Document

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. We plan to adopt this standard using the full retrospective approach. Preliminarily, we do not anticipate that the adoption will have a material impact upon our revenues. 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.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 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 November 3, 2017, the issuer had 348,617,792 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	24

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 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		U.S. Securities and Exchange Commission
SPA		LNG sale and purchase agreement
TBtu		trillion British thermal units, an energy unit
Train		an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA		terminal use agreement

Abbreviated Organizational Structure

The following diagram depicts our abbreviated organizational structure as of September 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)



	September 30,			December 31,
	2017			2016
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	—		$	—
Restricted cash	1,395			605
Accounts and other receivables	172			90
Accounts receivable—affiliate	18			99
Advances to affiliate	57			38
Inventory	77			97
Other current assets	35			29
Total current assets	1,754			958

Non-current restricted cash	48			—
Property, plant and equipment, net	15,097			14,158
Debt issuance costs, net	42			121
Non-current derivative assets	37			83
Other non-current assets, net	213			222
Total assets	$	17,191		$	15,542

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	24		$	27
Accrued liabilities	419			418
Current debt	—			224
Due to affiliates	55			99
Deferred revenue	134			73
Deferred revenue—affiliate	1			1
Derivative liabilities	4			14
Total current liabilities	637			856

Long-term debt, net	16,040			14,209
Non-current deferred revenue	2			5
Non-current derivative liabilities	2			2
Other non-current liabilities—affiliate	25			27

Partners’ equity
Common unitholders’ interest (348.6 million units and 57.1 million units issued and outstanding at September 30, 2017 and December 31, 2016, respectively)	1,559			130
Class B unitholders’ interest (zero and 145.3 million units issued and outstanding at September 30, 2017 and December 31, 2016, respectively)	—			62
Subordinated unitholders’ interest (135.4 million units issued and outstanding at September 30, 2017 and December 31, 2016)	(1,086		)	240
General partner’s interest (2% interest with 9.9 million units and 6.9 million units issued and outstanding at September 30, 2017 and December 31, 2016, respectively)	12			11
Total partners’ equity	485			443
Total liabilities and partners’ equity	$	17,191		$	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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Revenues
LNG revenues	$	723		$	249		$	1,718		$	334
LNG revenues—affiliate	111			16			864			16
Regasification revenues	65			64			195			194
Other revenues	3			1			7			2
Other revenues—affiliate	1			1			2			3
Total revenues	903			331			2,786			549

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	490			159			1,580			212
Cost of sales—affiliate	—			1			—			1
Operating and maintenance expense	73			38			205			80
Operating and maintenance expense—affiliate	31			14			70			36
Development expense	1			—			2			—
General and administrative expense	5			2			10			9
General and administrative expense—affiliate	18			25			63			68
Depreciation and amortization expense	87			44			239			92
Other	1			—			1			—
Total operating costs and expenses	706			283			2,170			498

Income from operations	197			48			616			51

Other income (expense)
Interest expense, net of capitalized interest	(153		)	(114		)	(437		)	(229		)
Loss on early extinguishment of debt	(25		)	(26		)	(67		)	(54		)
Derivative gain (loss), net	1			10			(2		)	(26		)
Other income	3			—			6			1
Total other expense	(174		)	(130		)	(500		)	(308		)

Net income (loss)	$	23		$	(82	)	$	116		$	(257	)

Basic and diluted net loss per common unit	$	(1.10	)	$	(0.27	)	$	(4.12	)	$	(0.56	)

Weighted average number of common units outstanding used for basic and diluted net loss per common unit calculation	247.2			57.1			121.2			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	—	30			—		—			—	84			—	2			116
Distributions	—	(73		)	—		—			—	—			—	(1		)	(74		)
Conversion of Class B units into common units	291.5	2,066			(145.3	)	(2,066		)	—	—			3.0	—			—
Amortization of beneficial conversion feature of Class B units	—	(594		)	—		2,004			—	(1,410		)	—	—			—
Balance at September 30, 2017	348.6	$	1,559		—		$	—		135.4	$	(1,086	)	9.9	$	12		$	485

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)



	Nine Months Ended September 30,
	2017			2016
Cash flows from operating activities
Net income (loss)	$	116		$	(257	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization expense	239			92
Amortization of debt issuance costs, deferred commitment fees, premium and discount	28			20
Loss on early extinguishment of debt	67			54
Total losses on derivatives, net	53			49
Net cash used for settlement of derivative instruments	(15		)	(9		)
Other	1			—
Changes in operating assets and liabilities:
Accounts and other receivables	(69		)	(31		)
Accounts receivable—affiliate	82			(36		)
Advances to affiliate	(36		)	—
Inventory	28			(26		)
Accounts payable and accrued liabilities	19			102
Due to affiliates	(47		)	9
Deferred revenue	58			(3		)
Other, net	(9		)	(6		)
Other, net—affiliate	(2		)	—
Net cash provided by (used in) operating activities	513			(42		)

Cash flows from investing activities
Property, plant and equipment, net	(1,195		)	(1,884		)
Other	—			(39		)
Net cash used in investing activities	(1,195		)	(1,923		)

Cash flows from financing activities
Proceeds from issuances of debt	3,814			5,419
Repayments of debt	(2,173		)	(3,130		)
Debt issuance and deferred financing costs	(47		)	(89		)
Distributions to owners	(74		)	(74		)
Net cash provided by financing activities	1,520			2,126

Net increase in cash, cash equivalents and restricted cash	838			161
Cash, cash equivalents and restricted cash—beginning of period	605			434
Cash, cash equivalents and restricted cash—end of period	$	1,443		$	595

Balances per Consolidated Balance Sheet:



	September 30, 2017
Cash and cash equivalents	$	—
Restricted cash	1,395
Non-current restricted cash	48
Total cash, cash equivalents and restricted cash	$	1,443

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 became operational in October 2017, 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 nine months ended September 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 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. On a quarterly basis beginning on the date of the initial purchase date of the Class B units, the conversion value of the Class B units increased at a compounded rate of 3.5% per quarter.

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

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



	September 30,		December 31,
	2017		2016
Current restricted cash
Liquefaction Project	$	579	$	358
CQP and cash held by guarantor subsidiaries	816		247
Total current restricted cash	$	1,395	$	605

Non-current restricted cash
Liquefaction Project	$	48	$	—

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

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



	September 30,		December 31,
	2017		2016
SPL trade receivable	$	154	$	88
Other accounts receivable	18		2
Total accounts and other receivables	$	172	$	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 September 30, 2017 and December 31, 2016, inventory consisted of the following (in millions):



	September 30,		December 31,
	2017		2016
Natural gas	$	16	$	15
LNG	13		45
Materials and other	48		37
Total inventory	$	77	$	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):



	September 30,			December 31,
	2017			2016
LNG terminal costs
LNG terminal	$	10,554		$	7,976
LNG terminal construction-in-process	5,320			6,728
Accumulated depreciation	(783		)	(553		)
Total LNG terminal costs, net	15,091			14,151
Fixed assets
Fixed assets	22			20
Accumulated depreciation	(16		)	(13		)
Total fixed assets, net	6			7
Property, plant and equipment, net	$	15,097		$	14,158

Depreciation expense was $85 million and $42 million in the three months ended September 30, 2017 and 2016, respectively, and $233 million and $86 million in the nine months ended September 30, 2017 and 2016, respectively.

We realized offsets to LNG terminal costs of $79 million and $59 million in the three months ended September 30, 2017 and 2016, respectively, and $242 million and $201 million in the nine months ended September 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 September 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
	September 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	—		14			—		14		—			13			—		13
Liquefaction Supply Derivatives asset (liability)	—		(1		)	29		28		(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 nine months ended September 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 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 September 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 September 30, 2017:



	Net Fair Value Asset (in millions)	Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$29	Income Approach	Basis Spread	$(0.370) - $0.081

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Balance, beginning of period	$	40		$	22		$	79		$	32
Realized and mark-to-market losses:
Included in cost of sales (1)	(8		)	(11		)	(43		)	(20		)
Purchases and settlements:
Purchases	(1		)	1			1			1
Settlements (1)	(2		)	—			(8		)	(1		)
Balance, end of period	$	29		$	12		$	29		$	12
Change in unrealized gains relating to instruments still held at end of period	$	(8	)	$	(11	)	$	(43	)	$	(20	)


(1)	Does not include the decrease in fair value of $1 million related to the realized gains capitalized during the nine months ended September 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 nine months ended September 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 September 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:



	September 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	$	—	$	3	$	3	$	—		$	—		$	—
Non-current derivative assets	—		11		11		—			16			16
Total derivative assets	—		14		14		—			16			16

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

Derivative asset (liability), net	$	—	$	14	$	14	$	(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 gain (loss), net on our Consolidated Statements of Operations during the three and nine months ended September 30, 2017 and 2016:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017			2016
SPL Interest Rate Derivatives gain (loss)	$	—	$	3	$	(2	)	$	(13	)
CQP Interest Rate Derivatives gain (loss)	1		7		—			(13		)

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	September 30, 2017			December 31, 2016
Liquefaction Supply Derivatives	Other current assets	$	8		$	13
Liquefaction Supply Derivatives	Non-current derivative assets	26			67
Liquefaction Supply Derivatives	Derivative liabilities	(4		)	(7		)
Liquefaction Supply Derivatives	Non-current derivative liabilities	(2		)	—


(1)	Does not include collateral of $2 million and $6 million deposited for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016, respectively.

SPL had secured up to approximately 2,462 TBtu and 1,994 TBtu of natural gas feedstock through natural gas supply contracts as of September 30, 2017 and December 31, 2016, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 1,549 TBtu and 1,117 TBtu as of September 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 nine months ended September 30, 2017 and 2016:



		Three Months Ended				Nine Months Ended
		September 30,				September 30,
	Statement of Operations Location (1)	2017		2016		2017		2016
Liquefaction Supply Derivatives loss (2)	Cost of sales	$	11	$	11	$	51	$	23


(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 September 30, 2017
CQP Interest Rate Derivatives	$	14		$	—		$	14
Liquefaction Supply Derivatives	35			(1		)	34
Liquefaction Supply Derivatives	(8		)	2			(6		)
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 September 30, 2017 and December 31, 2016, other non-current assets, net consisted of the following (in millions):



	September 30,		December 31,
	2017		2016
Advances made under EPC and non-EPC contracts	$	21	$	23
Advances made to municipalities for water system enhancements	94		95
Advances and other asset conveyances to third parties to support LNG terminals	30		31
Tax-related payments and receivables	37		28
Information technology service assets	23		27
Other	8		18
Total other non-current assets, net	$	213	$	222

NOTE 9—ACCRUED LIABILITIES

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



	September 30,		December 31,
	2017		2016
Interest costs and related debt fees	$	146	$	205
Sabine Pass LNG terminal and related pipeline costs	264		211
Other accrued liabilities	9		2
Total accrued liabilities	$	419	$	418

NOTE 10—DEBT

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



	September 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
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			—
2016 CQP Credit Facilities	1,090			2,560
Unamortized debt issuance costs	(210		)	(178		)
Total long-term debt, net	16,040			14,209

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

Total debt, net	$	16,040		$	14,433

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

2017 Debt Issuances and Redemptions

SPL Senior Notes

In February 2017, SPL issued an aggregate principal amount of $800 million of the 2037 SPL Senior Notes on a private placement basis in reliance on the exemption from registration provided for under Section 4(a)(2) of the Securities Act of 1933, as amended. In March 2017, SPL issued an aggregate principal amount of $1.35 billion, before discount, of the 2028 SPL Senior Notes. Net proceeds of the offerings of the 2037 SPL Senior Notes and the 2028 SPL Senior Notes were $789 million and $1.33 billion, respectively, after deducting the initial purchasers’ commissions (for the 2028 SPL Senior Notes) and estimated fees and expenses. The net proceeds of the 2037 SPL Senior Notes, after provisioning for incremental interest required during construction, were used to 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 nine months ended September 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 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.

2025 CQP Senior Notes

In September 2017, we issued an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing the release of its guarantee, Sabine Pass LNG-LP, LLC (the “CQP Guarantors”). Net proceeds of the offering of approximately $1.5 billion, after deducting the initial purchasers’ commissions and estimated fees and expenses, were used to prepay a portion of the outstanding indebtedness under the 2016 CQP Credit Facilities, resulting in a write-off of debt issuance costs associated with the 2016 CQP Credit Facilities of $25 million during the nine months ended September 30, 2017.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

The 2025 CQP Senior Notes are our senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of our future subordinated debt. The 2025 CQP Senior Notes will be secured alongside the 2016 CQP Credit Facilities on a first-priority basis (subject to permitted encumbrances) with liens on (1) substantially all the existing and future tangible and intangible assets and our rights and the rights of the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2016 CQP Credit Facilities) and (2) substantially all of the real property of SPLNG (except for excluded properties referenced in the 2016 CQP Credit Facilities). Upon the release of the liens securing the 2025 CQP Senior Notes, the limitation on liens covenant under the CQP Indenture will continue to govern the incurrence of liens by us and the CQP Guarantors.

In connection with the closing of the sale of the 2025 CQP Senior Notes, we and the CQP Guarantors entered into a registration rights agreement (the “CQP Registration Rights Agreement”). Under the CQP Registration Rights Agreement, we and the CQP Guarantors have agreed to use commercially reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange any and all of the 2025 CQP Senior Notes for a like aggregate principal amount of our debt securities with terms identical in all material respects to the 2025 CQP Senior Notes sought to be exchanged (other than with respect to restrictions on transfer or to any increase in annual interest rate), within 360 days after September 18, 2017. Under specified circumstances, we and the CQP Guarantors have also agreed to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2025 CQP Senior Notes. We will be obligated to pay additional interest on the 2025 CQP Senior Notes if we fail to comply with our obligation to register the 2025 CQP Senior Notes within the specified time period.

Credit Facilities

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



	SPL Working Capital Facility		2016 CQP Credit Facilities
Original facility size	$	1,200	$	2,800
Outstanding balance	—		1,090
Commitments prepaid or terminated	—		1,470
Letters of credit issued	721		50
Available commitment	$	479	$	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.

Interest Expense

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Total interest cost	$	227		$	221		$	662		$	619
Capitalized interest	(74		)	(107		)	(225		)	(390		)
Total interest expense, net	$	153		$	114		$	437		$	229

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value Disclosures

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



	September 30, 2017				December 31, 2016
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes, net of premium or discount (1)	$	14,360	$	15,556	$	11,513	$	12,309
2037 SPL Senior Notes (2)	800		844		—		—
Credit facilities (3)	1,090		1,090		3,098		3,098


(1)	Includes 2021 SPL Senior Notes, 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes, 2025 SPL Senior Notes, 2026 SPL Senior Notes, 2027 SPL Senior Notes, 2028 SPL Senior Notes and 2025 CQP Senior Notes. The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.


(2)	The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including our stock price and interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market.


(3)	Includes 2015 SPL Credit Facilities, SPL Working Capital Facility and 2016 CQP Credit Facilities. The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

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 nine months ended September 30, 2017 and 2016:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
LNG revenues—affiliate
Cheniere Marketing SPA and Cheniere Marketing Master SPA	$	111	$	16	$	864	$	16

Other revenues—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	—		—		—		1
Terminal Marine Services Agreement	1		1		2		2
Total other revenues—affiliate	1		1		2		3

Cost of sales—affiliate
Fees under the Pre-commercial LNG Marketing Agreement	—		1		—		1

Operating and maintenance expense—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	—		—		—		1
Services Agreements	25		14		64		35
Other agreements	6		—		6		—
Total operating and maintenance expense—affiliate	31		14		70		36

General and administrative expense—affiliate
Services Agreements	18		25		63		68

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 nine months ended September 30, 2017 and 2016, respectively, related to the Amended and Restated VCRA.

Cheniere Marketing SPA

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

Cheniere Marketing Master SPA

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

Commissioning Confirmation

Under the Cheniere Marketing Master SPA, SPL 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 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 September 30, 2017 and December 31, 2016, we had $57 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 ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Partners Services Agreement

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

Cheniere Investments Information Technology Services Agreement

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

SPLNG O&M Agreement

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

SPLNG MSA

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

SPL O&M Agreement

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

SPL MSA

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

CTPL O&M Agreement

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

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements (“CEAs”)

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

On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as a long-term obligation. As of both September 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 an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal. SPLNG did not record any revenues associated with this agreement during the three and nine months ended September 30, 2017 and 2016.

State Tax Sharing Agreements

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

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

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

NOTE 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 October 24, 2017, we declared a $0.44 distribution per common unit and subordinated unit and the related distribution to our general partner to be paid on November 14, 2017 to unitholders of record as of November 3, 2017 for the period from July 1, 2017 to September 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, which were mandatorily converted into our common units in accordance with the terms of our partnership agreement on August 2, 2017, were issued at a discount to the market price of the common units into which they were convertible. This discount, totaling $2,130 million, represented a beneficial conversion feature and was reflected as an increase in common and subordinated unitholders’ equity and a decrease in Class B unitholders’ equity to reflect the fair value of the Class B units at issuance on our Consolidated Statement of Partners’ Equity. The beneficial conversion feature was considered a dividend that was distributed ratably with respect to any Class B unit from its issuance date through its conversion date, which resulted in an increase in Class B unitholders’ equity and a decrease in common and subordinated unitholders’ equity. We amortized the beneficial conversion feature through the mandatory conversion date of August 2, 2017 using the effective yield method, with a weighted average effective yield of 888.7% per year and 966.1% per year for Cheniere Holdings’ and Blackstone CQP Holdco’s Class B units, respectively. The impact of the beneficial conversion feature was also included in earnings per unit for the three and nine months ended September 30, 2017 and 2016.

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 September 30, 2017
Net income	$	23
Declared distributions	217			153			—		60			4
Amortization of beneficial conversion feature of Class B units	—			(288		)	974		(686		)	—
Assumed allocation of undistributed net loss	$	(194	)	(137		)	—		(53		)	(4		)
Assumed allocation of net income				$	(272	)	$	974	$	(679	)	$	—

Weighted average units outstanding				247.2			50.6		135.4
Net loss per unit (1)				$	(1.10	)			$	(5.02	)

Three Months Ended September 30, 2016
Net loss	$	(82	)
Declared distributions	24			24			—		—			—
Amortization of beneficial conversion feature of Class B units	—			(9		)	30		(21		)	—
Assumed allocation of undistributed net loss	$	(106	)	(30		)	—		(73		)	(3		)
Assumed allocation of net loss				$	(15	)	$	30	$	(94	)	$	(3	)

Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit (1)				$	(0.27	)			$	(0.70	)

Nine Months Ended September 30, 2017
Net income	$	116
Declared distributions	267			202			—		60			5
Amortization of beneficial conversion feature of Class B units	—			(594		)	2,004		(1,410		)	—
Assumed allocation of undistributed net loss	$	(151	)	(107		)	—		(41		)	(3		)
Assumed allocation of net income				$	(499	)	$	2,004	$	(1,391	)	$	2

Weighted average units outstanding				121.2			113.4		135.4
Net loss per unit (1)				$	(4.12	)			$	(10.28	)

Nine Months Ended September 30, 2016
Net loss	$	(257	)
Declared distributions	74			73			—		—			1
Amortization of beneficial conversion feature of Class B units	—			(9		)	30		(21		)	—
Assumed allocation of undistributed net loss	$	(331	)	(96		)	—		(228		)	(7		)
Assumed allocation of net loss				$	(32	)	$	30	$	(249	)	$	(6	)

Weighted average units outstanding				57.1			145.3		135.4
Net loss per unit				$	(0.56	)			$	(1.84	)


(1)	Earnings per unit in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

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 Third-Party Revenues				Percentage of Accounts Receivable from Third Parties
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2017	2016	2017	2016	2017	2016
Customer A	31%	55%	42%	48%	33%	47%
Customer B	24%	—%	26%	—%	27%	50%
Customer C	35%	—%	18%	—%	29%	—%

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Nine Months Ended September 30,
	2017		2016
Cash paid during the period for interest, net of amounts capitalized	$	459	$	139

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $247 million and $295 million as of September 30, 2017 and 2016, respectively.

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 September 30, 2017:

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)



Standard	Description	Expected Date of Adoption	Effect on our Consolidated Financial Statements or Other Significant Matters
ASU 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.

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


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

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 became operational in October 2017, 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 aggregate 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


•	As of October 2017, more than 200 cumulative LNG cargoes had been produced, loaded and exported from the Liquefaction Project, with deliveries completed to 25 countries worldwide.

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 substantial completion was achieved in October 2017.

Financial


•	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 relating to Train 2 of the Liquefaction Project was reached under the respective 20-year SPAs with Gas Natural Fenosa LNG GOM, Limited and BG Gulf Coast LNG, LLC (“BG”).

•

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.


•	In September 2017, we issued an aggregate principal amount of $1.5 billion of 5.250% Senior Notes due 2025 (“the 2025 CQP Senior Notes”). Net proceeds of the offering of approximately $1.5 billion, after deducting commissions, fees and expenses, were used to prepay a portion of the outstanding indebtedness under our credit facilities (the “2016 CQP Credit Facilities”).


•	Fitch Ratings (“Fitch”) 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 (“Moody’s”) upgraded SPL’s senior secured debt rating from Ba1 to Baa3, an investment-grade rating.


•	In September 2017, Moody’s, S&P Global Ratings and Fitch assigned ratings of Ba2 / BB / BB, respectively to the 2025 CQP Senior Notes.

Liquidity and Capital Resources

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



	September 30,		December 31,
	2017		2016
Cash and cash equivalents	$	—	$	—
Restricted cash designated for the following purposes:
Liquefaction Project	627		358
CQP and cash held by guarantor subsidiaries	816		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”)	479		653
2016 CQP Credit Facilities	190		195

For additional information regarding our debt agreements, 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.

2025 CQP Senior Notes

The 2025 CQP Senior Notes are governed by an indenture (the “CQP Indenture”), which contains customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of the CQP Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

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. In September 2017, we issued the 2025 CQP Senior Notes and the net proceeds of the issuance was used to prepay $1.5 billion of the outstanding indebtedness under the 2016 CQP Credit Facilities. As of September 30, 2017 and December 31, 2016, we had $190 million and $195 million of available commitments, $50 million and $45 million aggregate amount of issued letters of credit and $1.1 billion and $2.6 billion of outstanding borrowings under the 2016 CQP Credit Facilities, 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.

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 September 30, 2017:



	Trains 1 & 2		Trains 3 & 4		Train 5
Overall project completion percentage	100%		100%		76.1%
Completion percentage of:
Engineering	100%		100%		100%
Procurement	100%		100%		98.9%
Subcontract work	100%		100%		58.6%
Construction	100%		99.9%		45.1%
Date of expected substantial completion	Train 1	Operational	Train 3	Operational	Train 5	2H 2019
	Train 2	Operational	Train 4	October 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 subsequently achieved substantial completion of Train 4 of the Liquefaction Project in October 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, SPL received an order providing for a three-year makeup period with respect to each of the non-FTA orders for LNG volumes SPL was authorized but 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 (the “Court of Appeals”) 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. The Court of Appeals denied the petition relating to the 503.3 Bcf/yr order to non-FTA countries in November 2017, and the time for review of the court’s denial has not yet expired.

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. Under SPL’s SPA with BG, BG has contracted for volumes related to Trains 3 and 4 for which the obligation to make LNG available to BG is expected to commence approximately one year after the date of first commercial delivery for the respective 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 under the respective SPA 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 September 30, 2017, SPL has secured up to approximately 2,462 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 September 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 gained access to a portion of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Trains 5 and 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During the three and nine months ended September 30, 2017, SPL recorded $7 million and $15 million, respectively, 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 project debt and 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. We realized offsets to LNG terminal costs of $79 million and $59 million in the three months ended September 30, 2017 and 2016, respectively, and $242 million and $201 million in the nine months ended September 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 September 30, 2017 and December 31, 2016:



	September 30,		December 31,
	2017		2016
Senior notes (1)	$	15,150	$	11,500
Credit facilities outstanding balance (2)	1,090		3,097
Letters of credit issued (3)	721		324
Available commitments under credit facilities (3)	479		2,295
Total capital resources from borrowings and available commitments	$	17,440	$	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”) and our 2025 CQP 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.

SPL Senior 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 September 30, 2017 and December 31, 2016, SPL had $479 million and $653 million of available commitments, $721 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 nine months ended September 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.



	Nine Months Ended September 30,
	2017			2016
Operating cash flows	$	513		$	(42	)
Investing cash flows	(1,195		)	(1,923		)
Financing cash flows	1,520			2,126

Net increase in cash, cash equivalents and restricted cash	838			161
Cash, cash equivalents and restricted cash—beginning of period	605			434
Cash, cash equivalents and restricted cash—end of period	$	1,443		$	595

Operating Cash Flows

Our operating cash flows increased from outflows of $42 million during the nine months ended September 30, 2016 to inflows of $513 million during the nine months ended September 30, 2017. The $555 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 nine months ended September 30, 2017, Trains 1 and 2 were operating for nine months and Train 3 was operating for six months, whereas Train 1 was operating for four months and Train 2 was operating for less than a month during the comparable period in 2016.

Investing Cash Flows

Investing cash outflows during the nine months ended September 30, 2017 and 2016 were $1.2 billion and $1.9 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 nine months ended September 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 nine months ended September 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 $369 million of repayments made under the 2015 SPL Credit Facilities;


•	issuance of an aggregate principal amount of $1.5 billion of the 2025 CQP Senior Notes, which was used to prepay $1.5 billion of the outstanding borrowings under the 2016 CQP Credit Facilities;


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


•	$47 million of debt issuance costs related to up-front fees paid upon the closing of these transactions; and


•	$74 million of distributions to unitholders.

Financing cash inflows during the nine months ended September 30, 2016 were $2.1 billion, primarily as a result of:


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


•	$1.7 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;


•	issuance of an aggregate principal amount of $1.5 billion of the 2027 SPL Senior Notes in September 2016, which was used to prepay $1.2 billion of the outstanding borrowings under the 2015 SPL Credit Facilities and pay a portion of the capital costs in connection with the construction of Trains 1 through 5 of the Liquefaction Project;


•	$314 million of borrowings and $230 million of repayments made under the SPL Working Capital Facility;


•	$89 million of debt issuance costs related to up-front fees paid upon the closing of these transactions; and


•	$74 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. Historically, on a quarterly basis, we have declared and paid a $0.425 distribution per common unit and the related distribution to our general partner of $24 million and $0.5 million, respectively. On October 24, 2017, we declared a $0.44 distribution per common unit and subordinated unit and the related distribution to our general partner to be paid on November 14, 2017 to unitholders of record as of November 3, 2017 for the period from July 1, 2017 to September 30, 2017.

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. On a quarterly basis beginning on the initial purchase date of the Class B units, the conversion value of the Class B units increased at a compounded rate of 3.5% per quarter. On August 2, 2017, the Class B units mandatorily converted into common units in accordance with the terms of the partnership agreement.

Results of Operations

Our consolidated net income was $23 million, or $1.10 loss per common unit (basic and diluted), in the three months ended September 30, 2017, compared to a net loss of $82 million, or $0.27 loss per common unit (basic and diluted), in the three months ended September 30, 2016. This $105 million increase in net income in 2017 was primarily a result of increased income from operations, which was partially offset by increased interest expense, net of amounts capitalized.

Our consolidated net income was $116 million, or $4.12 loss per common unit (basic and diluted), in the nine months ended September 30, 2017, compared to a net loss of $257 million, or $0.56 loss per common unit (basic and diluted), in the nine months ended September 30, 2016. This $373 million increase in net income in 2017 was primarily a result of increased income from operations and decreased derivative loss, net associated with interest rate derivative activity, which were partially offset by increased interest expense, net of amounts capitalized.

In August 2017, Hurricane Harvey struck the Texas and Louisiana coasts, and the Sabine Pass LNG terminal experienced a temporary suspension in construction and LNG loading operations. The terminal did not sustain significant damage, and the effects of Hurricane Harvey did not have a material impact on our Consolidated Financial Statements.

Revenues



	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except volumes)	2017		2016		Change		2017		2016		Change
LNG revenues	$	723	$	249	$	474	$	1,718	$	334	$	1,384
LNG revenues—affiliate	111		16		95		864		16		848
Regasification revenues	65		64		1		195		194		1
Other revenues	3		1		2		7		2		5
Other revenues—affiliate	1		1		—		2		3		(1		)
Total revenues	$	903	$	331	$	572	$	2,786	$	549	$	2,237

LNG volumes recognized as revenues (in TBtu)	144		51		93		439		69		370

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 nine months ended September 30, 2017 from the comparable periods in 2016 was attributable to both the increased volume of LNG sold that was recognized as revenues following the achievement of substantial completion of these Trains, 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 $79 million corresponding to 14 TBtu of LNG and $59 million corresponding to 10 TBtu of LNG in the three months ended September 30, 2017 and 2016, respectively, and $242 million corresponding to 40 TBtu of LNG and $201 million corresponding to 45 TBtu of LNG in the nine months ended September 30, 2017 and 2016, respectively, that were related to the sale of commissioning cargoes.

Operating costs and expenses



	Three Months Ended September 30,							Nine Months Ended September 30,
(in millions)	2017		2016		Change			2017		2016		Change
Cost of sales	$	490	$	159	$	331		$	1,580	$	212	$	1,368
Cost of sales—affiliate	—		1		(1		)	—		1		(1		)
Operating and maintenance expense	73		38		35			205		80		125
Operating and maintenance expense—affiliate	31		14		17			70		36		34
Development expense	1		—		1			2		—		2
General and administrative expense	5		2		3			10		9		1
General and administrative expense—affiliate	18		25		(7		)	63		68		(5		)
Depreciation and amortization expense	87		44		43			239		92		147
Other	1		—		1			1		—		1
Total operating costs and expenses	$	706	$	283	$	423		$	2,170	$	498	$	1,672

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

Cost of sales increased during the three and nine months ended September 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 nine months ended September 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 nine months ended September 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 nine months ended September 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 nine months ended September 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 September 30,									Nine Months Ended September 30,
(in millions)	2017			2016			Change			2017			2016			Change
Interest expense, net of capitalized interest	$	153		$	114		$	39		$	437		$	229		$	208
Loss on early extinguishment of debt	25			26			(1		)	67			54			13
Derivative loss (gain), net	(1		)	(10		)	9			2			26			(24		)
Other income	(3		)	—			(3		)	(6		)	(1		)	(5		)
Total other expense	$	174		$	130		$	44		$	500		$	308		$	192

Interest expense, net of capitalized interest, increased during the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016, primarily as a result of a decrease in the portion of total interest costs that could be capitalized as Trains 1 through 3 of the Liquefaction Project completed construction and an increase in our indebtedness outstanding (before premium, discount and unamortized debt issuance costs), from $14.1 billion as of September 30, 2016 to $16.2 billion as of September 30, 2017. For the three and nine months ended September 30, 2017, we incurred $227 million and $662 million of total interest cost, respectively, of which we capitalized $74 million and $225 million, respectively, which was directly related to the construction of the Liquefaction Project. For the three and nine months ended September 30, 2016, we incurred $221 million and $619 million of total interest cost, respectively, of which we capitalized $107 million and $390 million, respectively, which was directly related to the construction of the Liquefaction Project.

Loss on early extinguishment of debt increased during the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016. Loss on early extinguishment of debt recognized during the nine months ended September 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, in addition to $25 million write-off of debt issuance costs in September 2017 related to the prepayment of $1.5 billion of the outstanding indebtedness under the 2016 CQP Credit Facilities in connection with the issuance of the 2025 CQP Senior Notes. Loss on early extinguishment of debt recognized during the nine months ended September 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, in addition to $26 million write-off of debt issuance costs related to the prepayment of outstanding borrowings and termination of commitments under the 2015 SPL Credit Facilities of approximately $1.4 billion in September 2016 in connection with the issuance of the 2027 SPL Senior Notes.

Derivative gain, net decreased during the three months ended September 30, 2017 from the three months ended September 30, 2016, primarily due to an unfavorable shift in the long-term forward LIBOR curve between the periods. Derivative loss, net decreased during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016, primarily due to a favorable shift in the long-term forward LIBOR curve between the periods, partially 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 September 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):



	September 30, 2017				December 31, 2016
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	28	$	1	$	73	$	6

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):



	September 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	14		5		13			6

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


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 6.	EXHIBITS



Exhibit No.		Description
4.1		Indenture, dated as of September 18, 2017, between Cheniere Energy Partners, L.P., the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on September 18, 2017)
4.2		First Supplemental Indenture, dated as of September 18, 2017, between Cheniere Energy Partners, L.P., the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on September 18, 2017)
4.3		Form of 5.250% Senior Note due 2025 (Included as Exhibit A-1 to Exhibit 4.2 above)
10.1*		Administrative Amendment, dated August 7, 2017, to the Credit and Guaranty Agreement among the Partnership, as Borrower, certain subsidiaries of the Partnership, as Subsidiary Guarantors, the lenders from time to time party thereto, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing Bank, Administrative Agent and Coordinating Lead Arranger, and certain arrangers and other participants
10.2		Registration Rights Agreement, dated as of September 18, 2017, between Cheniere Energy Partners, L.P., the guarantors party thereto and Credit Suisse Securities (USA) LLC (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on September 18, 2017)
10.3*		Change order 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.: the Change Order CO-00059 Insurance Provisional Sum Closeout, dated May 18, 2017
10.4*		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-00037 HPAA Compressor MODBUS Link, dated June 28, 2017 and (ii) the Change Order CO-00038 Existing Facility Labor Provisional Sum Closure, dated August 24, 2017
10.5*		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 3 Liquefaction Facility, dated as of May 4, 2015, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: the Change Order CO-00021 Soils Preparation Provisional Sum Partial True-Up RECON 3, dated August 24, 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:	November 8, 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:	November 8, 2017	By:	/s/ Leonard Travis
			Leonard Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)