBtu and 1,994 TBtu of natural gas feedstock through natural gas supply contracts as of December 31, 2017 and 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,520 TBtu and 1,117 TBtu as of December 31, 2017 and 2016, respectively.

The following table shows the fair value and location of our Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):
 
 
Fair Value Measurements as of (1)
Consolidated Balance Sheet Location
 
December 31, 2017
 
December 31, 2016
Other current assets
 
$
41

 
$
13

Non-current derivative assets
 
17

 
67

Total derivative assets
 
58

 
80

 
 
 
 
 
Derivative liabilities
 

 
(7
)
Non-current derivative liabilities
 
(3
)
 

Total derivative liabilities
 
(3
)
 
(7
)
 
 
 
 
 
Derivative asset, net
 
$
55

 
$
73

 
(1)
Does not include a collateral call of $1 million and a collateral deposit of $6 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of December 31, 2017 and 2016, respectively.


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The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
 
Year Ended December 31,
 
Consolidated Statement of Operations Location (1)
 
2017
 
2016
 
2015
Liquefaction Supply Derivatives loss (gain) (2)
Cost (cost recovery) of sales
 
$
24

 
$
(42
)
 
$
(33
)
 
(1)
Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.
(2)
Does not include the realized value associated with derivative instruments that settle through physical delivery.

Consolidated Balance Sheet Presentation

Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):
 
 
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 December 31, 2017
 
 
 
 
 
 
Liquefaction Supply Derivatives
 
$
64

 
$
(6
)
 
$
58

Liquefaction Supply Derivatives
 
(3
)
 

 
(3
)
As of December 31, 2016
 
 
 
 
 
 
Interest Rate Derivatives
 
$
(6
)
 
$

 
$
(6
)
Liquefaction Supply Derivatives
 
82

 
(2
)
 
80

Liquefaction Supply Derivatives
 
(11
)
 
4

 
(7
)

NOTE 8—OTHER NON-CURRENT ASSETS

As of December 31, 2017 and 2016, other non-current assets, net consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Advances made under EPC and non-EPC contracts
 
$
26

 
$
23

Advances made to municipalities for water system enhancements
 
93

 
95

Advances and other asset conveyances to third parties to support LNG terminals
 
30

 
31

Tax-related payments and receivables
 
25

 
28

Information technology service assets
 
22

 
26

Other
 
1

 
11

Total other non-current assets, net
 
$
197

 
$
214


NOTE 9—ACCRUED LIABILITIES
 
As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Interest costs and related debt fees
 
$
229

 
$
204

Sabine Pass LNG terminal costs
 
384

 
211

Total accrued liabilities
 
$
613

 
$
415



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



NOTE 10—DEBT
 
As of December 31, 2017 and 2016, our debt consisted of the following (in millions):
 
 
December 31,
 
 
2017
 
2016
Long-term debt:
 
 
 
 
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”), net of unamortized premium of $6 and $7
 
$
2,006

 
$
2,007

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

 
1,000

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

 
1,506

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

 
2,000

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

 
2,000

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

 
1,500

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

 
1,500

4.200% Senior Secured Notes due 2028 (“2028 SPL Senior Notes”), net of unamortized discount of $1 and zero
 
1,349

 

5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)
 
800

 

2015 SPL Credit Facilities
 

 
314

Unamortized debt issuance costs
 
(183
)
 
(178
)
Total long-term debt, net
 
13,477

 
11,649

 
 
 
 
 
Current debt:
 
 
 
 
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)
 

 
224

 
 
 
 
 
Total debt, net
 
$
13,477

 
$
11,873


Below is a schedule of future principal payments that we are obligated to make, based on current construction schedules, on our outstanding debt at December 31, 2017 (in millions): 
Years Ending December 31,
 
Principal Payments
2018
 
$

2019
 

2020
 

2021
 
2,000

2022
 
1,000

Thereafter
 
10,650

Total
 
$
13,650


SPL Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes, after provisioning for incremental interest required during construction, were used to prepay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities and, along with the net proceeds of the 2028 SPL Senior Notes, the remainder is being used to pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the Liquefaction Project in lieu of the terminated portion of the commitments under the 2015 SPL Credit Facilities.
  
In connection with the issuance of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2015 SPL Credit Facilities of $42 million during the year ended December 31, 2017.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



The terms of the 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes and 2028 SPL Senior Notes (collectively with the 2037 SPL Senior Notes, the “SPL Senior Notes”) are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain customary terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. 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. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025. As of December 31, 2017, SPL was in compliance with all covenants related to the SPL Senior Notes. Interest on the SPL Senior Notes is payable semi-annually in arrears.

At any time prior to three months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is six months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the “make-whole” price (except for the 2037 SPL Senior Notes, in which case the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within three months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), 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.

SPL Working Capital Facility

Below is a summary of the SPL Working Capital Facility as of December 31, 2017 (in millions):
 
 
SPL Working Capital Facility
Original facility size
 
$
1,200

Less:
 
 
Outstanding balance
 

Letters of credit issued
 
730

Available commitment
 
$
470

 
 
 
Interest rate
 
LIBOR plus 1.75% or base rate plus 0.75%
Maturity date
 
December 31, 2020, with various terms for underlying loans

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to an additional $390 million.

Loans under the SPL Working Capital Facility accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the senior facility agent’s published prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50% and one month LIBOR plus 0.50%), plus the applicable margin. The applicable margin for LIBOR 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 loans is due

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



and payable at the end of each applicable LIBOR period, and interest on base rate loans is due and payable at the end of each fiscal quarter. However, if such base rate loan is converted into a LIBOR 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 December 31, 2017, no LC Draws had been made upon any letters of credit issued under the SPL Working Capital Facility.

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

The SPL Working Capital Facility contains conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. As of December 31, 2017, SPL was in compliance with all covenants related to the SPL Working Capital Facility. 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.

Interest Expense

Total interest expense consisted of the following (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Total interest cost
 
$
788

 
$
796

 
$
689

Capitalized interest
 
(285
)
 
(463
)
 
(492
)
Total interest expense, net
 
$
503

 
$
333

 
$
197


Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our debt (in millions):
 
 
December 31, 2017
 
December 31, 2016
 
 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
Senior notes, net of premium or discount (1)
 
$
12,860

 
$
13,955

 
$
11,513

 
$
12,309

2037 SPL Senior Notes (2)
 
800

 
871

 

 

Credit facilities (3)
 

 

 
538

 
538

 
(1)
Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes and 2028 SPL Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.
(2)
The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 
(3)
Includes 2015 SPL Credit Facilities and SPL Working Capital Facility. 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.

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NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2017, 2016 and 2015 (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
LNG revenues
 
$
2,615

 
$
535

 
$

LNG revenues—affiliate
 
1,389

 
294

 

Regasification revenues
 
260

 
259

 
259

Regasification revenues—affiliate
 
64

 
193

 
254

Other revenues
 
20

 
4

 
7

Other revenues—affiliate
 

 
4

 
3

Total revenues from customers
 
4,348

 
1,289

 
523

Revenues from derivative instruments (1)
 
20

 
4

 

Total revenues
 
$
4,368

 
$
1,293

 
$
523

 
(1)
Relates to the realized value associated with a portion of derivative instruments that settle through physical delivery.

LNG Revenues

We have entered into numerous SPAs with third party customers for the sale of LNG on a Free on Board (“FOB”) (delivered to the customer at the Sabine Pass LNG terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG equal to approximately 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, at the Sabine Pass LNG terminal, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the sale was negotiated. We have concluded that the variable fees meet the optional exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the optional exception, variable consideration related to the sale of LNG is also not included in the transaction price.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.


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Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the optional exception for allocating variable consideration and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6.

Upon substantial completion of Train 3, which was in June 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. 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 and we continue to recognize the payments received from Total as revenue. During the year ended December 31, 2017, SPL recorded $23 million as operating and maintenance expense under this partial TUA assignment agreement.

Regasification Revenues—Affiliate

SPLNG has a terminal use rights assignment and agreement (the “TURA”) with SPL and Cheniere Investments pursuant to which Cheniere Investments had the right to use SPL’s reserved capacity under the TUA and had the obligation to pay a portion of the fees required by the TUA to SPLNG, of approximately $250 million per year (the “TUA Fees”). Cheniere Investments’ right to use capacity at SPLNG’s LNG terminal and its respective percentage of TUA fees payable was reduced from 100% to zero as each of Trains 1 through 4 of SPL’s Liquefaction Project reached commercial operations. Train 4 reached commercial operations in October 2017 at which time Cheniere Investments’ right to capacity and obligation to pay future fees were substantially eliminated. SPL’s portion of the TUA Fees and SPLNG’s related revenues are eliminated in consolidation.

The following table shows the percentage of all TUA Fees receivable from Cheniere Investments and SPL in accordance with the TURA:
Period
 
Percentage of TUA Fees Receivable from
Cheniere Investments
 
Percentage of TUA Fees Receivable from SPL
Prior to May 2016 (substantial completion of Train 1)
 
100%
 
0%
May 2016 - September 2016 (substantial completion of Train 2)
 
75%
 
25%
September 2016 - March 2017 (substantial completion of Train 3)
 
50%
 
50%
March 2017 - October 2017 (substantial completion of Train 4)
 
25%
 
75%
Thereafter
 
0%
 
100%

Cheniere Investments’ obligation to pay their percentage share of the approximately $250 million annual payments to us regardless of their use of the LNG terminal is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. SPLNG provides access to an integrated regasification service to Cheniere Investments. Because SPLNG reduces Cheniere Investment’s access to the terminal as each Train reaches substantial completion, we have concluded that each of the periods in the table above must be accounted for as separate performance obligations. We have allocated the transaction price to each performance obligation using estimated stand-alone selling prices corresponding with the customer’s access to capacity in that period. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer. We have concluded that the variable consideration within the contract meets the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.


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Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” and “Non-current deferred revenue” on our Consolidated Balance Sheets (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Deferred revenues, beginning of period
 
$
78

 
$
36

 
$
40

Cash received but not yet recognized
 
110

 
71

 
25

Revenue recognized from prior period deferral
 
(76
)
 
(29
)
 
(29
)
Deferred revenues, end of period
 
$
112

 
$
78

 
$
36


The following table reflects the changes in our contract liabilities to affiliate, which we classify as “Deferred revenue—affiliate” on our Consolidated Balance Sheets (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Deferred revenues—affiliate, beginning of period
 
$
11

 
$
22

 
$
22

Cash received but not yet recognized
 

 
10

 
21

Revenue recognized from prior period deferral
 
(10
)
 
(21
)
 
(21
)
Deferred revenues—affiliate, end of period
 
$
1

 
$
11

 
$
22


We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2017 and 2016 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs. Changes in deferred revenue during the years ended December 31, 2017, 2016 and 2015 are also attributable to differences between the timing of revenue recognition and the receipt of advance payments under our TUAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:
 
 
Unsatisfied
Transaction Price
(in billions)
 
Weighted Average Recognition Timing (years) (1)
LNG revenues
 
$
55.7

 
10.2

Regasification revenues
 
2.9

 
5.7

Total revenues
 
$
58.6

 
 
 
    
(1)
The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We have elected the following optional exemptions which omit certain potential future sources of revenue from the table above:
(1)
We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.
(2)
We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. During the year ended December 31, 2017,

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approximately 58% of our LNG revenues, 100% of our LNG revenues—affiliate and approximately 2% of our Regasification revenues were related to variable consideration received from customers.

We have entered into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching a final investment decision on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

NOTE 12—RELATED PARTY TRANSACTIONS
 
Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015 (in millions):
 
Year Ended December 31,
 
2017
 
2016
 
2015
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA
$
1,389

 
$
294

 
$

 
Regasification revenues—affiliate
TUA fees from Cheniere Investments
64

 
193

 
254

 
 
 
 
 
 
Other revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG

 
1

 
1

Terminal Marine Services Agreement

 
3

 
2

Total other revenues—affiliate


4


3

 
Cost of sales—affiliate
Fees under the Pre-commercial LNG Marketing Agreement

 
2

 

 
Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG

 
1

 
1

Natural Gas Transportation Agreement
73

 
40

 

Services Agreements
84

 
45

 
23

Total operating and maintenance expense—affiliate
157


86


24

 
Development expense—affiliate
Services Agreements

 

 
1

 
General and administrative expense—affiliate
Services Agreements
67

 
77

 
102


LNG Terminal Capacity Agreements

Terminal Use Agreements

SPL obtained approximately 2.0 Bcf/d of regasification capacity and other liquefaction support services under a TUA with SPLNG, as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to pay the TUA Fees until at least May 2036.

In connection with this TUA, SPL is required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, which is recorded as operating and maintenance expense on our Consolidated Statements of Operations.

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Pursuant to the TURA, Cheniere Investments had the right to use SPL’s reserved capacity under SPL’s TUA with SPLNG and had the obligation to pay the TUA Fees required by the TUA to SPLNG. See Note 11—Revenues from Contracts with Customers for information regarding these agreements.

Cheniere Marketing SPA

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

Cheniere Marketing Master SPA

SPL has an agreement with Cheniere Marketing that allows the parties to sell and purchase LNG with each other by executing and delivering confirmations under this agreement.

Commissioning Confirmation

Under the Cheniere Marketing Master SPA, SPL executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the periods while Bechtel Oil, Gas and Chemicals, Inc. had control of, and was commissioning, the first four Trains of the Liquefaction Project.

Pre-commercial LNG Marketing Agreement

SPL has an agreement with Cheniere Marketing that authorizes Cheniere Marketing to act on SPL’s behalf to market and sell certain quantities of pre-commercial LNG that has not been accepted by BG Gulf Coast LNG, LLC, one of SPL’s SPA customers. SPL pays a fee to Cheniere Marketing for marketing and transportation, which is based on volume sold under this agreement.

Natural Gas Transportation Agreements

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, SPL has a transportation precedent agreement and a negotiated rate agreement to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. These agreements have a primary term through 2036 and thereafter continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. In addition, SPL has the right to elect to extend the term of the agreements for up to two consecutive ten-year terms. Maximum rates, charges and fees shall be applicable for the entitlements and quantities delivered pursuant to the agreements unless CTPL has advised SPL that it has agreed otherwise.

Services Agreements

As of both December 31, 2017 and 2016, we had $32 million of advances to affiliates under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

SPLNG O&M Agreement

SPLNG has a long-term operation and maintenance agreement (the “SPLNG O&M Agreement”) with Cheniere Investments pursuant to which SPLNG receives all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. SPLNG pays a fixed monthly fee of $130,000 (indexed for inflation) under the SPLNG O&M Agreement and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between the parties at the beginning of each operating year. In addition, SPLNG is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses.
 

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SPLNG MSA

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

SPL O&M Agreement

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

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

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including SPL and SPLNG, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements
 
SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This ten-year initiative represented an aggregate commitment of $25 million in order to aid in their reconstruction efforts following Hurricane Rita, which SPLNG fulfilled in the first quarter of 2016. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to, and in the year the Cameron Parish dollar-for-dollar credit is applied against, ad valorem tax levied on our LNG terminal.

On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of both December 31, 2017 and 2016, we had $25 million of both other non-current assets resulting from SPLNG’s ad valorem tax payments and other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing.
 

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Contracts for Sale and Purchase of Natural Gas and LNG
 
SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing, LLC (“Cheniere Marketing US”). Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing US at a sales price equal to the actual purchase price paid by Cheniere Marketing US to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing US with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG terminal.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal.

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing US have an LNG Terminal Export Agreement that provides Cheniere Marketing US the ability to export LNG from the Sabine Pass LNG terminal.  SPLNG did not record any revenues associated with this agreement during the years ended December 31, 2017, 2016 and 2015.

State Tax Sharing Agreements

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

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

NOTE 13—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $12 million, $11 million and $10 million, respectively, related primarily to office space and land sites. Our land site leases for the Sabine Pass LNG terminal have initial terms varying up to 30 years with multiple options to renew up to an additional 60 years.

Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in millions): 
Years Ending December 31,
Operating Leases (1)
2018
$
2

2019
2

2020
2

2021
2

2022
2

Thereafter
38

Total
$
48

 
(1)
Includes certain lease option renewals that are reasonably assured.


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NOTE 14—COMMITMENTS AND CONTINGENCIES
 
We have 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 December 31, 2017, are not recognized as liabilities but require disclosures in our Consolidated Financial Statements.

LNG Terminal Commitments and Contingencies
 
Obligations under EPC Contract

SPL has a lump sum turnkey contract with Bechtel for the engineering, procurement and construction of Train 5 of the Liquefaction Project. The EPC contract for Train 5 provides that SPL will pay Bechtel a contract price of $3.1 billion, subject to adjustment by change order.  SPL has the right to terminate the EPC contract for its convenience, in which case Bechtel will be paid (1) the portion of the contract price for the work performed, (2) costs reasonably incurred by Bechtel on account of such termination and demobilization and (3) a lump sum of up to $30 million depending on the termination date.

Obligations under SPAs

SPL has third-party SPAs which obligate SPL to purchase and liquefy sufficient quantities of natural gas to deliver contracted volumes of LNG to the customers’ vessels, subject to completion of construction of specified Trains of the Liquefaction Project.

Obligations under LNG TUAs
 
SPLNG has third-party TUAs with Total and Chevron U.S.A. Inc. to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG terminal.

Obligations under Natural Gas Supply, Transportation and Storage Service Agreements

SPL has index-based physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The terms of these contracts primarily range from approximately one to seven years and commence upon the occurrence of conditions precedent, including SPL’s declaration to the respective natural gas supplier that it is ready to commence the term of the supply arrangement in anticipation of the date of first commercial operation of the applicable, specified Trains of the Liquefaction Project. As of December 31, 2017, SPL has secured up to approximately 2,214 TBtu of natural gas feedstock through natural gas supply contracts, a portion of which are considered purchase obligations if the conditions precedent were met.

Additionally, SPL has transportation and storage service agreements for the Liquefaction Project. The initial terms of the transportation agreements range from one to 20 years, with renewal options for certain contracts, and commence upon the occurrence of conditions precedent. The terms of the SPL storage service agreements range from three to ten years.

As of December 31, 2017, SPL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met were as follows (in millions): 
Years Ending December 31,
Payments Due (1)
2018
$
2,274

2019
1,527

2020
1,397

2021
981

2022
336

Thereafter
1,169

Total
$
7,684

 
(1)
Pricing of natural gas supply contracts are variable based on market commodity basis prices adjusted for basis spread. Amounts included are based on prices and basis spreads as of December 31, 2017.


S-68


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



Obligations under LNG TUA

SPL has a partial TUA assignment agreement with Total, another TUA customer, whereby upon substantial completion of Train 3 in March 2017, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG.  This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6. 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.

Services Agreements
 
We have certain services agreements with affiliates. See Note 12—Related Party Transactions for information regarding such agreements.

Restricted Net Assets
 
At December 31, 2017, our restricted net assets of consolidated subsidiaries were approximately $1.5 billion.

Other Commitments
 
State Tax Sharing Agreements
 
SPLNG and SPL have state tax sharing agreements with Cheniere. See Note 12—Related Party Transactions for information regarding such agreements.

Other Agreements

In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. Additionally, we have various lease commitments, as disclosed in Note 13—Leases.
 
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. In the opinion of management, as of December 31, 2017, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.

NOTE 15—CUSTOMER CONCENTRATION
  
The following table shows customers with revenues of 10% or greater of total third-party revenues and customers with accounts receivable balances of 10% or greater of total accounts receivable from third parties:
 
 
Percentage of Total Third-Party Revenues
 
Percentage of Accounts Receivable from Third Parties
 
 
Year Ended December 31,
 
December 31,
 
 
2017
 
2016
 
2015
 
2017
 
2016
Customer A
 
39%
 
52%
 
—%
 
39%
 
47%
Customer B
 
27%
 
*
 
—%
 
32%
 
50%
Customer C
 
23%
 
—%
 
—%
 
26%
 
—%
 
* Less than 10%

During the year ended December 31, 2017, revenues from external customers that were derived from domestic customers was $1.4 billion and from customers outside of the United States was $1.5 billion, of which $787 million and $666 million were

S-69


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



from customers in Ireland and South Korea, respectively. During the year ended December 31, 2016, revenues from external customers that were derived from domestic customers was $677 million and from customers outside of the United States was $125 million. During the year ended December 31, 2015, all revenues from external customers were derived from domestic customers. 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.

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of cash flow information (in millions):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Cash paid during the period for interest, net of amounts capitalized
 
$
438

 
$
229

 
$
123

Non-cash contributions from member for certain operating activities
 
2

 
9

 
7

Non-cash distributions to affiliates for conveyance of assets
 

 

 
10

Non-cash conveyance of assets to non-affiliate
 

 

 
13


The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $270 million, $264 million and $230 million, as of December 31, 2017, 2016 and 2015, respectively.

NOTE 17—GUARANTEES

In February 2016, Cheniere Partners entered into the 2016 CQP Credit Facilities, which included an approximately $2.1 billion SPLNG tranche term loan that was used to satisfy SPLNG’s outstanding debt obligations in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (“the 2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with us subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of December 31, 2017, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us but not including our non-guarantor subsidiary’s assets and rights, and our real property (except for certain excluded properties). As of December 31, 2017, the collateralized net assets of the CQP Guarantors was $2.1 billion.


S-70


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



NOTE 18—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:
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 provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).
 
January 1, 2018
 
We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Consolidated Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 11—Revenues from Contracts with Customers.
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto
 
This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.
 
January 1, 2019

 
We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases on our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We have not yet determined whether we will elect any other practical expedients upon transition.
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.

S-71


SABINE PASS LNG-LP, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED




Additionally, the following table provides a brief description of a recent accounting standard that was adopted by us during the reporting period:
Standard
 
Description
 
Date of Adoption
 
Effect on our Consolidated Financial Statements or Other Significant Matters
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
 
The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.



S-72


SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SABINE PASS LNG-LP, LLC

CONDENSED BALANCE SHEETS
(in millions) 

 
 
December 31,
 
 
2017
 
2016
ASSETS
 
 
 
 
Investment in affiliates
 
$
1,522

 
$
2,083

 
 
 
 
 
Total assets
 
$
1,522

 
$
2,083

 
 
 
 
 
LIABILITIES AND MEMBER’S EQUITY
 
 
 
 
 
 
 
 
 
Liabilities
 
$

 
$

 
 
 
 
 
Member’s equity
 
1,522

 
2,083

 
 
 
 
 
Total liabilities and member’s equity
 
$
1,522

 
$
2,083



































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

S-73


SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SABINE PASS LNG-LP, LLC

CONDENSED STATEMENTS OF OPERATIONS
(in millions) 
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Revenues
 
$

 
$

 
$

 
 
 
 
 
 
 
Equity income (loss) of affiliates
 
679

 
53

 
(24
)
 
 
 
 
 
 
 
Net income (loss)
 
$
679

 
$
53

 
$
(24
)









































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

S-74


SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SABINE PASS LNG-LP, LLC

CONDENSED STATEMENTS OF CASH FLOWS
(in millions) 
 
Year Ended December 31,
 
2017
 
2016
 
2015
Cash provided by (used in) operating activities
$
428

 
$
247

 
$
242

 
 
 
 
 
 
Cash flows from investing activities
 
 
 
 
 
Investments in subsidiaries
(108
)
 
(2,002
)
 
(67
)
Distributions received from affiliates, net
921

 
64

 
95

Net cash provided by (used in) investing activities
813


(1,938
)

28

 
 
 
 
 
 
Cash flows from financing activities
 
 
 
 
 

Capital contributions
109

 
2,002

 
67

Distributions
(1,350
)
 
(311
)
 
(337
)
Net cash provided by (used in) financing activities
(1,241
)

1,691


(270
)
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents





Cash and cash equivalents—beginning of period

 

 

Cash and cash equivalents—end of period
$


$


$
































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

S-75


SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SABINE PASS LNG-LP, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
The Condensed Financial Statements represent the financial information required by Securities and Exchange Commission Regulation S-X 5-04 for Sabine Pass LP.
 
A substantial amount of Cheniere Investments’ operating, investing and financing activities are conducted by its affiliates. In the Condensed Financial Statements, Sabine Pass LP’s investments in affiliates are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are recorded on the Condensed Balance Sheets. The gain (loss) from operations of the affiliates is reported on a net basis as equity loss of affiliates.

We use the cumulative earnings approach for classifying distributions received from our equity method investees on the Condensed Statements of Cash Flows. The cumulative earnings approach dictates that distributions received by an investor are viewed as a return on investment and classified as cash flows from operating activities unless the cumulative distributions received exceed the cumulative equity in earnings recognized by the investor. Distributions received in excess of cumulative earnings are viewed as a return of investment and classified as cash flows from investing activities.

The Condensed Financial Statements should be read in conjunction with Sabine Pass LP’s Consolidated Financial Statements.


S-76












Sabine Pass LNG, L.P.
Consolidated Financial Statements
As of December 31, 2017 and 2016
and for the years ended December 31, 2017, 2016 and 2015









S-77


SABINE PASS LNG, L.P. AND SUBSIDIARY


DEFINITIONS

As used in these Consolidated Financial Statements, the terms listed below have the following meanings: 

Common Industry and Other Terms
Bcf/d
 
billion cubic feet per day
Bcfe
 
billion cubic feet equivalent
GAAP
 
generally accepted accounting principles in the United States
LNG
 
liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
Train
 
an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA
 
terminal use agreement

S-78


SABINE PASS LNG, L.P. AND SUBSIDIARY


Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2017 and the references to these entities used in these Consolidated Financial Statements:

orgcharta57.jpg


Unless the context requires otherwise, references to “SPLNG,” “the Partnership,” “we,” “us” and “our” refer to Sabine Pass LNG, L.P. and its wholly owned subsidiary, Tug Services.


S-79


Independent Auditors’ Report
To the Managers of Sabine Pass LNG-GP, LLC and
Partners of Sabine Pass LNG, L.P.:
We have audited the accompanying consolidated financial statements of Sabine Pass LNG, L.P., and its subsidiary (the Partnership), which comprise the consolidated balance sheets as of December 31, 2017 and 2016, and the related consolidated statements of income, partners’ equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the consolidated financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sabine Pass LNG, L.P and its subsidiary as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2017 in accordance with U.S. generally accepted accounting principles.
Emphasis of Matter
As discussed in Note 2 to the consolidated financial statements, in 2017, 2016 and 2015, the Partnership adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. Our opinion is not modified with respect to this matter.

/s/ KPMG LLP

Houston, Texas
June 15, 2018


S-80


SABINE PASS LNG, L.P. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(in thousands)


 
December 31,
 
2017
 
2016
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$

 
$

Restricted cash
11,389

 
739

Accounts and other receivables
924

 
396

Accounts receivable—affiliate
3,069

 
1,353

Advances to affiliate
6,676

 
6,018

Inventory
8,974

 
7,259

Other current assets
2,295

 
2,973

Total current assets
33,327

 
18,738

 
 
 
 
Property, plant and equipment, net
1,603,054

 
1,641,133

Other non-current assets, net
27,630

 
29,081

Total assets
$
1,664,011

 
$
1,688,952

LIABILITIES AND PARTNERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
3,639

 
$
3,675

Accrued liabilities
6,996

 
7,247

Due to affiliates
8,377

 
2,322

Deferred revenue
26,817

 
26,709

Deferred revenue—affiliate
21,974

 
21,884

Total current liabilities
67,803

 
61,837

 
 
 
 
Non-current deferred revenue
1,500

 
5,500

Non-current deferred revenue—affiliate
24,533

 
24,533

Other non-current liabilities
9,918

 
166

Other non-current liabilities—affiliate
66

 
147

 
 
 
 
Commitments and contingencies (see Note 9)
 
 
 
 
 
 
 
Partners’ equity
1,560,191

 
1,596,769

Total liabilities and partners’ equity
$
1,664,011

 
$
1,688,952



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

S-81


SABINE PASS LNG, L.P. AND SUBSIDIARY


CONSOLIDATED STATEMENTS OF INCOME
(in thousands)

 
Year Ended December 31,
 
2017
 
2016
 
2015
Revenues
 
 
 
 
 
Regasification revenues
$
260,201

 
$
259,314

 
$
258,833

Regasification revenues—affiliate
254,891

 
254,013

 
253,538

Other revenues
19,351

 
3,716

 
6,804

Other revenues—affiliate
24,676

 
17,688

 
3,864

Total revenues
559,119

 
534,731

 
523,039

 
 
 
 
 
 
Operating costs and expenses
 
 
 
 
 
Operating and maintenance expense
37,458

 
41,436

 
35,004

Operating and maintenance expense—affiliate
18,036

 
18,029

 
22,792

Development expense
356

 

 

Development expense—affiliate
1

 

 

General and administrative expense
318

 
924

 
3,276

General and administrative expense—affiliate
9,005

 
9,056

 
14,182

Depreciation and amortization expense
54,843

 
53,201

 
44,985

Loss (gain) on disposal of assets
1,659

 
(8
)
 
(22
)
Total operating costs and expenses
121,676

 
122,638

 
120,217

 
 
 
 
 
 
Income from operations
437,443

 
412,093

 
402,822

 
 
 
 
 
 
Other income (expense)
 
 
 
 
 
Interest expense
(9,113
)
 
(147,635
)
 
(161,134
)
Loss on early extinguishment of debt

 
(18,188
)
 

Other income
27

 
526

 
89

Total other expense
(9,086
)
 
(165,297
)
 
(161,045
)
 
 
 
 
 
 
Net income
$
428,357

 
$
246,796

 
$
241,777



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

S-82


SABINE PASS LNG, L.P. AND SUBSIDIARY


CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY (DEFICIT)
(in thousands)

 
 
General Partner Sabine Pass
LNG-GP, LLC
 
Limited Partner Sabine Pass
LNG-LP, LLC
 
Total
Partners’
Equity (Deficit)
Balance at December 31, 2014
 
$

 
$
(646,471
)
 
$
(646,471
)
Net income
 

 
241,777

 
241,777

Contributions
 

 
140,130

 
140,130

Distributions
 

 
(337,320
)
 
(337,320
)
Balance at December 31, 2015
 

 
(601,884
)
 
(601,884
)
Net income
 

 
246,796

 
246,796

Contributions
 

 
2,262,510

 
2,262,510

Distributions
 

 
(310,653
)
 
(310,653
)
Balance at December 31, 2016
 

 
1,596,769

 
1,596,769

Net income
 

 
428,357

 
428,357

Contributions
 

 
102,618

 
102,618

Distributions
 

 
(567,553
)
 
(567,553
)
Balance at December 31, 2017
 
$

 
$
1,560,191

 
$
1,560,191



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

S-83


SABINE PASS LNG, L.P. AND SUBSIDIARY


CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
Year Ended December 31,
 
2017
 
2016
 
2015
Cash flows from operating activities
 
 
 
 
 
Net income
$
428,357

 
$
246,796

 
$
241,777

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization expense
54,843

 
53,201

 
44,985

Non-cash interest expense
9,113

 

 

Amortization of debt issuance costs and discount

 
8,183

 
8,922

Loss on early extinguishment of debt

 
18,188

 

Other
1,659

 
10

 
887

Other—affiliate
2,183

 
8,714

 
7,216

Changes in operating assets and liabilities:
 
 
 
 
 
Accounts receivable—affiliate
(1,716
)
 
(738
)
 
307

Advances to affiliate
(658
)
 
1,136

 
(5,286
)
Inventory
1,423

 
2,387

 
(5,972
)
Accounts payable and accrued liabilities
(482
)
 
(10,835
)
 
2,360

Due to affiliates
5,921

 
(6,570
)
 
4,671

Deferred revenue
(3,893
)
 
(3,960
)
 
(3,986
)
Other, net
1,284

 
3,714

 
(6,005
)
Other—affiliate
8

 
539

 
2,617

Net cash provided by operating activities
498,042

 
320,765

 
292,493

 
 
 
 
 
 
Cash flows from investing activities
 

 
 

 
 
Property, plant and equipment, net
(20,274
)
 
(5,386
)
 
(5,391
)
Other

 
(4,537
)
 

Net cash used in investing activities
(20,274
)
 
(9,923
)
 
(5,391
)
 
 
 
 
 
 
Cash flows from financing activities
 

 
 

 
 
Repayments of debt

 
(2,085,500
)
 

Debt extinguishment costs

 
(13,651
)
 

Capital contributions
100,435

 
2,000,994

 
52,400

Distributions
(567,553
)
 
(310,653
)
 
(337,320
)
Net cash used in financing activities
(467,118
)
 
(408,810
)
 
(284,920
)
 
 
 
 
 
 
Net increase (decrease) in cash, cash equivalents and restricted cash
10,650

 
(97,968
)
 
2,182

Cash, cash equivalents and restricted cash—beginning of period
739

 
98,707

 
96,525

Cash, cash equivalents and restricted cash—end of period
$
11,389

 
$
739

 
$
98,707


Balances per Consolidated Balance Sheets:
 
December 31,
 
2017
 
2016
Cash and cash equivalents
$

 
$

Restricted cash
11,389

 
739

Total cash, cash equivalents and restricted cash
$
11,389

 
$
739



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

S-84


SABINE PASS LNG, L.P. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We are a Houston-based Delaware limited partnership formed by Cheniere to own, develop and operate an LNG receiving and regasification terminal in western Cameron Parish, Louisiana, less than four miles from the Gulf Coast on the Sabine-Neches Waterway (our “LNG terminal”). Our LNG terminal includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of SPLNG and its wholly owned subsidiary. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to conform prior period information to the current presentation.  The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto using the full retrospective method. We have elected to adopt the new accounting standard retrospectively for all periods presented.

We have evaluated subsequent events through June 15, 2018, the date the Consolidated Financial Statements were available to be issued.

Use of Estimates
 
The preparation of 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. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value
 
The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value.

Revenue Recognition

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. LNG regasification capacity payments are recognized as regasification revenues and liquefaction support services are recognized as regasification revenues—affiliate. We recognize tug services fees that are received by Tug Services, which were historically included in regasification revenues but are now included within other revenues on our Consolidated Statements of Income. We also recognize cargo loading fees from SPL for the loading of LNG vessels at our LNG terminal, which are included within other revenues—affiliate on our Consolidated Statements of Income. See Note 6—Revenues from Contracts with Customers for further discussion of revenues.
 
Cash and Cash Equivalents

We did not have any cash and cash equivalents as of December 31, 2017 and 2016, since our operations are funded through contributions from Cheniere Partners or contractually restricted as to usage or withdrawal.


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Restricted Cash

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and has been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of both December 31, 2017 and 2016, the balance of restricted cash consisted of funds reserved for the payment of short-term operating expenses and capital expenditures.

Accounts Receivable

Accounts receivable is reported net of allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses. The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral. We did not recognize any bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

Inventory

LNG inventory is recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value and subsequently charged to expense when issued.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in loss (gain) on disposal of assets.

Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We have recorded no impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 or 2015.

Concentration of Credit Risk
 
We have entered into two long-term TUAs with unaffiliated third parties for regasification capacity at our LNG terminal. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective TUAs.

Asset Retirement Obligations
 
We recognize asset retirement obligations (“AROs”) for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our assessment of AROs is described below.
 
We have not recorded an ARO associated with our LNG terminal. Based on the real property lease agreements at our LNG terminal, at the expiration of the term of the leases, we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at our LNG terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender our LNG terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.


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Income Taxes

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Income, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.

At December 31, 2017, the tax basis of our assets and liabilities was $605 million less than the reported amounts of our assets and liabilities.

Business Segment

Our regasification operations at the Sabine Pass LNG terminal represent a single reportable segment. Our chief operating decision maker reviews the financial results of SPLNG in total when evaluating financial performance and for purposes of allocating resources. All of our revenues and long-lived assets are attributed to the United States.

NOTE 3—INVENTORY

As of December 31, 2017 and 2016, inventory consisted of the following (in thousands):

 
 
December 31,
 
 
2017
 
2016
LNG
 
$
539

 
$
402

Materials and other
 
8,435

 
6,857

Total inventory
 
$
8,974

 
$
7,259


NOTE 4—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in thousands): 

 
 
December 31,
 
 
2017
 
2016
LNG terminal costs
 
 
 
 
LNG terminal
 
$
1,993,215

 
$
1,980,019

LNG terminal construction-in-process
 
11,148

 
8,840

LNG site and related costs
 
120

 
128

Accumulated depreciation
 
(401,512
)
 
(347,987
)
Total LNG terminal costs, net
 
1,602,971

 
1,641,000

Fixed assets
 
 

 
 

Fixed assets
 
2,255

 
2,617

Accumulated depreciation
 
(2,172
)
 
(2,484
)
Total fixed assets, net
 
83

 
133

Property, plant and equipment, net
 
$
1,603,054

 
$
1,641,133


Depreciation expense was $53.9 million, $52.3 million and $45.0 million in the years ended December 31, 2017, 2016 and 2015, respectively.


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LNG Terminal Costs

Our LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of our LNG terminal with similar estimated useful lives have a depreciable range between 15 and 50 years, as follows:
Components
 
Useful life (yrs)
LNG storage tanks
 
50
Marine berth, electrical, facility and roads
 
35
Regasification processing equipment
 
30
Sendout pumps
 
20
Other
 
15-30

Fixed Assets

Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 5—OTHER NON-CURRENT LIABILITIES

We, through Tug Services, entered into an agreement in 2009 which required the contingent payment of a portion of our future tug service revenues to third party counterparties over the life of the agreement in exchange for an initial cash payment of $6.0 million. We classified the cash received in 2009 as other non-current liabilities on our Consolidated Balance Sheets and impute interest expense on the non-current liability using the effective interest method. We had other non-current liabilities of $9.8 million as of December 31, 2017 resulting from this agreement. The effective interest rate is computed based on estimated payments of tug service revenues to third party counterparties over the life of the agreement, which concludes in January 2028. Changes in estimated payments to be paid to the counterparties to the agreement are reflected prospectively in interest expense on our Consolidated Statements of Income. The interest rate on the liability may vary during the term of the agreement depending primarily on the aggregate total revenue earned by Tug Services. Payments made to counterparties pursuant to the agreement reduce the other non-current liability balance.

NOTE 6—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the years ended December 31, 2017, 2016 and 2015 (in thousands):

 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Regasification revenues
 
$
260,201

 
$
259,314

 
$
258,833

Regasification revenues—affiliate
 
254,891

 
254,013

 
253,538

Other revenues
 
19,351

 
3,716

 
6,804

Other revenues—affiliate
 
24,676

 
17,688

 
3,864

Total revenues
 
$
559,119

 
$
534,731

 
$
523,039


Regasification Revenues

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term TUAs with unaffiliated third-party customers, under which they are required to pay fixed monthly fees regardless of their use of the LNG terminal. Each of the customers has reserved approximately 1.0 Bcf/d of regasification capacity. The customers are each obligated to make monthly capacity payments to us aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. The remaining capacity of the Sabine Pass LNG terminal has been reserved by SPL, a wholly owned subsidiary of Cheniere Partners. See “Regasification revenues—affiliate” below for information on revenue from SPL.


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Because we are continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that we provide a single performance obligation to our customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the inflation element within the contract meets the optional exception for allocating variable consideration and accordingly the inflation adjustment is not included in the transaction price and will be recognized over the year in which the inflation adjustment relates on a straight-line basis.

In 2012, SPL entered into a partial TUA assignment agreement with Total Gas & Power North America, Inc. (“Total”), whereby SPL would progressively gain access to Total’s capacity and other services provided under its TUA with us. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of additional Trains.

Upon substantial completion of Train 3, SPL gained access to a portion of Total’s capacity and other services provided under Total’s TUA with us. Upon substantial completion of Train 5, SPL will gain access to substantially all of Total’s capacity. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to us will continue to be made by Total to us in accordance with its TUA and we continue to recognize the payments received from Total as third-party revenue.

Regasification Revenues—Affiliate

SPL obtained 2.0 Bcf/d of regasification capacity and other liquefaction support services as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with us. SPL is obligated to make monthly capacity payments to us aggregating approximately $250 million per year (the “TUA Fees”), continuing until May 2036. In addition, SPL is required to pay us $120,000 in cargo loading fees for each LNG vessel that they load at our LNG terminal.

We have a terminal use rights assignment and agreement (the “TURA”) with SPL and Cheniere Investments pursuant to which Cheniere Investments had the right to use SPL’s reserved capacity under the TUA and had the obligation to pay a portion of the TUA Fees required by the TUA to us. Cheniere Investments’ right to use capacity at our LNG terminal and its respective percentage of TUA fees payable was reduced from 100% to zero as each of Trains 1 through 4 of SPL’s liquefaction project reached commercial operations. Train 4 reached commercial operations in October 2017 at which time Cheniere Investments’ right to capacity and obligation to pay future fees were substantially eliminated.

The following table shows the percentage of all TUA Fees receivable from Cheniere Investments and SPL in accordance with the TURA:
Period
 
Percentage of TUA Fees Receivable from
Cheniere Investments
 
Percentage of TUA Fees Receivable from SPL
Prior to May 2016 (substantial completion of Train 1)
 
100%
 
0%
May 2016 - September 2016 (substantial completion of Train 2)
 
75%
 
25%
September 2016 - March 2017 (substantial completion of Train 3)
 
50%
 
50%
March 2017 - October 2017 (substantial completion of Train 4)
 
25%
 
75%
Thereafter
 
0%
 
100%

Cheniere Partners has guaranteed SPL’s obligations under the TUA and the obligations of Cheniere Investments under the TURA.

SPL’s obligation to pay their percentage share of the approximately $250 million annual payments to us regardless of their use of the LNG terminal is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. Cargo loading fees are also considered variable consideration because their receipt depends upon SPL’s use of liquefaction support services. Because we provide recurring firm liquefaction support service throughout the course of the agreement, and because SPL immediately receives the benefit of such performance, we have concluded that we have a single performance obligation for which the related revenues shall be recognized over time. We have determined that an output method of recognition based on the quantity of firm liquefaction support services used best reflects the benefits of this service to the customer. Because we expect that SPL shall use the full amount of firm liquefaction support services on a periodic basis, this methodology results in the recognition of such fixed fees on a substantially straight-line basis. We have

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



concluded that both the inflation element within the contract and cargo loading fees meet the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Cheniere Investments’ obligation to pay their percentage share of the approximately $250 million annual payments to us regardless of their use of the LNG terminal is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. SPLNG provides access to an integrated regasification service to Cheniere Investments. Because SPLNG reduces Cheniere Investments’ access to the terminal as each Train reaches substantial completion, we have concluded that each of the periods in the table above must be accounted for as separate performance obligations. We have allocated the transaction price to each performance obligation using estimated stand-alone selling prices corresponding with the customer’s access to capacity in that period. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer. We have concluded that the variable consideration within the contract meets the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Other Revenues

Tug Services has entered into arrangements to provide tug related services to each vessel that docks at the Sabine Pass LNG terminal. These customers pay tug services fees of $125,000 for each vessel that docks at our LNG terminal, which is included in other revenues. Because we are continuously available to provide tug services on a daily basis with the same pattern of transfer, we have concluded that we provide a single performance obligation to our customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer. Tug services fees are considered variable consideration because their receipt depends entirely upon the customer’s need to dock at the facility. We have concluded that the tug service fees meet the optional exemption to opt out of allocating variable consideration to the transaction price and we have elected to recognize such fees during the period to which they relate.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as “Deferred revenue” and “Non-current deferred revenue” on our Consolidated Balance Sheets (in thousands):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Deferred revenues, beginning of period
 
$
32,209

 
$
36,169

 
$
40,155

Cash received but not yet recognized
 
25,384

 
25,276

 
25,253

Revenue recognized from prior period deferral
 
(29,276
)
 
(29,236
)
 
(29,239
)
Deferred revenues, end of period
 
$
28,317

 
$
32,209

 
$
36,169


The following table reflects the changes in our contract liabilities to affiliate, which we classify as “Deferred revenue—affiliate” and “Non-current deferred revenue—affiliate” on our Consolidated Balance Sheets (in thousands):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Deferred revenues—affiliate, beginning of period
 
$
46,417

 
$
43,925

 
$
41,465

Cash received but not yet recognized
 
21,258

 
23,620

 
23,591

Revenue recognized from prior period deferral
 
(21,168
)
 
(21,128
)
 
(21,131
)
Deferred revenues—affiliate, end of period
 
$
46,507

 
$
46,417

 
$
43,925


We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. We recognize deferred revenue related to our TUAs because our customers are required to pay a month in advance of the associated service period. We have recorded non-current deferred revenue—affiliate representing a prepayment of SPL’s future obligations under the TUA.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:
 
 
Unsatisfied
Transaction Price
(in billions)
 
Weighted Average Recognition Timing (years) (1)
Regasification revenues
 
$
2.9

 
5.7

Regasification revenues—affiliate
 
4.6

 
9.2

Total revenues
 
$
7.5

 
 
 
    
(1)
The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes all variable consideration under our TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the number of LNG vessels loaded and adjustments to the consumer price index. During the year ended December 31, 2017, approximately 2% of our Regasification revenues and approximately 2% of our Regasification revenues—affiliate were related to variable consideration received from customers.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED




NOTE 7—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the years ended December 31, 2017, 2016 and 2015 (in thousands):
 
Year Ended December 31,
 
2017
 
2016
 
2015
Regasification revenues—affiliate
TUA fees from Cheniere Investments
$
64,408

 
$
193,497

 
$
253,538

TUA fees from SPL
190,483

 
60,516

 

Total regasification revenues—affiliate
254,891

 
254,013

 
253,538

 
Other revenues—affiliate
Sale of natural gas under TUA

 
1,349

 

Cargo loading fees under TUA
24,676

 
8,425

 

Contracts for Sale of Natural Gas and LNG

 
5,047

 
1,072

Other agreements

 
2,867

 
2,792

Total other revenues—affiliate
24,676

 
17,688

 
3,864

 
Operating and maintenance expense—affiliate
Contracts for Purchase of Natural Gas and LNG

 
607

 
1,121

Services Agreements
19,040

 
18,563

 
22,315

LNG Site Sublease Agreement
(960
)
 
(942
)
 
(712
)
Other agreements
(44
)
 
(199
)
 
68

Total operating and maintenance expense—affiliate
18,036

 
18,029

 
22,792

 
Development expense—affiliate
Services Agreements
1

 

 

 
General and administrative expense—affiliate
Services Agreements
9,005

 
9,056

 
14,182


Terminal Use Agreements

Pursuant to the TURA, Cheniere Investments had the right to use SPL’s reserved capacity under SPL’s TUA with us and had the obligation to pay the TUA Fees required by the TUA to us. See Note 6—Revenues from Contracts with Customers for information regarding these agreements.

Services Agreements

As of December 31, 2017 and 2016, we had $6.7 million and $6.0 million, respectively, of advances to affiliates under the services agreements described below. The non-reimbursable amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

Operation and Maintenance Agreement

We have a long-term operation and maintenance agreement (the “O&M Agreement”) with Cheniere Investments pursuant to which we receive all necessary services required to operate and maintain our LNG receiving terminal. We pay a fixed monthly fee of $130,000 (indexed for inflation) under the O&M Agreement and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between the parties at the beginning of each operating year. In addition, we are required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses.

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Management Services Agreement
 
We have a long-term management services agreement (the “MSA”) with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of our LNG receiving terminal, excluding those matters provided for under the O&M Agreement. We pay a monthly fixed fee of $520,000 (indexed for inflation) under the MSA.

Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.

Agreement to Fund Our Cooperative Endeavor Agreements

We have executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from 2007 through 2016. This ten-year initiative represented an aggregate commitment of $24.5 million in order to aid in their reconstruction efforts following Hurricane Rita, which we fulfilled in the first quarter of 2016. In exchange for our advance payments of annual ad valorem taxes, Cameron Parish will grant us a dollar-for-dollar credit against future ad valorem taxes to be levied against our LNG terminal starting in 2019. Beginning in September 2007, we entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay us additional TUA revenues equal to any and all amounts payable by us to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, we will make payments to Cheniere Marketing equal to, and in the year the Cameron Parish dollar-for-dollar credit is applied against, ad valorem tax levied on our LNG terminal.

These advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that we utilized to make the ad valorem tax payments were recorded as non-current deferred revenue—affiliate. As of both December 31, 2017 and 2016, we had $24.5 million of both other non-current assets resulting from ad valorem tax payments and non-current deferred revenue—affiliate resulting from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

We are able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing, LLC (“Cheniere Marketing US”). Under these agreements, we purchase natural gas or LNG from Cheniere Marketing US at a sales price equal to the actual purchase price paid by Cheniere Marketing US to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing US with respect to the receipt, purchase and delivery of the natural gas or LNG to our LNG terminal. We are also able to sell and purchase natural gas and LNG under an agreement with SPL.

Terminal Marine Services Agreement

In connection with our tug boat lease, Tug Services has an agreement with a wholly owned subsidiary of Cheniere to provide its LNG cargo vessels with tug boat and marine services at our LNG terminal. The agreement also provides that Tug Services shall contingently pay the wholly owned subsidiary of Cheniere a portion of its future revenues. Accordingly, Tug Services distributed $2.7 million to the wholly owned subsidiary of Cheniere during the year ended December 31, 2017. No amounts were distributed during the years ended December 31, 2016 and 2015.

LNG Site Sublease Agreement

We have agreements with SPL to sublease a portion of the LNG terminal site for its liquefaction project. The aggregate annual sublease payment is $0.9 million. The initial term of the sublease expires on December 31, 2034, with options to renew for multiple 10-year extensions with similar terms as the initial term. The annual sublease payment will be adjusted for inflation every five years based on a consumer price index, as defined in the sublease agreement.

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LNG Terminal Export Agreement

We have an LNG Terminal Export Agreement with Cheniere Marketing US that provides Cheniere Marketing US with the ability to export LNG from our LNG terminal.  We did not record any revenues associated with this agreement during the years ended December 31, 2017, 2016 and 2015.

Cooperation Agreement
We have an agreement (the “Cooperation Agreement”) with SPL to allow SPL to retain and acquire certain rights to access the property and facilities that we own for the purpose of constructing, modifying and operating SPL’s facilities under construction. In consideration for the access we have given, SPL has agreed to transfer title to us of certain facilities, equipment and modifications, which we are obligated to operate and maintain. The term of this agreement is consistent with our TUA described above. Under this agreement, SPL conveyed to us zero, $252.8 million and $80.5 million of assets during the years ended December 31, 2017, 2016 and 2015, respectively.

State Tax Sharing Agreement

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

NOTE 8—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $9.3 million, $8.9 million and $8.9 million, respectively, related primarily to tug boat leases and land site leases, net of sublease income of $1.0 million, $0.9 million and $0.7 million, respectively. Our land site leases for the LNG terminal have initial terms varying up to 30 years with multiple options to renew up to an additional 60 years.
 
Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in thousands): 
Year ending December 31,
Operating Leases (1)
2018
$
1,536

2019
1,536

2020
1,536

2021
1,536

2022
1,536

Thereafter (2)
33,696

Total minimum payments required
$
41,376

 
(1)
Lease payments for our land leases do not take into account the $26.4 million sublease payments we will receive from SPL, as discussed in Note 7—Related Party Transactions.
(2)
Includes certain lease option renewals that are reasonably assured for our land site leases.

NOTE 9—COMMITMENTS AND CONTINGENCIES
LNG TUA Commitments

We have TUAs with Total, Chevron U.S.A. Inc. and SPL to provide berthing for LNG vessels and for the unloading and loading, storage and regasification of LNG at our LNG terminal. See Note 7—Related Party Transactions for information regarding the agreement with SPL.


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Services Agreements

We have certain services agreements with affiliates. See Note 7—Related Party Transactions for information regarding such agreements.
 
State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere.  See Note 7—Related Party Transactions for information regarding this agreement.

Cooperative Endeavor Agreements

We have executed CEAs with various Cameron Parish, Louisiana taxing authorities. See Note 7—Related Party Transactions for information regarding such agreements.

Guarantees

Certain subsidiaries of Cheniere Partners, including us, have unconditionally guaranteed the debt obligations of Cheniere Partners. See Note 11—Guarantees for information regarding these guarantees.

Other Commitments
 
In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position. Additionally, we have various lease commitments, as disclosed in Note 8—Leases.

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. In the opinion of management, as of December 31, 2017, there were no pending legal matters that would reasonably be expected to have a material impact on our consolidated operating results, financial position or cash flows.

NOTE 10—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of cash flow information (in thousands):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Cash paid during the period for interest
 
$

 
$
154,412

 
$
152,213

Non-cash contributions for conveyance of assets under Cooperation Agreement
 

 
252,802

 
80,515

Non-cash contributions from limited partner for certain operating activities
 
2,183

 
8,714

 
7,215

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $2.2 million, $1.8 million and $1.6 million as of December 31, 2017, 2016 and 2015, respectively.


S-95


SABINE PASS LNG, L.P. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



NOTE 11—GUARANTEES
In February 2016, Cheniere Partners entered into a credit and guaranty agreement aggregating $2.8 billion (the “2016 CQP Credit Facilities”), which included an approximately $2.1 billion SPLNG tranche term loan that was used to satisfy our outstanding debt obligations in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (“the 2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with Sabine Pass LP subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of December 31, 2017, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us, and our real property (except for certain excluded properties).


S-96


SABINE PASS LNG, L.P. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



NOTE 12—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:
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 provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).
 
January 1, 2018
 
We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Consolidated Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Consolidated Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 6—Revenues from Contracts with Customers.
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto
 
This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.
 
January 1, 2019

 
We continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases on our Consolidated Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We have not yet determined whether we will elect any other practical expedients upon transition.
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.


S-97


SABINE PASS LNG, L.P. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED



Additionally, the following table provides a brief description of a recent accounting standard that was adopted by us during the reporting period:
Standard
 
Description
 
Date of Adoption
 
Effect on our Consolidated Financial Statements or Other Significant Matters
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
 
The adoption of this guidance did not have a material impact on our Consolidated Financial Statements or related disclosures.



S-98














Cheniere Creole Trail Pipeline, L.P.

Financial Statements

As of December 31, 2017 and 2016
and for the years ended December 31, 2017, 2016 and 2015







S-99


Independent Auditors’ Report
To the Managing Member of Cheniere Pipeline GP Interests, LLC:

We have audited the accompanying financial statements of Cheniere Creole Trail Pipeline, L.P. (the Partnership) which comprise the balance sheets as of December 31, 2017 and 2016, and the related statements of operations, partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes to the financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cheniere Creole Trail Pipeline, L.P. as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017 in accordance with U.S. generally accepted accounting principles.
Emphasis of Matter
As discussed in Note 2 to the financial statements, in 2017, 2016 and 2015, the Partnership adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto. Our opinion is not modified with respect to this matter.

/s/ KPMG LLP

Houston, Texas
June 15, 2018



S-100


CHENIERE CREOLE TRAIL PIPELINE, L.P.
BALANCE SHEETS
(in thousands)



 
 
December 31,
 
 
2017
 
2016
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$

 
$

Restricted cash
 
48

 
96

Accounts receivable—affiliate
 
6,805

 
6,805

Advances to affiliate
 
3,937

 
5,787

Inventory
 
1,536

 
1,651

Other current assets
 
1,014

 
302

Total current assets
 
13,340

 
14,641

 
 
 
 
 
Property, plant and equipment, net
 
560,534

 
578,737

Other non-current assets, net
 
9,583

 
7,859

Total assets
 
$
583,457

 
$
601,237

 
 
 
 
 
LIABILITIES AND PARTNERS’ EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
757

 
$
675

Accrued liabilities
 
219

 
299

Accrued liabilities—affiliate
 
3,991

 
1,888

Other current liabilities—affiliate
 
601

 
550

Total current liabilities
 
5,568

 
3,412

 
 
 
 
 
Other non-current liabilities—affiliate
 

 
390

 
 
 
 
 
Commitments and contingencies (see Note 8)
 
 
 
 
 
 
 
 
 
Partners’ equity
 
577,889

 
597,435

Total liabilities and partners’ equity
 
$
583,457

 
$
601,237



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

S-101



CHENIERE CREOLE TRAIL PIPELINE, L.P.
STATEMENTS OF OPERATIONS
(in thousands)



 
Year Ended December 31,
 
2017
 
2016
 
2015
Revenues—affiliate
$
81,762

 
$
56,363

 
$
1,117

 
 
 
 
 
 
Expenses
 
 
 

 
 
Operating and maintenance expense
7,709

 
4,774

 
2,689

Operating and maintenance expense—affiliate
12,088

 
11,137

 
4,996

General and administrative expense
1,589

 
1,103

 
3,399

General and administrative expense—affiliate
1,336

 
695

 
9,031

Depreciation and amortization expense
19,373

 
19,767

 
18,171

Total expenses
42,095

 
37,476

 
38,286

 
 
 
 
 
 
Income (loss) from operations
39,667

 
18,887

 
(37,169
)
 
 
 
 
 
 
Other income (expense)
 

 
 
 
 
Interest expense, net of capitalized interest

 
(581
)
 
(13,562
)
Loss on early extinguishment of debt

 
(1,457
)
 

Other income (expense)
(3
)
 
(2
)
 
16

Total other expense
(3
)
 
(2,040
)
 
(13,546
)
 
 
 
 
 
 
Net income (loss)
$
39,664

 
$
16,847

 
$
(50,715
)


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

S-102



CHENIERE CREOLE TRAIL PIPELINE, L.P.
STATEMENTS OF PARTNERS’ EQUITY
(in thousands)



 
 
General Partner Interest
 
Limited Partner Interest
 
Total Partners’
Equity
Balance at December 31, 2014
 
$

 
$
227,269

 
$
227,269

Net loss
 

 
(50,715
)
 
(50,715
)
Contributions
 

 
33,265

 
33,265

Balance at December 31, 2015
 

 
209,819

 
209,819

Net income
 

 
16,847

 
16,847

Contributions
 

 
420,248

 
420,248

Distributions
 

 
(49,479
)
 
(49,479
)
Balance at December 31, 2016
 

 
597,435

 
597,435

Net income
 

 
39,664

 
39,664

Contributions
 

 
22,532

 
22,532

Distributions
 

 
(81,742
)
 
(81,742
)
Balance at December 31, 2017
 
$

 
$
577,889

 
$
577,889



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

S-103



CHENIERE CREOLE TRAIL PIPELINE, L.P.
STATEMENTS OF CASH FLOWS
(in thousands)


 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Cash flows from operating activities
 
 
 
 
 
 
Net income (loss)
 
$
39,664

 
$
16,847

 
$
(50,715
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
 
 
 
Depreciation and amortization expense
 
19,373

 
19,767

 
18,171

Loss on early extinguishment of debt
 

 
1,457

 

Amortization of debt issuance costs and discount
 

 
192

 
1,034

Changes in operating assets and liabilities:
 
 
 
 
 
 
Accounts receivable—affiliate
 

 
(6,648
)
 
(188
)
Inventory
 
116

 
(372
)
 
(554
)
Accounts payable and accrued liabilities
 
(201
)
 
(1,379
)
 
(409
)
Accrued liabilities—affiliate
 
2,107

 
(2,680
)
 
3,906

Advances to affiliate
 
1,851

 
(1,417
)
 
(2,885
)
Other
 
(2,809
)
 
(1,049
)
 
144

Other—affiliate
 
(339
)
 
442

 
180

Net cash provided by (used in) operating activities
 
59,762

 
25,160

 
(31,316
)
 
 
 
 
 
 
 
Cash flows from investing activities
 
 

 
 

 
 
Property, plant and equipment, net
 
(600
)
 
(2,047
)
 
(18,621
)
Other
 

 
(1,654
)
 
(555
)
Net cash used in investing activities
 
(600
)
 
(3,701
)
 
(19,176
)
 
 
 
 
 
 
 
Cash flows from financing activities
 
 

 
 

 
 
Repayments of debt
 

 
(400,000
)
 

Debt duration fees
 

 

 
(1,000
)
Capital contributions
 
22,532

 
420,248

 
23,135

Distributions
 
(81,742
)
 
(49,479
)
 

Other
 

 
(13
)
 

Net cash provided by (used in) financing activities
 
(59,210
)
 
(29,244
)
 
22,135

 
 
 
 
 
 
 
Net decrease in cash, cash equivalents and restricted cash
 
(48
)
 
(7,785
)
 
(28,357
)
Cash, cash equivalents and restricted cash—beginning of period
 
96

 
7,881

 
36,238

Cash, cash equivalents and restricted cash—end of period
 
$
48

 
$
96

 
$
7,881


Balances per Balance Sheets:
 
 
December 31
 
 
2017
 
2016
Cash and cash equivalents
 
$

 
$

Restricted cash
 
48

 
96

Total cash, cash equivalents and restricted cash
 
$
48

 
$
96




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

S-104



CHENIERE CREOLE TRAIL PIPELINE, L.P. 
NOTES TO FINANCIAL STATEMENTS


NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Cheniere Creole Trail Pipeline, L.P. (“CTPL”), a Delaware limited partnership, is a Houston based partnership formed with one general partner, Cheniere Pipeline GP Interests, LLC, and one limited partner, Cheniere Energy Investments, LLC (“Cheniere Investments”), both of which are wholly owned subsidiaries of Cheniere Energy Partners, L.P. (“Cheniere Partners”). Cheniere Partners is a publicly-traded Delaware limited partnership formed by Cheniere Energy, Inc. (“Cheniere”). Unless the context requires otherwise, references to “we,” “us” and “our” refer to CTPL.

We were formed to own and operate a 94-mile pipeline (the “Creole Trail Pipeline”) interconnecting the Sabine Pass liquefied natural gas (“LNG”) terminal with a number of large interstate pipelines. The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Cheniere Partners is developing, constructing and operating natural gas liquefaction facilities (the “Liquefaction Project”) at the Sabine Pass LNG terminal through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC (“SPL”). Cheniere Partners plans to construct up to six industrial trains comprised of refrigerant compressor loops used to cool natural gas into LNG (“Trains”), which are in various stages of development, construction and operations. Trains 1 through 4 are operational, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability and potential overdesign, of approximately 4.5 million tonnes per annum (“mtpa”) and an adjusted nominal production capacity of approximately 4.3 to 4.6 mtpa of LNG. Cheniere Partners also owns and operates regasification facilities at the Sabine Pass LNG terminal through its wholly owned subsidiary, Sabine Pass LNG, L.P. (“SPLNG”), that include pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 billion cubic feet equivalent (“Bcfe”), two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 billion cubic feet per day (“Bcf/d”).

SPL has entered into transportation precedent and other agreements to secure firm pipeline capacity with us, which supplement enabling agreements and long-term natural gas supply contracts SPL has executed with third parties to secure natural gas feedstock for the Liquefaction Project.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Basis of Presentation

Our Financial Statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”).

On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto using the full retrospective method. We have elected to adopt the new accounting standard retrospectively for all periods presented.

We have evaluated subsequent events through June 15, 2018, the date the Financial Statements were available to be issued.

Use of Estimates

The preparation of Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the value of property, plant and equipment, asset retirement obligations (“AROs”) and fair value measurements. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value

The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable reported on the Balance Sheets approximates fair value.


S-105


CHENIERE CREOLE TRAIL PIPELINE, L.P.  
NOTES TO FINANCIAL STATEMENTS—CONTINUED


Revenue Recognition

We transport natural gas for shippers under a tariff regulated by the Federal Energy Regulatory Commission (“FERC”).  The tariff specifies the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service on the pipeline system.  Our revenues are derived from agreements for the receipt and delivery of natural gas at points along the pipeline system as specified in each shipper’s individual transportation contract.  See Note 5—Revenues from Contracts with Customers for further discussion of revenues.

Cash and Cash Equivalents

We did not have any cash and cash equivalents as of December 31, 2017 and 2016, since our operations are funded through contributions from Cheniere Partners or contractually restricted as to usage or withdrawal.

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 Balance Sheets. As of both December 31, 2017 and 2016, the balance of restricted cash consisted of funds reserved for the payment of short-term operating expenses.

Accounts Receivable

Accounts receivable is reported net of allowances for doubtful accounts. Impaired receivables are specifically identified and evaluated for expected losses. The expected loss on impaired receivables is primarily determined based on the debtor’s ability to pay and the estimated value of any collateral. We did not recognize any bad debt expense related to accounts receivable during the years ended December 31, 2017, 2016 and 2015.

Inventory

Inventory is recorded at the lower of cost and net realizable value and subsequently charged to expense when issued. Inventory cost is determined using the average cost method. We did not record any expense related to inventory write downs during the years ended December 31, 2017, 2016 and 2015.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in other operating costs and expenses.

Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.  We did not record any impairments related to property, plant and equipment during the years ended December 31, 2017, 2016 and 2015.

Regulated Natural Gas Pipelines

The Creole Trail Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated

S-106


CHENIERE CREOLE TRAIL PIPELINE, L.P.  
NOTES TO FINANCIAL STATEMENTS—CONTINUED


rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in our Balance Sheets as other assets and other liabilities. We periodically evaluate their applicability under GAAP and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write off the associated regulatory assets and liabilities.

Items that may influence our assessment are:
inability to recover cost increases due to rate caps and rate case moratoriums;  
inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;  
excess capacity;  
increased competition and discounting in the markets we serve; and  
impacts of ongoing regulatory initiatives in the natural gas industry.

Concentration of Credit Risk
 
SPL has entered into transportation precedent and other agreements to secure firm pipeline capacity with us, which is our only customer. We are dependent SPL’s creditworthiness and its willingness to perform under its agreements with us.

Asset Retirement Obligations

We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.

We have not recorded an ARO associated with retirement of the Creole Trail Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.

Income Taxes

We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Statements of Operations, is able to be included in the federal income tax return of Cheniere Partners, a publicly traded partnership which indirectly owns us. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.

At December 31, 2017, the tax basis of our assets and liabilities was $114 million less than the reported amounts of our assets and liabilities.

Business Segment

Our pipeline operations represent a single reportable segment. Our chief operating decision maker reviews the financial results of CTPL in total when evaluating financial performance and for purposes of allocating resources. All of our revenues and long-lived assets are attributed to the United States.


S-107


CHENIERE CREOLE TRAIL PIPELINE, L.P.  
NOTES TO FINANCIAL STATEMENTS—CONTINUED


NOTE 3—PROPERTY, PLANT AND EQUIPMENT
 
Property, plant and equipment, net consists of natural gas pipeline costs and fixed assets, as follows (in thousands):
 
 
December 31,
 
 
2017
 
2016
Natural gas pipeline costs
 
 
 
 
Natural gas pipeline
 
$
706,980

 
$
705,847

Natural gas pipeline construction-in-progress
 
86

 
653

Accumulated depreciation
 
(147,206
)
 
(129,045
)
Total natural gas pipeline costs, net
 
559,860

 
577,455

Fixed assets
 
 
 
 
Fixed assets
 
7,290

 
7,138

Accumulated depreciation
 
(6,616
)
 
(5,856
)
Total fixed assets, net
 
674

 
1,282

Property, plant and equipment, net
 
$
560,534

 
$
578,737


Depreciation expense during the years ended December 31, 2017, 2016 and 2015 was $19.0 million, $19.4 million and $17.6 million, respectively.

Our natural gas pipeline cost is depreciated using the straight-line depreciation method with an estimated useful life of 40 years. Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

NOTE 4—ACCRUED LIABILITIES
 
As of December 31, 2017 and 2016, accrued liabilities consisted of the following (in thousands):
 
 
December 31,
 
 
2017
 
2016
Pipeline costs
 
$
179

 
$
64

Other
 
40

 
235

Total accrued liabilities
 
$
219

 
$
299


NOTE 5—REVENUES FROM CONTRACTS WITH CUSTOMERS

SPL has a transportation precedent agreement and a negotiated rate agreement with us to secure firm pipeline transportation capacity for the transportation of adequate natural gas feedstock to the Sabine Pass LNG terminal. These agreements have a primary term through September 2036, with the right for SPL to extend the term of the agreements for up to two consecutive ten-year terms. Thereafter, the agreements continue in effect from year to year until terminated by either party upon written notice of one year or the term of the agreements, whichever is less. SPL has continuous access to its firm transportation capacity during the contract term but has no ability to defer unused capacity to future periods. SPL pays fixed fees of approximately $82 million per year to reserve the right to transport natural gas up to maximum contractually specified levels, regardless of the quantities that SPL actually transports.

Because we are continuously available to provide transportation service on a daily basis with the same pattern of transfer, we have concluded that we provide a single performance obligation to SPL on a continuous basis over time. Because our rights to consideration corresponds directly with the value of the incremental service performed, we have elected to recognize revenue when we have the right to invoice SPL for services performed to date, which results in a substantially straight-line recognition pattern over the term of the contract.


S-108


CHENIERE CREOLE TRAIL PIPELINE, L.P.  
NOTES TO FINANCIAL STATEMENTS—CONTINUED


Transaction Price Allocated to Future Performance Obligations

Because our sales contract with SPL has a long-term duration, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of December 31, 2017:
 
 
Unsatisfied
Transaction Price
(in billions)
 
Weighted Average Recognition Timing (years) (1)
Revenues—affiliate
 
$
1.5

 
9.4

 
    
(1)
The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

We omit from the table above all variable consideration expected to be recognized through our use of the right to invoice election.

We have elected the practical expedient to omit the disclosure of the transaction price allocated to future performance obligations and an explanation of when the entity expects to recognize the amount as revenue as of December 31, 2016.

NOTE 6—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Statements of Operations for the years ended December 31, 2017, 2016 and 2015 (in thousands):
 
Year Ended December 31,
 
2017
 
2016
 
2015
Revenues—affiliate
 
 
Transportation Agreements
$
81,660

 
$
56,349

 
$
1,117

Other agreements
102

 
14

 

Total revenues—affiliate
81,762

 
56,363

 
1,117

 
 
 
 
 
 
Operating and maintenance expense—affiliate
 
 
Services Agreements
9,789

 
10,533

 
5,093

Operational Balancing Agreements
2,299

 
604

 
(82
)
Other agreements

 

 
(15
)
Total operating and maintenance expense—affiliate
12,088

 
11,137

 
4,996

 
 
 
 
 
 
General and administrative expense—affiliate
 
 
Services Agreements
1,336

 
695

 
9,031


We had $3.9 million and $5.8 million of advances to affiliates, $4.0 million and $1.9 million of accrued liabilities—affiliate and zero and $0.4 million of other non-current liabilities—affiliate as of December 31, 2017 and 2016, respectively, under the services agreements described below.

Services Agreements
Operation and Maintenance Agreement

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


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NOTES TO FINANCIAL STATEMENTS—CONTINUED


Cheniere Investments Information Technology Services Agreement

Cheniere Investments has an information technology services agreement with Cheniere, pursuant to which Cheniere Investments’ subsidiaries, including us, receive certain information technology services. On a quarterly basis, the various entities receiving the benefit are invoiced by Cheniere according to the cost allocation percentages set forth in the agreement. In addition, Cheniere is entitled to reimbursement for all costs incurred by Cheniere that are necessary to perform the services under the agreement.

Operational Balancing Agreements
We have Operational Balancing Agreements (“OBAs”) with SPLNG and SPL that provide for the resolution of any operational imbalances (1) during the term of the agreement on an in-kind basis and (2) upon termination of the agreement by cash-out at a rate equivalent to the average of the midpoint prices for Henry Hub, Louisiana pricing published in “Gas Daily’s-Daily Price Survey” for each day of the month following termination. The SPLNG OBA became effective following the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008, and the SPL OBA became effective in April 2015. As of both December 31, 2017 and 2016, we had $0.6 million of other current liabilities—affiliate under the operational balancing agreements.
 
Transportation Agreements
SPL has a transportation precedent agreement and a negotiated rate agreement with us to secure firm pipeline transportation capacity for the transportation of adequate natural gas feedstock to the Sabine Pass LNG terminal. See Note 5—Revenues from Contracts with Customers for information regarding these agreements. As of both December 31, 2017 and 2016, we had $6.8 million of accounts receivable—affiliate under the transportation agreements.

Interconnect Agreement
We had an agreement with SPL whereby SPL constructed certain interconnect facilities between the Creole Trail Pipeline and the Liquefaction Project, with ownership and responsibility for maintenance and operation transferred to us following construction. Upon completion of certain modifications during the third quarter of 2015, SPL conveyed $10.1 million of assets to us under this agreement.

State Tax Sharing Agreement

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

NOTE 7—LEASES

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense for all operating leases of $0.4 million, $0.3 million and $0.3 million, respectively, related primarily to land sites and office space. Our land site leases for the Sabine Pass LNG terminal have initial terms varying up to 30 years with multiple options to renew up to an additional 60 years.


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NOTES TO FINANCIAL STATEMENTS—CONTINUED


Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in thousands): 
Years Ending December 31,
Operating Leases (1)
2018
$
330

2019
330

2020
329

2021
329

2022
393

Thereafter
5,530

Total
$
7,241

 
(1)
Includes certain lease option renewals that are reasonably assured.

NOTE 8—COMMITMENTS AND CONTINGENCIES

Services Agreements

We have certain services agreements with affiliates. See Note 6—Related Party Transactions for information regarding such agreements.

State Tax Sharing Agreement

We have a state tax sharing agreement with Cheniere. See Note 6—Related Party Transactions for additional information regarding this agreement.

Guarantees

Certain subsidiaries of Cheniere Partners, including us, have unconditionally guaranteed the debt obligations of Cheniere Partners. See Note 10—Guarantees for information regarding these guarantees.

Other Commitments
 
In the ordinary course of business, we have entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position and meet the definition of a commitment as of December 31, 2017. Additionally, we have various operating lease commitments, as disclosed in Note 7—Leases.

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. In the opinion of management, as of December 31, 2017, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows.

NOTE 9—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of cash flow information (in thousands):
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
Cash paid during the period for interest, net of amounts capitalized
 
$

 
$
2,429

 
$
12,483

Non-cash contribution from affiliate for conveyance of assets
 

 

 
10,130


The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $0.4 million, $0.2 million and $0.9 million as of December 31, 2017, 2016 and 2015, respectively.


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NOTES TO FINANCIAL STATEMENTS—CONTINUED


NOTE 10—GUARANTEES
 
In February 2016, Cheniere Partners entered into a credit and guaranty agreement aggregating $2.8 billion (the “2016 CQP Credit Facilities”), which included a $450.0 million CTPL tranche term loan that was used to satisfy our obligations under an existing term loan in 2016. The 2016 CQP Credit Facilities will mature on February 25, 2020 and are unconditionally guaranteed by each of Cheniere Partners’ subsidiaries other than SPL (collectively the “CQP Guarantors”), including us. The 2016 CQP Credit Facilities contain customary affirmative and negative covenants, including restrictions of our ability to incur additional indebtedness or liens, engage in asset sales, enter into hedging arrangements (other than permitted hedging agreements) and engage in transactions with affiliates. Cheniere Partners and the CQP Guarantors are also required to establish and maintain certain deposit accounts, which are subject to the control of a collateral agent pursuant to a depositary agreement that was entered into on the closing date of the 2016 CQP Credit Facilities.

In September 2017, Cheniere Partners issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (“the 2025 CQP Senior Notes”). The 2025 CQP Senior Notes are jointly and severally guaranteed by the CQP Guarantors, with Sabine Pass LNG-LP, LLC, a wholly owned subsidiary of Cheniere Partners, subject to certain conditions that will govern the release of its guarantee. Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities. The 2025 CQP Senior Notes are governed by an indenture, which contains customary terms and events of default and certain covenants that, among other things, limit the ability of Cheniere Partners and the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

As of December 31, 2017, there was no liability that was recorded related to these guarantees.

Additionally, Cheniere Partners’ debt obligations are secured by a first priority lien on substantially all of the existing and future tangible and intangible assets and rights of Cheniere Partners and the CQP Guarantors, including us, and the real property of Sabine Pass LNG, L.P. (except for certain excluded properties).


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CHENIERE CREOLE TRAIL PIPELINE, L.P.  
NOTES TO FINANCIAL STATEMENTS—CONTINUED


NOTE 11—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by us as of December 31, 2017:
Standard
 
Description
 
Expected Date of Adoption
 
Effect on our Financial Statements or Other Significant Matters
ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and subsequent amendments thereto
 
This standard provides a single, comprehensive revenue recognition model which replaces and supersedes most existing revenue recognition guidance and requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard requires that the costs to obtain and fulfill contracts with customers should be recognized as assets and amortized to match the pattern of transfer of goods or services to the customer if expected to be recoverable. The standard also requires enhanced disclosures. This guidance may be adopted either retrospectively to each prior reporting period presented subject to allowable practical expedients (“full retrospective approach”) or as a cumulative-effect adjustment as of the date of adoption (“modified retrospective approach”).
 
January 1, 2018
 
We will adopt this standard on January 1, 2018 using the full retrospective approach. The adoption of this standard will not have a material impact upon our Financial Statements but will result in significant additional disclosure regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, including significant judgments and assumptions used in applying the standard. For the purpose of these Financial Statements, we have retrospectively applied this standard and have included the additional disclosures at Note 5—Revenues from Contracts with Customers.
ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto
 
This standard requires a lessee to recognize leases on its balance sheet by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This guidance may be early adopted, and must be adopted using a modified retrospective approach with certain available practical expedients.
 
January 1, 2019
 
We continue to evaluate the effect of this standard on our Financial Statements. Preliminarily, we anticipate a material impact from the requirement to recognize all leases on our Balance Sheets. Because this assessment is preliminary and the accounting for leases is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact of the adoption of this standard upon our results of operations or cash flows. We expect to elect the practical expedient to retain our existing accounting for land easements which were not previously accounted for as leases. We have not yet determined whether we will elect any other practical expedients upon transition.
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 Financial Statements and related disclosures.


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CHENIERE CREOLE TRAIL PIPELINE, L.P.  
NOTES TO FINANCIAL STATEMENTS—CONTINUED



Additionally, the following table provides a brief description of a recent accounting standard that was adopted by us during the reporting period:
Standard
 
Description
 
Date of Adoption
 
Effect on our Financial Statements or Other Significant Matters
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
 
The adoption of this guidance did not have a material impact on our Financial Statements or related disclosures.

NOTE 12—SUBSEQUENT EVENTS

Recent FERC Developments

On March 15, 2018, the FERC issued a policy statement regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (“MLP”) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. The FERC will no longer permit a MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. The FERC also issued a Notice of Proposed Rulemaking proposing a process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in Tax Reform and this policy statement. Furthermore, the FERC issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to accumulated deferred income tax amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are currently evaluating the impact of these developments and continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform.


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