Document

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.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2017

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

For the transition period from to

Cheniere Energy Partners, L.P.

(Exact name of registrant as specified in its charter)



Delaware	001-33366	20-5913059
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

700 Milam Street, Suite 1900 Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 375-5000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer x			Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)			Smaller reporting company ¨
			Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of August 3, 2017, the issuer had 348,614,790 common units and 135,383,831 subordinated units outstanding.

CHENIERE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS



	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations	4
	Consolidated Statement of Partners’ Equity	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36

Item 4.	Controls and Procedures	36

Part II. Other Information
Item 1.	Legal Proceedings	37

Item 1A.	Risk Factors	37

Item 5.	Other Information	37

Item 6.	Exhibits	38

	Signatures	39

DEFINITIONS

As used in this quarterly report, the terms listed below have the following meanings:

Common Industry and Other Terms



Bcf		billion cubic feet
Bcf/d		billion cubic feet per day
Bcf/yr		billion cubic feet per year
Bcfe		billion cubic feet equivalent
DOE		U.S. Department of Energy
EPC		engineering, procurement and construction
FERC		Federal Energy Regulatory Commission
FTA countries		countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP		generally accepted accounting principles in the United States
Henry Hub		the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
LIBOR		London Interbank Offered Rate
LNG		liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu		million British thermal units, an energy unit
mtpa		million tonnes per annum
non-FTA countries		countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC		Securities and Exchange Commission
SPA		LNG sale and purchase agreement
TBtu		trillion British thermal units, an energy unit
Train		an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA		terminal use agreement

Abbreviated Organizational Structure

The following diagram depicts our abbreviated organizational structure as of June 30, 2017, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

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

References to “Blackstone Group” refer to The Blackstone Group, L.P. References to “Blackstone CQP Holdco” refer to Blackstone CQP Holdco LP. References to “Blackstone” refer to Blackstone Group and Blackstone CQP Holdco.


PART I.	FINANCIAL INFORMATION


ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)



	June 30,			December 31,
	2017			2016
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	—		$	—
Restricted cash	865			605
Accounts and other receivables	138			90
Accounts receivable—affiliate	41			99
Advances to affiliate	40			38
Inventory	93			97
Other current assets	39			29
Total current assets	1,216			958

Non-current restricted cash	698			—
Property, plant and equipment, net	14,922			14,158
Debt issuance costs, net	73			121
Non-current derivative assets	43			83
Other non-current assets, net	211			222
Total assets	$	17,163		$	15,542

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	44		$	27
Accrued liabilities	467			418
Current debt	—			224
Due to affiliates	44			99
Deferred revenue	65			73
Deferred revenue—affiliate	1			1
Derivative liabilities	2			14
Total current liabilities	623			856

Long-term debt, net	16,025			14,209
Non-current deferred revenue	3			5
Non-current derivative liabilities	1			2
Other non-current liabilities—affiliate	25			27

Partners’ equity
Common unitholders’ interest (57.1 million units issued and outstanding at June 30, 2017 and December 31, 2016)	(198		)	130
Class B unitholders’ interest (145.3 million units issued and outstanding at June 30, 2017 and December 31, 2016)	1,092			62
Subordinated unitholders’ interest (135.4 million units issued and outstanding at June 30, 2017 and December 31, 2016)	(420		)	240
General partner’s interest (2% interest with 6.9 million units issued and outstanding at June 30, 2017 and December 31, 2016)	12			11
Total partners’ equity	486			443
Total liabilities and partners’ equity	$	17,163		$	15,542

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Revenues
LNG revenues	$	503		$	85		$	995		$	85
LNG revenues—affiliate	422			—			753			—
Regasification revenues	65			65			130			130
Other revenues	2			1			4			1
Other revenues—affiliate	—			—			1			2
Total revenues	992			151			1,883			218

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	577			49			1,090			53
Operating and maintenance expense	82			24			132			42
Operating and maintenance expense—affiliate	21			11			39			22
Development expense	1			—			1			—
General and administrative expense	2			4			5			7
General and administrative expense—affiliate	23			21			45			43
Depreciation and amortization expense	86			29			152			48
Total operating costs and expenses	792			138			1,464			215

Income from operations	200			13			419			3

Other income (expense)
Interest expense, net of capitalized interest	(154		)	(72		)	(284		)	(115		)
Loss on early extinguishment of debt	—			(27		)	(42		)	(28		)
Derivative loss, net	(3		)	(15		)	(3		)	(36		)
Other income	3			1			3			1
Total other expense	(154		)	(113		)	(326		)	(178		)

Net income (loss)	$	46		$	(100	)	$	93		$	(175	)

Basic and diluted net loss per common unit	$	(3.71	)	$	(0.21	)	$	(4.50	)	$	(0.29	)

Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation	57.1			57.1			57.1			57.1

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY

(in millions)

(unaudited)



	Common Unitholders’ Interest				Class B Unitholders’ Interest			Subordinated Unitholder’s Interest				General Partner’s Interest				Total Partners’ Equity
	Units	Amount			Units	Amount		Units	Amount			Units	Amount			Total Partners’ Equity
Balance at December 31, 2016	57.1	$	130		145.3	$	62	135.4	$	240		6.9	$	11		$	443
Net income	—	27			—	—		—	64			—	2			93
Distributions	—	(49		)	—	—		—	—			—	(1		)	(50		)
Amortization of beneficial conversion feature of Class B units	—	(306		)	—	1,030		—	(724		)	—	—			—
Balance at June 30, 2017	57.1	$	(198	)	145.3	$	1,092	135.4	$	(420	)	6.9	$	12		$	486

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)



	Six Months Ended June 30,
	2017			2016
Cash flows from operating activities
Net income (loss)	$	93		$	(175	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization expense	152			48
Amortization of debt issuance costs, deferred commitment fees, premium and discount	19			11
Loss on early extinguishment of debt	42			28
Total losses on derivatives, net	43			48
Net cash used for settlement of derivative instruments	(16		)	(4		)
Changes in operating assets and liabilities:
Accounts and other receivables	(47		)	(71		)
Accounts receivable—affiliate	59			1
Advances to affiliate	(19		)	1
Inventory	12			(17		)
Accounts payable and accrued liabilities	68			47
Due to affiliates	(57		)	(3		)
Deferred revenue	(10		)	(2		)
Other, net	(13		)	(9		)
Other, net—affiliate	(2		)	(1		)
Net cash provided by (used in) operating activities	324			(98		)

Cash flows from investing activities
Property, plant and equipment, net	(898		)	(1,224		)
Other	—			(39		)
Net cash used in investing activities	(898		)	(1,263		)

Cash flows from financing activities
Proceeds from issuances of debt	2,314			3,365
Repayments of debt	(703		)	(1,842		)
Debt issuance and deferred financing costs	(29		)	(70		)
Distributions to owners	(50		)	(50		)
Net cash provided by financing activities	1,532			1,403

Net increase in cash, cash equivalents and restricted cash	958			42
Cash, cash equivalents and restricted cash—beginning of period	605			434
Cash, cash equivalents and restricted cash—end of period	$	1,563		$	476

Balances per Consolidated Balance Sheet:



	June 30, 2017
Cash and cash equivalents	$	—
Restricted cash	865
Non-current restricted cash	698
Total cash, cash equivalents and restricted cash	$	1,563

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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 3 are operational, Train 4 is undergoing commissioning, Train 5 is under construction and Train 6 is being commercialized and has all necessary regulatory approvals in place. In the second quarter of 2016, we started production at the Liquefaction Project and began recognizing LNG revenues, which include fees that are received pursuant to our long-term SPAs and other related revenues.

We also own and operate regasification facilities at the Sabine Pass LNG terminal through SPLNG and 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. Regasification revenues include LNG regasification capacity reservation fees that are received from our two long-term TUA customers. 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.

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of Cheniere Partners have been prepared in accordance with GAAP for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2016. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included. Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.

Results of operations for the three and six months ended June 30, 2017 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2017.

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

NOTE 2—UNITHOLDERS’ EQUITY

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

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

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights (“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. The higher percentages range from 15% to 50%.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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. The Class B units are subject to conversion, mandatorily or at the option of the Class B unitholders under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. The Class B units are not entitled to cash distributions except in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets. On a quarterly basis beginning on the date of the initial purchase date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere Holdings and Blackstone CQP Holdco was 2.04 and 1.99, respectively, as of June 30, 2017. See Note 16—Subsequent Events for information regarding the subsequent conversion of the Class B units into common units.

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 June 30, 2017 and December 31, 2016, restricted cash consisted of the following (in millions):



	June 30,		December 31,
	2017		2016
Current restricted cash
Liquefaction Project	$	579	$	358
CQP and cash held by guarantor subsidiaries	286		247
Total current restricted cash	$	865	$	605

Non-current restricted cash
Liquefaction Project	$	698	$	—

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of June 30, 2017 and December 31, 2016, accounts and other receivables consisted of the following (in millions):



	June 30,		December 31,
	2017		2016
SPL trade receivable	$	123	$	88
Other accounts receivable	15		2
Total accounts and other receivables	$	138	$	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 June 30, 2017 and December 31, 2016, inventory consisted of the following (in millions):



	June 30,		December 31,
	2017		2016
Natural gas	$	17	$	15
LNG	29		45
Materials and other	47		37
Total inventory	$	93	$	97

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net consists of LNG terminal costs and fixed assets, as follows (in millions):



	June 30,			December 31,
	2017			2016
LNG terminal costs
LNG terminal	$	10,442		$	7,976
LNG terminal construction-in-process	5,173			6,728
Accumulated depreciation	(699		)	(553		)
Total LNG terminal costs, net	14,916			14,151
Fixed assets
Fixed assets	21			20
Accumulated depreciation	(15		)	(13		)
Total fixed assets, net	6			7
Property, plant and equipment, net	$	14,922		$	14,158

Depreciation expense was $84 million and $26 million in the three months ended June 30, 2017 and 2016, respectively, and $148 million and $44 million in the six months ended June 30, 2017 and 2016, respectively.

We realized offsets to LNG terminal costs of $39 million and $128 million in the three months ended June 30, 2017 and 2016, respectively, and $163 million and $142 million in the six months ended June 30, 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.

NOTE 7—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 (collectively, the “Liquefaction Supply Derivatives”).

None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process.

The following table (in millions) shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of June 30, 2017 and December 31, 2016, which are classified as other current assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets.



	Fair Value Measurements as of
	June 30, 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	—		13		—		13		—			13			—		13
Liquefaction Supply Derivatives asset (liability)	2		—		40		42		(4		)	(2		)	79		73

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

There have been no changes to our evaluation of and accounting for our derivative positions during the six months ended June 30, 2017. See Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016 for additional information.

We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.

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

The fair value of substantially all of our Physical Liquefaction Supply Derivatives is developed through the use of internal models which are impacted by inputs that are unobservable in the marketplace. As a result, the fair value of our Physical Liquefaction Supply Derivatives is designated as Level 3 within the valuation hierarchy. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data. Internal fair value models include conditions precedent to the respective long-term natural gas supply contracts. As of June 30, 2017 and December 31, 2016, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure is under development to accommodate marketable physical gas flow.

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of June 30, 2017:



	Net Fair Value Asset (in millions)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$40	Income Approach	Basis Spread	$(0.338) - $0.080

The following table (in millions) shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the six months ended June 30, 2017 and 2016:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Balance, beginning of period	$	41		$	30		$	79		$	32
Realized and mark-to-market losses:
Included in cost of sales (1)	(1		)	(8		)	(40		)	(10		)
Purchases and settlements:
Purchases	2			—			5			—
Settlements (1)	(2		)	—			(4		)	—
Balance, end of period	$	40		$	22		$	40		$	22
Change in unrealized gains relating to instruments still held at end of period	$	(1	)	$	(8	)	$	(40	)	$	(9	)


(1)	Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the six months ended June 30, 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. 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.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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”). 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 10—Debt.

During the six months ended June 30, 2017, there were no changes to the terms of our interest rate swaps (“CQP Interest Rate Derivatives”) entered into to hedge a portion of the variable interest payments on the credit facilities we entered into in February 2016 (the “2016 CQP Credit Facilities”). See Note 8—Derivative Instruments of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016 for additional information.

As of June 30, 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

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



	June 30, 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	$	—	$	2	$	2	$	—		$	—		$	—
Non-current derivative assets	—		11		11		—			16			16
Total derivative assets	—		13		13		—			16			16

Derivative liabilities	—		—		—		(4		)	(3		)	(7		)
Non-current derivative liabilities	—		—		—		(2		)	—			(2		)
Total derivative liabilities	—		—		—		(6		)	(3		)	(9		)

Derivative asset (liability), net	$	—	$	13	$	13	$	(6	)	$	13		$	7

The following table (in millions) 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 three and six months ended June 30, 2017 and 2016:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
SPL Interest Rate Derivatives loss	$	—		$	(5	)	$	(2	)	$	(16	)
CQP Interest Rate Derivatives loss	(3		)	(10		)	(1		)	(20		)

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Liquefaction Supply Derivatives

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



		Fair Value Measurements as of (1)
	Balance Sheet Location	June 30, 2017			December 31, 2016
Liquefaction Supply Derivatives	Other current assets	$	13		$	13
Liquefaction Supply Derivatives	Non-current derivative assets	32			67
Liquefaction Supply Derivatives	Derivative liabilities	(2		)	(7		)
Liquefaction Supply Derivatives	Non-current derivative liabilities	(1		)	—


(1)	Does not include collateral of $6 million deposited for such contracts, which is included in other current assets in our Consolidated Balance Sheet as of December 31, 2016.

SPL had secured up to approximately 2,220 TBtu and 1,994 TBtu of natural gas feedstock through natural gas supply contracts as of June 30, 2017 and December 31, 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,424 TBtu and 1,117 TBtu as of June 30, 2017 and December 31, 2016, respectively.

The following table (in millions) shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations during the three and six months ended June 30, 2017 and 2016:



		Three Months Ended June 30,				Six Months Ended June 30,
	Statement of Operations Location (1)	2017		2016		2017		2016
Liquefaction Supply Derivatives loss (2)	Cost of sales	$	1	$	8	$	40	$	12


(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.

Balance Sheet Presentation

Our derivative instruments are presented on a net basis on our Consolidated Balance Sheets as described above. The following table (in millions) shows the fair value of our derivatives outstanding on a gross and net basis:



	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
As of June 30, 2017
CQP Interest Rate Derivatives	$	13		$	—		$	13
Liquefaction Supply Derivatives	49			(4		)	45
Liquefaction Supply Derivatives	(4		)	1			(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		)

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—OTHER NON-CURRENT ASSETS

As of June 30, 2017 and December 31, 2016, other non-current assets consisted of the following (in millions):



	June 30,		December 31,
	2017		2016
Advances made under EPC and non-EPC contracts	$	19	$	23
Advances made to municipalities for water system enhancements	95		95
Advances and other asset conveyances to third parties to support LNG terminals	30		31
Tax-related payments and receivables	33		28
Information technology service assets	25		27
Other	9		18
Total other non-current assets, net	$	211	$	222

NOTE 9—ACCRUED LIABILITIES

As of June 30, 2017 and December 31, 2016, accrued liabilities consisted of the following (in millions):



	June 30,		December 31,
	2017		2016
Interest costs and related debt fees	$	190	$	205
Sabine Pass LNG terminal and related pipeline costs	272		211
Other accrued liabilities	5		2
Total accrued liabilities	$	467	$	418

NOTE 10—DEBT

As of June 30, 2017 and December 31, 2016, our debt consisted of the following (in millions):



	June 30,			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
2016 CQP Credit Facilities	2,560			2,560
Unamortized debt issuance costs	(195		)	(178		)
Total long-term debt, net	16,025			14,209

Current debt:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	—			224

Total debt, net	$	16,025		$	14,433

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

2017 Debt Issuances and Redemptions

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 repay 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 six months ended June 30, 2017.

The 2037 SPL Senior Notes and the 2028 SPL Senior Notes accrue interest at fixed rates of 5.00% and 4.200%, respectively, and interest is payable semi-annually in arrears. The terms of the 2037 SPL Senior Notes are governed by an indenture which contains 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. The 2028 SPL Senior Notes are governed by the same common indenture as the senior notes of SPL other than the 2037 SPL Senior Notes, which also contains customary terms and events of default, covenants and redemption terms.

At any time prior to six months before the respective dates of maturity of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, SPL may redeem all or part of such notes at a redemption price equal to the “optional redemption” price for the 2037 SPL Senior Notes or the “make-whole” price for the 2028 SPL Senior Notes, as set forth in the respective indentures governing the notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within six months of the respective maturity dates for the 2037 SPL Senior Notes and the 2028 SPL Senior Notes, redeem all or part of such notes at a redemption price equal to 100% of the principal amount of such notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

Credit Facilities

Below is a summary (in millions) of our credit facilities outstanding as of June 30, 2017:



	SPL Working Capital Facility		2016 CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Outstanding balance	—		2,560
Letters of credit issued	366		50
Available commitment	$	834	$	190

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 principals due quarterly commencing on February 19, 2019


(1)	There is a 0.50% step-up for both LIBOR and base rate loans beginning on February 25, 2019.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Interest Expense

Total interest expense consisted of the following (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Total interest cost	$	224		$	205		$	435		$	397
Capitalized interest	(70		)	(133		)	(151		)	(282		)
Total interest expense, net	$	154		$	72		$	284		$	115

Fair Value Disclosures

The following table (in millions) shows the carrying amount and estimated fair value of our debt:



	June 30, 2017				December 31, 2016
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	12,860	$	14,040	$	11,513	$	12,309
2037 SPL Senior Notes (2)	800		860		—		—
Credit facilities (3)	2,560		2,560		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 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 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.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—RELATED PARTY TRANSACTIONS

Below is a summary (in millions) of our related party transactions as reported on our Consolidated Statements of Operations for the three and six months ended June 30, 2017 and 2016:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	422	$	—	$	753	$	—

Other revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	—		—		—		1
Terminal Marine Services Agreement	—		—		1		1
Total other revenues—affiliate	—		—		1		2

Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	—		—		—		1
Services Agreements	21		11		39		21
Total operating and maintenance expense—affiliate	21		11		39		22

General and administrative expense—affiliate
Services Agreements	23		21		45		43

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 SPL delivers its first commercial cargo at the Liquefaction Project.

In connection with this TUA, SPL is required to pay for a portion of the cost (primarily LNG inventory) to maintain the cryogenic readiness of the regasification facilities at the Sabine Pass LNG terminal, 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 three and six months ended June 30, 2017 and 2016, respectively, related to the Amended and Restated VCRA.

Cheniere Marketing SPA

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Marketing Master SPA

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

Pre-commercial LNG Marketing Agreement

SPL has entered into 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 June 30, 2017 and December 31, 2016, we had $40 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.

Cheniere Partners Services Agreement

We have entered into a services agreement with Cheniere Terminals, a wholly owned subsidiary of Cheniere, pursuant to which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $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 entered into 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 entered into a long-term operation and maintenance agreement (the “SPLNG O&M Agreement”) with Cheniere Investments pursuant to which SPLNG receives all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. SPLNG 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 entered into a long-term management services agreement (the “SPLNG MSA”) with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 entered into an operation and maintenance agreement (the “SPL O&M Agreement”) with Cheniere Investments pursuant to which SPL receives all of the necessary services required to construct, operate and maintain the Liquefaction Project. Before 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 entered into a management services agreement (the “SPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the construction and operation of the Liquefaction Project, excluding those matters provided for under the SPL O&M Agreement. The services include, among other services, exercising the day-to-day management of SPL’s affairs and business, managing SPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of SPL’s business and operations, entering into financial derivatives on 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 entered into an amended long-term operation and maintenance agreement (the “CTPL O&M Agreement”) with Cheniere Investments pursuant to which CTPL receives all necessary services required to operate and maintain the Creole Trail Pipeline. CTPL is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses. Cheniere Investments 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.

CTPL MSA

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

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-

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 June 30, 2017 and December 31, 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 entered into an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal. SPLNG did not record any revenues associated with this agreement during the three and six months ended June 30, 2017 and 2016.

State Tax Sharing Agreements

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

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 12—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 July 21, 2017, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid on August 11, 2017 to unitholders of record as of August 1, 2017 for the period from April 1, 2017 to June 30, 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. Historical income (loss) attributable to a company that was purchased from an entity under common control is allocated to the predecessor owner in accordance with the terms of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

The Class B units were issued at a discount to the market price of the common units into which they are convertible. This discount, totaling $2,130 million, represents a beneficial conversion feature and is reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at issuance on our Consolidated Statement of Partners’ Equity. The beneficial conversion feature is considered a dividend that will be distributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortize the beneficial conversion feature through the mandatory conversion date of August 2017 for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units. We are amortizing using the effective yield method with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units, respectively. The impact of the beneficial conversion feature is also included in earnings per unit for the three and six months ended June 30, 2017 and 2016. See Note 16—Subsequent Events for information regarding the subsequent conversion of the Class B units into common units.

Based on the capital structure as of June 30, 2017, the anticipated impact to the capital accounts in connection with the amortization of the beneficial conversion feature is as follows in 2017 (in millions):



Common Units	Class B Units	Subordinated Units
$(594)	$2,004	$(1,410)

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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). We did not allocate earnings or losses for IDRs for the purpose of the two-class method earnings per unit calculation for any of the periods presented. The following table (in millions, except per unit data) provides a reconciliation of net income (loss) and the allocation of net income (loss) to the common units, the subordinated units and the general partner units for purposes of computing net loss per unit.



				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner Units
Three Months Ended June 30, 2017
Net income	$	46
Declared distributions	25			25			—		—			—
Amortization of beneficial conversion feature of Class B units	—			(237		)	796		(559		)	—
Assumed allocation of undistributed net income	$	21		—			—		21			—
Assumed allocation of net income (loss)				$	(212	)	$	796	$	(538	)	$	—

Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(3.71	)			$	(3.97	)

Three Months Ended June 30, 2016
Net loss	$	(100	)
Declared distributions	25			25			—		—			—
Assumed allocation of undistributed net loss	$	(125	)	(37		)	—		(86		)	(2		)
Assumed allocation of net loss				$	(12	)	$	—	$	(86	)	$	(2	)

Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(0.21	)			$	(0.64	)

Six Months Ended June 30, 2017
Net income	$	93
Declared distributions	50			49			—		—			1
Amortization of beneficial conversion feature of Class B units	—			(306		)	1,030		(724		)	—
Assumed allocation of undistributed net income	$	43		—			—		43			—
Assumed allocation of net income (loss)				$	(257	)	$	1,030	$	(681	)	$	1

Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(4.50	)			$	(5.03	)

Six Months Ended June 30, 2016
Net loss	$	(175	)
Declared distributions	50			49			—		—			1
Assumed allocation of undistributed net loss	$	(225	)	(66		)	—		(155		)	(4		)
Assumed allocation of net loss				$	(17	)	$	—	$	(155	)	$	(3	)

Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(0.29	)			$	(1.14	)

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 13—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 Revenues				Percentage of Accounts Receivable
	Three Months Ended June 30,		Six Months Ended June 30,		June 30,	December 31,
	2017	2016	2017	2016	2017	2016
Customer A	46%	54%	50%	38%	38%	47%
Customer B	27%	—%	28%	—%	35%	50%
Customer C	13%	—%	*	—%	17%	—%

* Less than 10%

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION

The following table (in millions) provides supplemental disclosure of cash flow information:



	Six Months Ended June 30,
	2017		2016
Cash paid during the period for interest, net of amounts capitalized	$	273	$	100

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $266 million and $315 million as of June 30, 2017 and 2016, respectively.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 15—RECENT ACCOUNTING STANDARDS

The following table provides a brief description of recent accounting standards that had not been adopted by the Partnership as of June 30, 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 continue to evaluate the effect of this standard on our Consolidated Financial Statements. Preliminarily, we plan to adopt this standard using the full retrospective approach and we do not currently anticipate that the adoption will have a material impact upon our revenues. The Financial Accounting Standards Board has issued and may issue in the future amendments and interpretive guidance which may cause our evaluation to change. Furthermore, we routinely enter into new contracts and we cannot predict with certainty whether the accounting for any future contract under the new standard would result in a significant change from existing guidance. Because this assessment is preliminary and the accounting for revenue recognition is subject to significant judgment, this conclusion could change as we finalize our assessment. We have not yet determined the impact that recognizing fulfillment costs as assets will have on our Consolidated Financial Statements.
ASU 2016-02, Leases (Topic 842)	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, whether we will elect to early adopt this standard or which, if any, practical expedients we will elect 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.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Additionally, the following table provides a brief description of a recent accounting standard that was adopted by the Partnership during the reporting period:

NOTE 16—SUBSEQUENT EVENTS

As of June 30, 2017, Cheniere Holdings and Blackstone CQP Holdco owned 45.3 million and 100.0 million, respectively, of our Class B units. On August 2, 2017, the Class B units held by Cheniere Holdings and 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 is based on approximately 92.5 million converted common units, 135.4 million subordinated units and 12.0 million common units, and Blackstone CQP Holdco’s ownership is based on approximately 199.0 million converted common units, but excludes any common units that may be deemed to be beneficially owned by Blackstone Group, an affiliate of Blackstone CQP Holdco.


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

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements.” All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:


•	statements regarding our ability to pay distributions to our unitholders;


•	statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL;


•	statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, by certain dates, or at all;

•

statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;


•	statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;


•	statements relating to the construction of our Trains, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any such EPC or other contractor, and anticipated costs related thereto;


•	statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;


•	statements regarding counterparties to our commercial contracts, construction contracts and other contracts;


•	statements regarding our planned development and construction of additional Trains, including the financing of such Trains;


•	statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;


•	statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;


•	statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions; and


•	any other statements that relate to non-historical or future information.

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2016. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis includes the following subjects:


•	Overview of Business


•	Overview of Significant Events


•	Liquidity and Capital Resources


•	Results of Operations


•	Off-Balance Sheet Arrangements


•	Summary of Critical Accounting Estimates


•	Recent Accounting Standards

Overview of Business

We are a publicly traded Delaware limited partnership formed by Cheniere. Our vision is to be recognized as the premier global LNG company and provide a reliable, competitive and integrated source of LNG to our customers while creating a safe, productive and rewarding work environment for our employees. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to economically justify the use of LNG. Through our wholly owned subsidiary, 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 3 are operational, Train 4 is undergoing commissioning, 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 of LNG. Through our wholly owned subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two marine berths that can accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We also own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines through our wholly owned subsidiary, CTPL.

Overview of Significant Events

Our significant accomplishments since January 1, 2017 and through the filing date of this Form 10-Q include the following:

Strategic


•	Year to date, LNG from the Liquefaction Project has been delivered to 10 new countries. As of July 2017, LNG from the Liquefaction Project had reached 24 of the 40 LNG importing countries around the world.

Operational


•	SPL commenced production and shipment of LNG commissioning cargoes from Train 3 of the Liquefaction Project in January 2017 and achieved substantial completion and commenced operating activities in March 2017.


•	Commissioning activities for Train 4 of the Liquefaction Project began in March 2017, and first LNG was achieved in July 2017.


•	In April 2017, we reached the milestone of 100 cumulative LNG cargoes exported from the Liquefaction Project. As of July 2017, more than 160 cumulative LNG cargoes had been exported from the Liquefaction Project.


•	In June 2017, the date of first commercial delivery was reached under the 20-year SPA with Korea Gas Corporation relating to Train 3 of the Liquefaction Project.


•	In August 2017, the date of first commercial delivery was reached under the respective 20-year SPAs with Gas Natural Fenosa LNG GOM, Limited and BG Gulf Coast LNG, LLC relating to Train 2 of the Liquefaction Project.

Financial

•

In February and March 2017, SPL issued aggregate principal amounts of $800 million of 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) and $1.35 billion, before discount, of 4.200% Senior Secured Notes due 2028 (the “2028 SPL Senior Notes”), respectively. Net proceeds of the offerings of the 2037 SPL Senior Notes and 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 repay the outstanding borrowings under the credit facilities SPL entered into in June 2015 (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.


•	Fitch Ratings assigned SPL’s senior secured debt an investment grade rating of BBB- in January 2017 and an investment-grade issuer default rating of BBB- in June 2017.


•	In May 2017, Moody’s Investors Service upgraded SPL’s senior secured debt rating from Ba1 to Baa3, an investment-grade rating.

Liquidity and Capital Resources

The following table (in millions) provides a summary of our liquidity position at June 30, 2017 and December 31, 2016:



	June 30,		December 31,
	2017		2016
Cash and cash equivalents	$	—	$	—
Restricted cash designated for the following purposes:
Liquefaction Project	1,277		358
CQP and cash held by guarantor subsidiaries	286		247
Available commitments under the following credit facilities:
2015 SPL Credit Facilities	—		1,642
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	834		653
$2.8 billion 2016 CQP Credit Facilities (“2016 CQP Credit Facilities”)	190		195

For additional information regarding our debt agreements, see Note 10—Debt of our Notes to Consolidated Financial Statements.

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 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. We had $2.6 billion of outstanding borrowings under the 2016 CQP Credit Facilities as of both June 30, 2017 and December 31, 2016, and we had $190 million and $195 million of available commitments and $50 million and $45 million aggregate amount of issued letters of credit as of June 30, 2017 and December 31, 2016, respectively.

The 2016 CQP Credit Facilities mature on February 25, 2020, and the outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. The 2016 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants and limit our ability to make restricted payments, including distributions, to once per fiscal quarter as long as certain conditions are satisfied. Under the terms of the 2016 CQP Credit Facilities, 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.

See Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016 for additional information regarding the 2016 CQP Credit Facilities.

Sabine Pass LNG Terminal

Liquefaction Facilities

We are developing, constructing and operating the Liquefaction Project at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We have received authorization from the FERC to site, construct and operate Trains 1 through 6. The following table summarizes the overall project status of the Liquefaction Project as of June 30, 2017:



	Trains 1 & 2		Trains 3 & 4		Train 5
Overall project completion percentage	100%		99.0%		69.0%
Completion percentage of:
Engineering	100%		100%		99.9%
Procurement	100%		100%		96.6%
Subcontract work	100%		93.8%		48.5%
Construction	100%		99.0%		30.5%
Date of expected substantial completion	Train 1	Operational	Train 3	Operational	Train 5	2H 2019
	Train 2	Operational	Train 4	2H 2017

We achieved substantial completion of Trains 1, 2 and 3 of the Liquefaction Project and commenced operating activities in May 2016, September 2016 and March 2017, respectively, and started the commissioning of Train 4 of the Liquefaction Project in March 2017.

The following orders have been issued by the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal:


•	Trains 1 through 4—FTA countries for a 30-year term, which commenced on May 15, 2016, and non-FTA countries for a 20-year term, which commenced on June 3, 2016, in an amount up to a combined total of the equivalent of 16 mtpa (approximately 803 Bcf/yr of natural gas).


•	Trains 1 through 4—FTA countries for a 25-year term and non-FTA countries for a 20-year term, in an amount up to a combined total of the equivalent of approximately 203 Bcf/yr of natural gas (approximately 4 mtpa).


•	Trains 5 and 6—FTA countries and non-FTA countries for a 20-year term, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).

In each case, the terms of these authorizations begin on the earlier of the date of first export thereunder or the date specified in the particular order, which ranges from five to 10 years from the date the order was issued. In addition, we received an order providing for a three-year makeup period with respect to each of the non-FTA orders for LNG volumes we were unable to export during any portion of the initial 20-year export period of such order.

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

A party to the proceedings requested rehearings of the orders above related to the export of 803 Bcf/yr, 203 Bcf/yr and 503.3 Bcf/yr to non-FTA countries. The DOE issued orders denying rehearing of the orders. The same party petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review (1) the 203 Bcf/yr order to non-FTA countries and the order denying the request for rehearing of the same and (2) the 503.3 Bcf/yr order to non-FTA countries and the order denying the request for rehearing of the same. Both appeals are pending.

Customers

SPL has entered into six fixed price, 20-year SPAs with extension rights with third parties to make available an aggregate amount of LNG that equates to approximately 19.75 mtpa of LNG, which is approximately 88% of the expected aggregate nominal production capacity of Trains 1 through 5. The obligation to make LNG available under the SPAs commences from the date of first commercial delivery for Trains 1 through 5, as specified in each SPA. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee equal to 115% of Henry Hub per MMBtu of LNG. In certain circumstances, the customers may elect to cancel or suspend deliveries of LNG cargoes, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA commences upon the start of operations of a specified Train.

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

In addition, Cheniere Marketing has entered into an SPA with SPL to purchase, at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers.

Natural Gas Transportation, Storage and Supply

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing volatility in natural gas needs for the Liquefaction Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of June 30, 2017, SPL has secured up to approximately 2,220 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts.

Construction

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

The total contract prices of the EPC contract for Trains 1 and 2, the EPC contract for Trains 3 and 4 and the EPC contract for Train 5 of the Liquefaction Project are approximately $4.1 billion, $3.9 billion and $3.1 billion, respectively, reflecting amounts incurred under change orders through June 30, 2017. Total expected capital costs for Trains 1 through 5 are estimated to be between $12.5 billion and $13.5 billion before financing costs and between $17.5 billion and $18.5 billion after financing costs, including, in each case, estimated owner’s costs and contingencies.

Final Investment Decision on Train 6

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

Regasification Facilities

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

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, continuing until at least 20 years after SPL delivers its first commercial cargo at the Liquefaction Project. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 3, SPL commenced gaining 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. During both the three and six months ended June 30, 2017, SPL recorded $8 million as operating and maintenance expense under this partial TUA assignment agreement.

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

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to Trains 1 through 5 of the Liquefaction Project will be financed through borrowings and cash flows under the SPAs. We believe that with the net proceeds of borrowings, available commitments under the SPL Working Capital Facility and cash flows from operations, we will have adequate financial resources available to complete Trains 1 through 5 of the Liquefaction Project and to meet our currently anticipated capital, operating and debt service requirements. SPL began generating cash flows from operations from the Liquefaction Project in May 2016, when Train 1 achieved substantial completion and initiated operating activities. Trains 2 and 3 subsequently achieved substantial completion in September 2016 and March 2017, respectively. Additionally, we realized offsets to LNG terminal costs of $39 million and $128 million in the three months ended June 30, 2017 and 2016, respectively, and $163 million and $142 million in the six months ended June 30, 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, during the testing phase for the construction of those Trains of the Liquefaction Project. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.

The following table (in millions) provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Uses of Cash), at June 30, 2017 and December 31, 2016:



	June 30,		December 31,
	2017		2016
Senior notes (1)	$	13,650	$	11,500
Credit facilities outstanding balance (2)	2,560		3,097
Letters of credit issued (3)	366		324
Available commitments under credit facilities (3)	834		2,295
Total capital resources from borrowings and available commitments	$	17,410	$	17,216

(1)

Includes SPL’s 5.625% Senior Secured Notes due 2021, 6.25% Senior Secured Notes due 2022, 5.625% Senior Secured Notes due 2023, 5.75% Senior Secured Notes due 2024, 5.625% Senior Secured Notes due 2025, 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”), 5.00% Senior Secured Notes due 2027 (the “2027 SPL Senior Notes”), 2028 SPL Senior Notes and 2037 SPL Senior Notes (collectively, the “SPL Senior Notes”).


(2)	Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and CTPL and SPLNG tranche term loans outstanding under the 2016 CQP Credit Facilities.


(3)	Includes 2015 SPL Credit Facilities and SPL Working Capital Facility. Does not include the letters of credit issued or available commitments under the 2016 CQP Credit Facilities, which are not specifically for the Liquefaction Project.

For additional information regarding our debt agreements related to the Sabine Pass LNG Terminal, see Note 10—Debt of our Notes to Consolidated Financial Statements in this quarterly report and Note 11—Debt of our Notes to Consolidated Financial Statements in our annual report on Form 10-K for the year ended December 31, 2016.

Senior Secured Notes

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.

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.

Both the indenture governing the 2037 SPL Senior Notes (the “2037 SPL Senior Notes Indenture”) and the common indenture governing the remainder of the SPL Senior Notes (the “SPL Indenture”) include restrictive covenants. SPL may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of SPL, including the SPL Senior Notes and the SPL Working Capital Facility. Under the 2037 SPL Senior Notes Indenture and the SPL Indenture, SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied.

2015 SPL Credit Facilities

In June 2015, SPL entered into the 2015 SPL Credit Facilities with commitments aggregating $4.6 billion to fund a portion of the costs of developing, constructing and placing into operation Trains 1 through 5 of the Liquefaction Project. In February 2017, SPL issued the 2037 SPL Senior Notes and a portion of the net proceeds of the issuance was used to repay the then outstanding borrowings of $369 million under the 2015 SPL Credit Facilities. In March 2017, SPL issued the 2028 SPL Senior Notes and SPL terminated the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities.

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. As of June 30, 2017 and December 31, 2016, SPL had $834 million and $653 million of available commitments, $366 million and $324 million aggregate amount of issued letters of credit and zero and $224 million of loans outstanding under the SPL Working Capital Facility, respectively.

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. Loans deemed made in connection with a draw upon a letter of credit 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.

Sources and Uses of Cash

The following table (in millions) summarizes the sources and uses of our cash, cash equivalents and restricted cash for the six months ended June 30, 2017 and 2016. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.



	Six Months Ended June 30,
	2017			2016
Operating cash flows	$	324		$	(98	)
Investing cash flows	(898		)	(1,263		)
Financing cash flows	1,532			1,403

Net increase in cash, cash equivalents and restricted cash	958			42
Cash, cash equivalents and restricted cash—beginning of period	605			434
Cash, cash equivalents and restricted cash—end of period	$	1,563		$	476

Operating Cash Flows

Our operating cash flows increased from outflows of $98 million during the six months ended June 30, 2016 to inflows of $324 million during the six months ended June 30, 2017. The $422 million increase in operating cash inflows in 2017 compared to 2016 was primarily related to increased cash receipts from the sale of LNG cargoes, partially offset by increased operating costs and expenses as a result of the of additional Trains that were operating between the periods. During the six months ended June 30, 2017, Trains 1 and 2 were operating for six months and Train 3 was operating for three months, whereas only Train 1 was operating for one month during the comparable period in 2016.

Investing Cash Flows

Investing cash outflows during the six months ended June 30, 2017 and 2016 were $898 million and $1.3 billion, respectively, and were primarily used to fund the construction costs for Trains 1 through 5 of the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion. Additionally, during the six months ended June 30, 2016, we used $39 million primarily for payments to a municipal water district for water system enhancements that will increase potable water supply to the Sabine Pass LNG terminal and payments made pursuant to the information technology services agreement for capital assets purchased on our behalf.

Financing Cash Flows

Financing cash inflows during the six months ended June 30, 2017 were $1.5 billion, primarily as a result of:


•	issuances of aggregate principal amounts of $800 million of the 2037 SPL Senior Notes and $1.35 billion of the 2028 SPL Senior Notes;


•	$55 million of borrowings and a $369 million repayment made under the 2015 SPL Credit Facilities;


•	$110 million of borrowings and $334 million of repayments made under the SPL Working Capital Facility;


•	$29 million of debt issuance costs related to up-front fees paid upon the closing of these transactions; and


•	$50 million of distributions to unitholders.

Financing cash inflows during the six months ended June 30, 2016 were $1.4 billion, primarily as a result of:


•	$450 million of borrowings under the 2016 CQP Credit Facilities, which was entered into in February 2016 to prepay the $400 million CTPL Term Loan;


•	$1.3 billion of borrowings under the 2015 SPL Credit Facilities;


•	issuance of an aggregate principal amount of $1.5 billion of the 2026 SPL Senior Notes in June 2016, which was used to prepay $1.3 billion of the outstanding borrowings under the 2015 SPL Credit Facilities;


•	$140 million of borrowings and $155 million of repayments made under the SPL Working Capital Facility;


•	$70 million of debt issuance costs related to up-front fees paid upon the closing of these transactions; and


•	$50 million of distributions to unitholders.

Cash Distributions to Unitholders

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). 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 accumulated operating surplus. On a quarterly basis, we declare and pay a $0.425 distribution per common unit and the related distribution to our general partner of $24 million and $0.5 million, respectively.

The subordinated units will receive distributions only to the extent we have available cash above the initial quarterly distributions requirement for our common unitholders and general partner along with certain reserves. The ending of the subordination period and conversion of the subordinated units into common units will depend upon future business development.

In 2012 and 2013, we issued a new class of equity interests representing limited partner interests in us (“Class B units”), in connection with the development of the Liquefaction Project. The Class B units are not entitled to cash distributions, except in the event of our liquidation or a merger, consolidation or other combination of us with another person or the sale of all or substantially all of our assets. The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basis beginning on the initial purchase date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The accreted conversion ratio of the Class B units owned by Cheniere and Blackstone CQP Holdco was 2.04 and 1.99, respectively, as of June 30, 2017. On August 2, 2017, the Class B units mandatorily converted into common units in accordance with the terms of the partnership agreement. See Note 16—Subsequent Events of our Notes to Consolidated Financial Statements for information regarding the subsequent conversion of the Class B units into common units.

Results of Operations

Our consolidated net income was $46 million, or $3.71 loss per common unit (basic and diluted), in the three months ended June 30, 2017, compared to a net loss of $100 million, or $0.21 loss per common unit (basic and diluted), in the three months ended June 30, 2016. This $146 million increase in net income in 2017 was primarily a result of increased income from operations and decreased loss on early extinguishment of debt, which were partially offset by increased interest expense, net of amounts capitalized.

Our consolidated net income was $93 million, or $4.50 loss per common unit (basic and diluted), in the six months ended June 30, 2017, compared to a net loss of $175 million, or $0.29 loss per common unit (basic and diluted), in the six months ended June 30, 2016. This $268 million increase in net income in 2017 was primarily a result of increased income from operations and decreased derivative loss, net, which were partially offset by increased interest expense, net of amounts capitalized, and loss on early extinguishment of debt.

Revenues



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except volumes)	2017		2016		Change		2017		2016		Change
LNG revenues	$	503	$	85	$	418	$	995	$	85	$	910
LNG revenues—affiliate	422		—		422		753		—		753
Regasification revenues	65		65		—		130		130		—
Other revenues	2		1		1		4		1		3
Other revenues—affiliate	—		—		—		1		2		(1		)
Total revenues	$	992	$	151	$	841	$	1,883	$	218	$	1,665

Volumes recognized as revenues (in TBtu)	167		18		149		295		18		277

We began recognizing LNG revenues from the Liquefaction Project following the substantial completion and the commencement of operating activities of Train 1 in May 2016. Trains 2 and 3 subsequently achieved substantial completion in September 2016 and March 2017, respectively. The increase in revenues for the three and six months ended June 30, 2017 from the comparable periods in 2016 was attributable to both the increased volume of LNG sold that was recognized as revenues, as well as increased revenues per MMBtu. As additional Trains become operational, we expect our LNG revenues to increase in the future.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process because these amounts are earned or loaded during the testing phase for the construction of that Train. We realized offsets to LNG terminal costs of $39 million corresponding to 8 TBtu of LNG and $128 million corresponding to 31 TBtu of LNG in the three months ended June 30, 2017 and 2016, respectively, and $163 million corresponding to 26 TBtu of LNG and $142 million corresponding to 35 TBtu of LNG in the six months ended June 30, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes.

Operating costs and expenses



	Three Months Ended June 30,							Six Months Ended June 30,
(in millions)	2017		2016		Change			2017		2016		Change
Cost of sales	$	577	$	49	$	528		$	1,090	$	53	$	1,037
Operating and maintenance expense	82		24		58			132		42		90
Operating and maintenance expense—affiliate	21		11		10			39		22		17
Development expense	1		—		1			1		—		1
General and administrative expense	2		4		(2		)	5		7		(2		)
General and administrative expense—affiliate	23		21		2			45		43		2
Depreciation and amortization expense	86		29		57			152		48		104
Total operating costs and expenses	$	792	$	138	$	654		$	1,464	$	215	$	1,249

Our total operating costs and expenses increased during the three and six months ended June 30, 2017 from the comparable periods in 2016, primarily as a result of additional Trains that were operating between the periods. During the six months ended June 30, 2017, Trains 1 and 2 were operating for six months and Train 3 was operating for three months, whereas only Train 1 was operating for one month during the comparable period in 2016.

Cost of sales increased during the three and six months ended June 30, 2017 from the comparable periods in 2016, primarily as a result of the increase in operating Trains during 2017. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to the extent those costs are not utilized for the commissioning process. The increase during the three and six months ended June 30, 2017 from the comparable periods in 2016 was primarily related to the increase in both the volume and pricing of natural gas feedstock. Cost of sales also includes gains and losses from derivatives associated with economic hedges to secure natural gas feedstock for the Liquefaction Project, variable transportation and storage costs and other costs to convert natural gas into LNG.

Operating and maintenance expense (including affiliates) increased during the three and six months ended June 30, 2017 from the comparable periods in 2016, as a result of the increase in operating Trains during 2017. Operating and maintenance expense includes costs associated with operating and maintaining the Liquefaction Project. The increase during the three and six

months ended June 30, 2017 from the comparable periods in 2016 was primarily related to natural gas transportation and storage capacity demand charges, third-party service and maintenance contract costs and payroll and benefit costs of operations personnel. Operating and maintenance expense (including affiliates) also includes TUA reservation charges as a result of the commencement of payments under the partial TUA assignment agreement with Total, insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the three and six months ended June 30, 2017 from the comparable periods in 2016 as a result of increased number of operational Trains, as the assets related to the Trains of the Liquefaction Project began depreciating upon reaching substantial completion.

As additional Trains become operational, we expect our operating costs and expenses to generally increase in the future, although certain costs will not proportionally increase with the number of operational Trains as cost efficiencies will be realized.

Other expense (income)



	Three Months Ended June 30,									Six Months Ended June 30,
(in millions)	2017			2016			Change			2017			2016			Change
Interest expense, net of capitalized interest	$	154		$	72		$	82		$	284		$	115		$	169
Loss on early extinguishment of debt	—			27			(27		)	42			28			14
Derivative loss, net	3			15			(12		)	3			36			(33		)
Other income	(3		)	(1		)	(2		)	(3		)	(1		)	(2		)
Total other expense	$	154		$	113		$	41		$	326		$	178		$	148

Interest expense, net of capitalized interest, increased during the three and six months ended June 30, 2017 compared to the three and six months ended June 30, 2016, primarily as a result of an increase in our indebtedness outstanding (before premium, discount and unamortized debt issuance costs), from $13.4 billion as of June 30, 2016 to $16.2 billion as of June 30, 2017, and a decrease in the portion of total interest costs that could be capitalized as Trains 1 through 3 of the Liquefaction Project completed construction. For the three and six months ended June 30, 2017, we incurred $224 million and $435 million of total interest cost, respectively, of which we capitalized $70 million and $151 million, respectively, which was directly related to the construction of the Liquefaction Project. For the three and six months ended June 30, 2016, we incurred $205 million and $397 million of total interest cost, respectively, of which we capitalized $133 million and $282 million, respectively, which was directly related to the construction of the Liquefaction Project.

Loss on early extinguishment of debt decreased during the three months ended June 30, 2017, as compared to the three months ended June 30, 2016, and increased during the six months ended June 30, 2017, as compared to the six months ended June 30, 2016. Loss on early extinguishment of debt recognized during the six months ended June 30, 2017 was attributable to the $42 million write-off of debt issuance costs in March 2017 upon termination of the remaining available balance of $1.6 billion under the 2015 SPL Credit Facilities in connection with the issuance of the 2028 SPL Senior Notes. Loss on early extinguishment of debt recognized during the six months ended June 30, 2016 was primarily due to the $26 million write-off of debt issuance costs related to the prepayment of approximately $1.3 billion of outstanding borrowings under the 2015 SPL Credit Facilities in June 2016 in connection with the issuance of the 2026 SPL Senior Notes.

Derivative loss, net decreased during the three and six months ended June 30, 2017 from the comparable periods in 2016, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods. During the six months ended June 30, 2017, the gain attributable to a relative increase in the long-term forward LIBOR curve during the period was offset by the $7 million loss in March 2017 upon the settlement of interest rate swaps associated with approximately $1.6 billion of commitments that were terminated under the 2015 SPL Credit Facilities.

Off-Balance Sheet Arrangements

As of June 30, 2017, we had no transactions that met the definition of off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.

Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes.

There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the year ended December 31, 2016.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 15—Recent Accounting Standards of our Notes to Consolidated Financial Statements.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Marketing and Trading Commodity Price Risk

We have entered into commodity derivatives consisting of natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):



	June 30, 2017				December 31, 2016
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	42	$	2	$	73	$	6

See Note 7—Derivative Instruments for additional details about our derivative instruments.

Interest Rate Risk

We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the 2015 SPL Credit Facilities (“SPL Interest Rate Derivatives”), the 2016 CQP Credit Facilities (“CQP Interest Rate Derivatives” and collectively, with the SPL Interest Rate Derivatives, the “Interest Rate Derivatives”). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the remaining terms of the Interest Rate Derivatives as follows (in millions):



	June 30, 2017				December 31, 2016
	Fair Value		Change in Fair Value		Fair Value			Change in Fair Value
SPL Interest Rate Derivatives	$	—	$	—	$	(6	)	$	2
CQP Interest Rate Derivatives	13		5		13			6


ITEM 4.	CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our general partner’s management, including our general partner’s Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

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

PART II. OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. There have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the year ended December 31, 2016.


ITEM 1A.	RISK FACTORS

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2016.


ITEM 5.	OTHER INFORMATION

Compliance Disclosure

Pursuant to Section 13(r) of the Exchange Act, if during the quarter ended June 30, 2017, we or any of our affiliates had engaged in certain transactions with Iran or with persons or entities designated under certain executive orders, we would be required to disclose information regarding such transactions in our quarterly report on Form 10-Q as required under Section 219 of the Iran Threat Reduction and Syria Human Rights Act of 2012. During the quarter ended June 30, 2017, we did not engage in any transactions with Iran or with persons or entities related to Iran.


ITEM 6.	EXHIBITS



Exhibit No.		Description
10.1		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00057 Process Flare Provisional Sum Closeout, dated April 4, 2017 and (ii) the Change Order CO-00058 Louisiana Sales and Use Tax Provisional Sum Closeout, dated May 4, 2017 (Incorporated by reference to Exhibit 10.40 to SPL’s Registration Statement on Form S-4 (SEC File No. 333-218646), filed on June 9, 2017)
10.2		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated as of December 20, 2012, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00035 Ingersoll Rand Vendor HAZOP Updates, dated April 4, 2017 and (ii) the Change Order CO-00036 Process Flare Provisional Sum Transfer, dated April 4, 2017 (Incorporated by reference to Exhibit 10.55 to SPL’s Registration Statement on Form S-4 (SEC File No. 333-218646), filed on June 9, 2017)
10.3		Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-00018 Stage 3 Process Flare Modification, dated March 10, 2017, (ii) the Change Order CO-00019 Site Drainage Design Change: Permanent Drainage Implementation, dated March 10, 2017 and (iii) the Change Order CO-00020 Soils Provisional Sum Partial True-up RECON 2, dated March 13, 2017 (Incorporated by reference to Exhibit 10.64 to SPL’s Registration Statement on Form S-4 (SEC File No. 333-218646), filed on June 9, 2017)
31.1*		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*		Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**		Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document



*	Filed herewith.
**	Furnished herewith.

SIGNATURES

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



		CHENIERE ENERGY PARTNERS, L.P.
		By:	Cheniere Energy Partners GP, LLC,
			its general partner

Date:	August 7, 2017	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)

Date:	August 7, 2017	By:	/s/ Leonard Travis
			Leonard Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)