Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2019

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

For the transition period from to

Commission file number 001-33366

Cheniere Energy Partners, L.P.

(Exact name of registrant as specified in its charter)



Delaware			20-5913059
(State or other jurisdiction of incorporation or organization)			(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)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	CQP	NYSE American

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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ 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.



Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	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 ☐ No ☒

As of August 2, 2019, the registrant had 348,626,792 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 Income	4
	Consolidated Statements 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	33

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44

Item 4.	Controls and Procedures	44

Part II. Other Information
Item 1.	Legal Proceedings	45

Item 1A.	Risk Factors	45

Item 6.	Exhibits	46

	Signatures	47

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 Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of June 30, 2019, 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. and its consolidated subsidiaries, including SPLNG, SPL and CTPL.

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


PART I.	FINANCIAL INFORMATION


ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)



	June 30,			December 31,
	2019			2018
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	1,016		$	—
Restricted cash	596			1,541
Accounts and other receivables	243			348
Accounts receivable—affiliate	166			114
Advances to affiliate	225			228
Inventory	104			99
Derivative assets	17			6
Other current assets	67			20
Other current assets—affiliate	1			—
Total current assets	2,435			2,356

Property, plant and equipment, net	16,232			15,390
Operating lease assets, net	92			—
Debt issuance costs, net	20			13
Non-current derivative assets	37			31
Other non-current assets, net	157			184
Total assets	$	18,973		$	17,974

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	74		$	15
Accrued liabilities	1,076			821
Due to affiliates	44			49
Deferred revenue	122			116
Deferred revenue—affiliate	—			1
Current operating lease liabilities	6			—
Derivative liabilities	8			66
Total current liabilities	1,330			1,068

Long-term debt, net	16,720			16,066
Non-current operating lease liabilities	86			—
Non-current derivative liabilities	12			14
Other non-current liabilities	3			4
Other non-current liabilities—affiliate	21			22

Partners’ equity
Common unitholders’ interest (348.6 million units issued and outstanding at June 30, 2019 and December 31, 2018)	1,827			1,806
Subordinated unitholders’ interest (135.4 million units issued and outstanding at June 30, 2019 and December 31, 2018)	(982		)	(990		)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at June 30, 2019 and December 31, 2018)	(44		)	(16		)
Total partners’ equity	801			800
Total liabilities and partners’ equity	$	18,973		$	17,974

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per unit data)

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Revenues
LNG revenues	$	1,171		$	1,155		$	2,538		$	2,170
LNG revenues—affiliate	455			178			760			681
Regasification revenues	67			65			133			130
Other revenues	12			9			23			19
Total revenues	1,705			1,407			3,454			3,000

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	880			698			1,759			1,535
Operating and maintenance expense	162			98			300			193
Operating and maintenance expense—affiliate	37			30			66			56
Development expense	—			1			—			1
General and administrative expense	3			2			6			6
General and administrative expense—affiliate	27			17			48			35
Depreciation and amortization expense	138			106			252			211
Impairment expense and loss on disposal of assets	3			—			5			—
Total operating costs and expenses	1,250			952			2,436			2,037

Income from operations	455			455			1,018			963

Other income (expense)
Interest expense, net of capitalized interest	(230		)	(184		)	(417		)	(369		)
Derivative gain, net	—			3			—			11
Other income	7			7			16			11
Total other expense	(223		)	(174		)	(401		)	(347		)

Net income	$	232		$	281		$	617		$	616

Basic and diluted net income per common unit	$	0.44		$	0.55		$	1.19		$	1.22

Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation	348.6			348.6			348.6			348.6

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(in millions)

(unaudited)



Three and Six Months Ended June 30, 2019
	Common Unitholders’ Interest				Subordinated Unitholder’s Interest				General Partner’s Interest				Total Partners’ Equity
	Units	Amount			Units	Amount			Units	Amount			Total Partners’ Equity
Balance at December 31, 2018	348.6	$	1,806		135.4	$	(990	)	9.9	$	(16	)	$	800
Net income	—	272			—	105			—	8			385
Distributions
Common units, $0.59/unit	—	(206		)	—	—			—	—			(206		)
Subordinated units, $0.59/unit	—	—			—	(80		)	—	—			(80		)
General partner units	—	—			—	—			—	(18		)	(18		)
Balance at March 31, 2019	348.6	1,872			135.4	(965		)	9.9	(26		)	881
Net income	—	164			—	64			—	4			232
Distributions
Common units, $0.60/unit	—	(209		)	—	—			—	—			(209		)
Subordinated units, $0.60/unit	—	—			—	(81		)	—	—			(81		)
General partner units	—	—			—	—			—	(22		)	(22		)
Balance at June 30, 2019	348.6	$	1,827		135.4	$	(982	)	9.9	$	(44	)	$	801



Three and Six Months Ended June 30, 2018
	Common Unitholders’ Interest				Subordinated Unitholder’s Interest				General Partner’s Interest				Total Partners’ Equity
	Units	Amount			Units	Amount			Units	Amount			Total Partners’ Equity
Balance at December 31, 2017	348.6	$	1,670		135.4	$	(1,043	)	9.9	$	12		$	639
Net income	—	236			—	92			—	7			335
Distributions
Common units, $0.50/unit	—	(175		)	—	—			—	—			(175		)
Subordinated units, $0.50/unit	—	—			—	(68		)	—	—			(68		)
General partner units	—	—			—	—			—	(6		)	(6		)
Balance at March 31, 2018	348.6	1,731			135.4	(1,019		)	9.9	13			725
Net income	—	199			—	77			—	5			281
Distributions
Common units, $0.55/unit	—	(191		)	—	—			—	—			(191		)
Subordinated units, $0.55/unit	—	—			—	(74		)	—	—			(74		)
General partner units	—	—			—	—			—	(13		)	(13		)
Balance at June 30, 2018	348.6	$	1,739		135.4	$	(1,016	)	9.9	$	5		$	728

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)



	Six Months Ended June 30,
	2019			2018
Cash flows from operating activities
Net income	$	617		$	616
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	252			211
Amortization of debt issuance costs, deferred commitment fees, premium and discount	14			16
Total losses (gains) on derivatives, net	(84		)	41
Net cash provided by (used for) settlement of derivative instruments	7			(3		)
Impairment expense and loss on disposal of assets	5			—
Other	5			3
Changes in operating assets and liabilities:
Accounts and other receivables	70			(50		)
Accounts receivable—affiliate	(52		)	142
Advances to affiliate	(25		)	(70		)
Inventory	(4		)	8
Accounts payable and accrued liabilities	(123		)	(59		)
Due to affiliates	(2		)	(15		)
Deferred revenue	7			(14		)
Other, net	(44		)	(19		)
Other, net—affiliate	(3		)	(2		)
Net cash provided by operating activities	640			805

Cash flows from investing activities
Property, plant and equipment, net	(585		)	(345		)
Other	(1		)	—
Net cash used in investing activities	(586		)	(345		)

Cash flows from financing activities
Proceeds from issuances of debt	649			—
Debt issuance and deferred financing costs	(19		)	(1		)
Distributions to owners	(616		)	(527		)
Other	3			—
Net cash provided by (used in) financing activities	17			(528		)

Net increase (decrease) in cash, cash equivalents and restricted cash	71			(68		)
Cash, cash equivalents and restricted cash—beginning of period	1,541			1,589
Cash, cash equivalents and restricted cash—end of period	$	1,612		$	1,521

Balances per Consolidated Balance Sheet:



	June 30, 2019
Cash and cash equivalents	$	1,016
Restricted cash	596
Total cash, cash equivalents and restricted cash	$	1,612

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 in various stages of constructing and operating six 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. Trains 1 through 5 are operational and Train 6 is under construction. The Sabine Pass LNG terminal has operational regasification facilities owned by SPLNG and a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines through our wholly owned subsidiary, CTPL.

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, 2018.

Results of operations for the three and six months ended June 30, 2019 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2019.

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.

Recent Accounting Standards

We adopted ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto (“ASC 842”) on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. The adoption of the standard resulted in the recognition of right-of-use assets and lease liabilities for operating leases of approximately $100 million on our Consolidated Balance Sheets, with no material impact on our Consolidated Statements of Income or Consolidated Statements of Cash Flows. We have elected the practical expedients to (1) carryforward prior conclusions related to lease identification and classification for existing leases, (2) combine lease and non-lease components of an arrangement for all classes of leased assets, (3) omit short-term leases with a term of 12 months or less from recognition on the balance sheet and (4) carryforward our existing accounting for land easements not previously accounted for as leases. See Note 11—Leases for additional information on our leases following the adoption of this standard.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

met, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.

As of June 30, 2019, Cheniere, Blackstone CQP Holdco and the public owned a 48.6%, 40.3% and 9.1% interest in us, respectively. Cheniere’s 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 and legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of June 30, 2019 and December 31, 2018, restricted cash consisted of the following (in millions):



	June 30,		December 31,
	2019		2018
Current restricted cash
Liquefaction Project	$	596	$	756
Cash held by us and our guarantor subsidiaries	—		785
Total current restricted cash	$	596	$	1,541

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.

In May 2019, we entered into the $1.5 billion credit facilities (the “2019 CQP Credit Facilities”), which replaced the previous $2.8 billion credit facilities (the “2016 CQP Credit Facilities”). The cash held by us and our guarantor subsidiaries was restricted in use under the terms of the 2016 CQP Credit Facilities and the related depositary agreement governing the extension of credit to us, but is no longer restricted under the 2019 CQP Credit Facilities.

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of June 30, 2019 and December 31, 2018, accounts and other receivables consisted of the following (in millions):



	June 30,		December 31,
	2019		2018
SPL trade receivable	$	234	$	330
Other accounts receivable	9		18
Total accounts and other receivables	$	243	$	348

NOTE 5—INVENTORY

As of June 30, 2019 and December 31, 2018, inventory consisted of the following (in millions):



	June 30,		December 31,
	2019		2018
Natural gas	$	15	$	28
LNG	10		6
Materials and other	79		65
Total inventory	$	104	$	99

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

As of June 30, 2019 and December 31, 2018, property, plant and equipment, net consisted of the following (in millions):



	June 30,			December 31,
	2019			2018
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	16,761		$	12,760
LNG terminal construction-in-process	1,000			3,913
Accumulated depreciation	(1,536		)	(1,290		)
Total LNG terminal costs, net	16,225			15,383
Fixed assets
Fixed assets	27			26
Accumulated depreciation	(20		)	(19		)
Total fixed assets, net	7			7
Property, plant and equipment, net	$	16,232		$	15,390

Depreciation expense was $137 million and $104 million during the three months ended June 30, 2019 and 2018, respectively, and $250 million and $206 million during the six months ended June 30, 2019 and 2018, respectively.

We realized offsets to LNG terminal costs of $48 million during the six months ended June 30, 2019 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 Trains of the Liquefaction Project, during the testing phase for its construction. We did not realize any offsets to LNG terminal costs during the three months ended June 30, 2019 and the three and six months ended June 30, 2018.

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”).

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Income to the extent not utilized for the commissioning process.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis as of June 30, 2019 and December 31, 2018, which are classified as derivative assets, non-current derivative assets, derivative liabilities or non-current derivative liabilities in our Consolidated Balance Sheets (in millions).



	Fair Value Measurements as of
	June 30, 2019									December 31, 2018
	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
Liquefaction Supply Derivatives asset (liability)	$	1	$	(1	)	$	34	$	34	$	5	$	(23	)	$	(25	)	$	(43	)

We value our Liquefaction Supply Derivatives using a market-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data.

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated conditions

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

precedent, including evaluating whether the respective market is available as pipeline infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of June 30, 2019 and December 31, 2018, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which may be impacted by inputs that are unobservable in the marketplace. The curves used to generate the fair value of our Physical Liquefaction Supply Derivatives are based on basis adjustments applied to forward curves for a liquid trading point. In addition, there may be observable liquid market basis information in the near term, but terms of a Physical Liquefaction Supply Derivatives contract may exceed the period for which such information is available, resulting in a Level 3 classification. In these instances, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market basis price for future delivery periods in which applicable commodity basis prices were either not observable or lacked corroborative market data.

The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas market basis spreads due to the contractual notional amount represented by our Level 3 positions, which is a substantial portion of our overall Physical Liquefaction Supply Derivatives portfolio. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of June 30, 2019:



	Net Fair Value Asset (in millions)	Valuation Approach	Significant Unobservable Input	Significant Unobservable Inputs Range
Physical Liquefaction Supply Derivatives	$34	Market approach incorporating present value techniques	Henry Hub Basis Spread	$(0.350) - $0.056

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three and six months ended June 30, 2019 and 2018 (in millions):



	Three Months Ended June 30,					Six Months Ended June 30,
	2019		2018			2019			2018
Balance, beginning of period	$	29	$	10		$	(25	)	$	43
Realized and mark-to-market gains (losses):
Included in cost of sales	3		(1		)	16			(13		)
Purchases and settlements:
Purchases	1		6			—			6
Settlements	1		(4		)	43			(25		)
Balance, end of period	$	34	$	11		$	34		$	11
Change in unrealized gains (losses) relating to instruments still held at end of period	$	3	$	(1	)	$	16		$	(13	)

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 the unconditional right of set-off in the event of default. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of netting and any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

Interest Rate Derivatives

We previously had interest rate swaps (“CQP Interest Rate Derivatives” and, collectively with the CCH Interest Rate Derivatives and the CCH Interest Rate Forward Start Derivatives, the “Interest Rate Derivatives”) to hedge a portion of the variable interest payments on our credit facilities, which were terminated in October 2018.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the changes in the fair value and settlements of our Interest Rate Derivatives recorded in derivative gain, net on our Consolidated Statements of Income during the three and six months ended June 30, 2019 and 2018 (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
CQP Interest Rate Derivatives gain	$	—	$	3	$	—	$	11

Liquefaction Supply Derivatives

SPL has entered into primarily index-based physical natural gas supply contracts and associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project. The terms of the physical natural gas supply contracts range up to five years, some of which commence upon the satisfaction of certain conditions precedent.

SPL had secured up to approximately 3,437 TBtu and 3,464 TBtu of natural gas feedstock through natural gas supply contracts as of June 30, 2019 and December 31, 2018, respectively. The notional natural gas position of our Liquefaction Supply Derivatives was approximately 3,122 TBtu and 2,978 TBtu as of June 30, 2019 and December 31, 2018, respectively.

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



	Fair Value Measurements as of (1)
Consolidated Balance Sheet Location	June 30, 2019			December 31, 2018
Derivative assets	$	17		$	6
Non-current derivative assets	37			31
Total derivative assets	54			37

Derivative liabilities	(8		)	(66		)
Non-current derivative liabilities	(12		)	(14		)
Total derivative liabilities	(20		)	(80		)

Derivative asset (liability), net	$	34		$	(43	)


(1)	Does not include collateral calls of $2 million and $1 million for such contracts, which are included in other current assets in our Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018, respectively.

The following table shows the changes in the fair value, settlements and location of our Liquefaction Supply Derivatives on our Consolidated Statements of Income during the three and six months ended June 30, 2019 and 2018 (in millions):



		Three Months Ended June 30,					Six Months Ended June 30,
	Consolidated Statement of Income Location (1)	2019		2018			2019		2018
Liquefaction Supply Derivatives gain	LNG revenues	$	—	$	—		$	1	$	—
Liquefaction Supply Derivatives gain (loss)	Cost of sales	7		(2		)	83		(52		)


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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Consolidated Balance Sheet Presentation

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



	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Offsetting Derivative Assets (Liabilities)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
As of June 30, 2019
Liquefaction Supply Derivatives	$	56		$	(2	)	$	54
Liquefaction Supply Derivatives	(21		)	1			(20		)
As of December 31, 2018
Liquefaction Supply Derivatives	$	63		$	(26	)	$	37
Liquefaction Supply Derivatives	(92		)	12			(80		)

NOTE 8—OTHER NON-CURRENT ASSETS

As of June 30, 2019 and December 31, 2018, other non-current assets, net consisted of the following (in millions):



	June 30,		December 31,
	2019		2018
Advances made to municipalities for water system enhancements	$	89	$	90
Advances and other asset conveyances to third parties to support LNG terminals	36		36
Tax-related payments and receivables	17		17
Information technology service assets	9		20
Advances made under EPC and non-EPC contracts	—		14
Other	6		7
Total other non-current assets, net	$	157	$	184

NOTE 9—ACCRUED LIABILITIES

As of June 30, 2019 and December 31, 2018, accrued liabilities consisted of the following (in millions):



	June 30,		December 31,
	2019		2018
Interest costs and related debt fees	$	266	$	224
Accrued natural gas purchases	310		518
LNG terminal and related pipeline costs	484		79
Other accrued liabilities	16		—
Total accrued liabilities	$	1,076	$	821

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 10—DEBT

As of June 30, 2019 and December 31, 2018, our debt consisted of the following (in millions):



	June 30,			December 31,
	2019			2018
Long-term debt:
SPL
5.625% Senior Secured Notes due 2021 (“2021 SPL Senior Notes”)	$	2,000		$	2,000
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”)	1,500			1,500
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”)	1,350			1,350
5.00% Senior Secured Notes due 2037 (“2037 SPL Senior Notes”)	800			800
Cheniere Partners
5.250% Senior Notes due 2025 (“2025 CQP Senior Notes”)	1,500			1,500
5.625% Senior Notes due 2026 (“2026 CQP Senior Notes”)	1,100			1,100
2016 CQP Credit Facilities	—			—
2019 CQP Credit Facilities	649			—
Unamortized premium, discount and debt issuance costs, net	(179		)	(184		)
Total long-term debt, net	16,720			16,066

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

Total debt, net	$	16,720		$	16,066

2019 Debt Issuances and Terminations

2016 CQP Credit Facilities

In May 2019, the remaining commitments under the 2016 CQP Credit Facilities were terminated. There were no write-offs of debt issuance costs associated with the termination of the 2016 CQP Credit Facilities.

2019 CQP Credit Facilities

In May 2019, we entered into the $1.5 billion 2019 CQP Credit Facilities, which consist of a $750 million term loan (“CQP Term Facility”) and a $750 million revolving credit facility (“CQP Revolving Facility”). Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the Liquefaction Project and subject to a sublimit, for general corporate purposes. The CQP Revolving Facility is also available for the issuance of letters of credit.

Loans under the 2019 CQP Credit Facilities will accrue interest at a variable rate per annum equal to LIBOR or the base rate (equal to the highest of the prime rate, the federal funds effective rate, as published by the Federal Reserve Bank of New York, plus 0.50%, and the adjusted one-month LIBOR plus 1.0%), plus the applicable margin. Under the CQP Term Facility, the applicable margin for LIBOR loans is 1.50% per annum, and the applicable margin for base rate loans is 0.50% per annum, in each case with a 0.25% step-up beginning on May 29, 2022. Under the CQP Revolving Facility, the applicable margin for LIBOR loans is 1.25% to 2.125% per annum, and the applicable margin for base rate loans is 0.25% to 1.125% per annum, in each case depending on our then-current rating. Interest on LIBOR loans is due and payable at the end of each applicable LIBOR period (and at the end of every three-month period within the LIBOR period, if any), and interest on base rate loans is due and payable at the end of each calendar quarter.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

We incurred $20 million of discounts and debt issuance costs in conjunction with the entry into the 2019 CQP Credit Facilities. We pay a commitment fee equal to an annual rate of 30% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears.

The 2019 CQP Credit Facilities mature on May 29, 2024. The principal of any loans under the 2019 CQP Credit Facilities must be repaid in quarterly installments commencing on May 29, 2023 based on an amortization schedule. Any 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 2019 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 and one true-up per fiscal quarter as long as certain conditions are satisfied.

The 2019 CQP Credit Facilities are unconditionally guaranteed by each of our subsidiaries other than SPL, Sabine Pass LNG-LP, LLC and certain of our subsidiaries owning other development projects, as well as certain other specified subsidiaries and members of the foregoing entities.

Credit Facilities

Below is a summary of our credit facilities outstanding as of June 30, 2019 (in millions):



	SPL Working Capital Facility (1)		2019 CQP Credit Facilities
Original facility size	$	1,200	$	1,500
Less:
Outstanding balance	—		649
Commitments prepaid or terminated	—		—
Letters of credit issued	415		—
Available commitment	$	785	$	851

Interest rate on outstanding balance	LIBOR plus 1.75% or base rate plus 0.75%		(2)
Weighted average interest rate of outstanding balance	n/a		3.92%
Maturity date	December 31, 2020		May 29, 2024


(1)	The SPL Working Capital Facility was amended in May 2019 in connection with commercialization and financing of Train 6 of the Liquefaction Project. All terms of the SPL Working Capital Facility substantially remained unchanged.


(2)	LIBOR plus 1.50% or base rate plus 0.50%, with a 0.25% step-up beginning on May 29, 2022 for the CQP Term Facility. LIBOR plus 1.25% to 2.125% or base rate plus 0.25% to 1.125%, depending on our then-current rating for the CQP Revolving Facility.

Restrictive Debt Covenants

As of June 30, 2019, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Total interest cost	$	237		$	234		$	472		$	466
Capitalized interest	(7		)	(50		)	(55		)	(97		)
Total interest expense, net	$	230		$	184		$	417		$	369

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value Disclosures

The following table shows the carrying amount, which is net of unamortized premium, discount and debt issuance costs, and estimated fair value of our debt (in millions):



	June 30, 2019				December 31, 2018
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes (1)	$	15,288	$	16,755	$	15,275	$	15,672
2037 SPL Senior Notes (2)	791		912		791		817
Credit facilities (3)	641		641		—		—


(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, 2025 CQP Senior Notes and 2026 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 the SPL Working Capital Facility, 2016 CQP Credit Facilities and 2019 CQP Credit Facilities. 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—LEASES

Our leased assets consist primarily of tug vessels and land sites, all of which are classified as operating leases.

ASC 842 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. As our leases generally do not provide an implicit rate, in order to calculate the lease liability, we discounted our expected future lease payments using our relevant subsidiary’s incremental borrowing rate at the later of January 1, 2019 or the commencement date of the lease. The incremental borrowing rate is an estimate of the rate of interest that a given subsidiary would have to pay to borrow on a collateralized basis over a similar term to that of the lease term.

Many of our leases contain renewal options exercisable at our sole discretion. Options to renew a lease are included in the lease term and recognized as part of the right-of-use asset and lease liability only to the extent they are reasonably certain to be exercised, such as when necessary to satisfy obligations that existed at the execution of the lease or when the non-renewal would otherwise result in an economic penalty.

We have elected the practical expedient to omit leases with an initial term of 12 months or less (“short-term lease”) from recognition on the balance sheet. We recognize short-term lease payments on a straight-line basis over the lease term and variable payments under short-term leases in the period in which the obligation is incurred.

Certain of our leases contain non-lease components which are not separated from the lease components when calculating the right-of-use asset and lease liability per our use of the practical expedient to combine both components of an arrangement for all classes of leased assets.

Certain of our leases also contain variable payments, such as inflation, that are not included when calculating the right-of-use asset and lease liability unless the payments are in-substance fixed. We recognize lease expense for operating leases on a straight-line basis over the lease term.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):



	Consolidated Balance Sheet Location	June 30, 2019
Right-of-use assets—Operating	Operating lease assets, net	$	92
Current operating lease liabilities	Current operating lease liabilities	6
Non-current operating lease liabilities	Non-current operating lease liabilities	86

The following table shows the classification and location of our lease cost on our Consolidated Statements of Income (in millions):



	Consolidated Statement of Income Location (1)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost (1)	Operating costs and expenses (2)	$	4	$	6


(1)	Includes variable lease costs.


(2)	Presented in cost of sales, operating and maintenance expense or selling, general and administrative expense consistent with the nature of the asset under lease.

Future annual minimum lease payments for operating leases as of June 30, 2019 are as follows (in millions):



Years Ending December 31,	Operating Leases
2019	$	5
2020	10
2021	10
2022	10
2023	10
Thereafter	124
Total lease payments	169
Less: Interest	(77		)
Present value of lease liabilities	$	92

Future annual minimum lease payments for operating leases as of December 31, 2018, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows (in millions):



Years Ending December 31,	Operating Leases (1)
2019	$	10
2020	10
2021	10
2022	10
2023	10
Thereafter	124
Total	$	174


(1)	Includes certain lease option renewals that are reasonably assured and payments for certain non-lease components.

The following table shows the weighted-average remaining lease term (in years) and the weighted-average discount rate for our operating leases:



	June 30, 2019
Weighted-average remaining lease term (in years)	26.1
Weighted-average discount rate	4.8	%

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table includes other quantitative information for our operating leases (in millions):



	Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	5

NOTE 12—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three and six months ended June 30, 2019 and 2018 (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
LNG revenues	$	1,171	$	1,155	$	2,537	$	2,170
LNG revenues—affiliate	455		178		760		681
Regasification revenues	67		65		133		130
Other revenues	12		9		23		19
Total revenues from customers	1,705		1,407		3,453		3,000
Net derivative gains (1)	—		—		1		—
Total revenues	$	1,705	$	1,407	$	3,454	$	3,000


(1)	See Note 7—Derivative Instruments for additional information on our derivatives.

Deferred Revenue Reconciliation

The following table reflects the changes in our contract liabilities, which we classify as deferred revenue on our Consolidated Balance Sheets (in millions):



	Six Months Ended June 30, 2019
Deferred revenues, beginning of period	$	116
Cash received but not yet recognized	122
Revenue recognized from prior period deferral	(116		)
Deferred revenues, end of period	$	122

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied as of June 30, 2019 and December 31, 2018:



	June 30, 2019			December 31, 2018
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues (2)	$	56.3	10	$	53.6	10
Regasification revenues	2.5		5	2.6		6
Total revenues	$	58.8		$	56.2


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


(2)	Includes future consideration from agreement anticipated to be assigned to SPL from Cheniere Marketing.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

We have elected the following exemptions which omit certain potential future sources of revenue from the table above:


(1)	We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.

(2)

We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The table above excludes substantially all variable consideration under our SPAs and TUAs. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Approximately 53% and 55% of our LNG revenues during the three months ended June 30, 2019 and 2018, respectively, and approximately 55% of our LNG revenues during each of the six months ended June 30, 2019 and 2018, were related to variable consideration received from customers. During each of the three and six months ended June 30, 2019 and 2018, approximately 3% of our regasification revenues were related to variable consideration received from customers. All of our LNG revenues—affiliate were related to variable consideration received from customers during each of the three and six months ended June 30, 2019 and 2018.

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

NOTE 13—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the three and six months ended June 30, 2019 and 2018 (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
LNG revenues—affiliate
Cheniere Marketing Agreements	$	455	$	178	$	760	$	681

Operating and maintenance expense—affiliate
Services Agreements	37		30		66		56

General and administrative expense—affiliate
Services Agreements	27		17		48		35

As of June 30, 2019 and December 31, 2018, we had $166 million and $114 million, respectively, of accounts receivable—affiliate, under the agreements described below.

Terminal Use Agreement

SPL obtained approximately 2.0 Bcf/d of regasification capacity and other liquefaction support services under a TUA with SPLNG as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA with SPLNG. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million per year (the “TUA Fees”), continuing until at least May 2036.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Marketing Agreements

Cheniere Marketing SPA

Cheniere Marketing has an SPA (“Base 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.

In May 2019, SPL and Cheniere Marketing entered into an amendment to the Base SPA to remove certain conditions related to the sale of LNG from Trains 5 and 6 of the Liquefaction Project and provide that cargoes rejected by Cheniere Marketing under the Base SPA can be sold by SPL to Cheniere Marketing at a contract price equal to a portion of the estimated net profits from the sale of such cargo.

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. SPL executed a confirmation with Cheniere Marketing that obligated Cheniere Marketing in certain circumstances to buy LNG cargoes produced during the period while Bechtel Oil, Gas and Chemicals, Inc. had control of, and was commissioning, Train 5 of the Liquefaction Project.

Cheniere Marketing Letter Agreement

In May 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 20 cargoes totaling approximately 70 million MMBtu scheduled for delivery between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 per MMBtu.

Services Agreements

As of June 30, 2019 and December 31, 2018, we had $225 million and $228 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

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 Investments 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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

SPLNG O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPLNG O&M Agreement are required to be remitted to such subsidiary.

SPLNG MSA

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

SPL O&M Agreement

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

SPL MSA

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

CTPL O&M Agreement

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

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements

SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain annual property tax payments from SPLNG from 2007 through 2016. This initiative represented an aggregate commitment of $25 million over 10 years in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for SPLNG’s advance payments of annual ad valorem taxes, Cameron Parish will grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. 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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

to Cheniere Marketing equal to ad valorem tax levied on our LNG terminal in the year the Cameron Parish dollar-for-dollar credit is applied.

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. We had $4 million and $3 million in due to affiliates and $21 million and $22 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing as of June 30, 2019 and December 31, 2018, respectively.

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. The agreement also provides that Tug Services shall contingently pay the wholly owned subsidiary of Cheniere a portion of its future revenues. Accordingly, Tug Services distributed $2 million and $1 million during the three months ended June 30, 2019 and 2018, respectively, and $3 million and $2 million during the six months ended June 30, 2019 and 2018, respectively, to the wholly owned subsidiary of Cheniere, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ Equity.

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 six months ended June 30, 2019 and 2018.

State Tax Sharing Agreements

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

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

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

NOTE 14—NET INCOME PER COMMON UNIT

Net income per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income 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 Statements of Partners’ Equity. On July 26, 2019, we declared a $0.61 distribution per common unit and subordinated unit and the related distribution to our general partner and IDR holders to be paid on August 14, 2019 to unitholders of record as of August 6, 2019 for the period from April 1, 2019 to June 30, 2019.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table provides a reconciliation of net income and the allocation of net income to the common units, the subordinated units, the general partner units and IDRs for purposes of computing basic and diluted net income per unit (in millions, except per unit data).



				Limited Partner Units
	Total			Common Units			Subordinated Units			General Partner Units			IDR
Three Months Ended June 30, 2019
Net income	$	232
Declared distributions	316			211			83			7			15
Assumed allocation of undistributed net loss (1)	$	(84	)	(58		)	(24		)	(2		)	—
Assumed allocation of net income				$	153		$	59		$	5		$	15

Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	0.44		$	0.44

Three Months Ended June 30, 2018
Net income	$	281
Declared distributions	284			195			76			6			7
Assumed allocation of undistributed net loss (1)	$	(3	)	(2		)	(1		)	—			—
Assumed allocation of net income				$	193		$	75		$	6		$	7

Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	0.55		$	0.55

Six Months Ended June 30, 2019
Net income	$	617
Declared distributions	626			421			164			13			28
Assumed allocation of undistributed net loss (1)	$	(9	)	(6		)	(3		)	—			—
Assumed allocation of net income				$	415		$	161		$	13		$	28

Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	1.19		$	1.19


Six Months Ended June 30, 2018
Net income	$	616
Declared distributions	562			387			150			12			13
Assumed allocation of undistributed net income (1)	$	54		38			15			1			—
Assumed allocation of net income				$	425		$	165		$	13		$	13

Weighted average units outstanding				348.6			135.4
Basic and diluted net income per unit				$	1.22		$	1.22


(1)	Under our partnership agreement, the IDRs participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss).

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 15—CUSTOMER CONCENTRATION

The following table shows customers with revenues of 10% or greater of total revenues from external customers and customers with accounts receivable balances of 10% or greater of total accounts receivable from external customers:



	Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable from External Customers
	Three Months Ended June 30,		Six Months Ended June 30,		June 30,	December 31,
	2019	2018	2019	2018	2019	2018
Customer A	30%	27%	30%	29%	19%	35%
Customer B	20%	22%	19%	23%	26%	23%
Customer C	19%	22%	19%	24%	26%	30%
Customer D	23%	20%	23%	15%	25%	*

* Less than 10%

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Six Months Ended June 30,
	2019		2018
Cash paid during the period for interest, net of amounts capitalized	$	355	$	350

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $690 million and $255 million as of June 30, 2019 and 2018, respectively.

NOTE 17—SUPPLEMENTAL GUARANTOR INFORMATION

Our CQP Senior Notes are jointly and severally guaranteed by each of our subsidiaries other than SPL (the “Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”). These guarantees are full and unconditional, subject to certain customary release provisions including (1) the sale, exchange, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the CQP Indenture. See Note 10—Debt 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, 2018 for additional information regarding the CQP Senior Notes.

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

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)



Condensed Consolidating Balance Sheet
June 30, 2019
(in millions)

	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	1,009	$	7	$	—	$	—		$	1,016
Restricted cash	—		—		596		—			596
Accounts and other receivables	—		3		240		—			243
Accounts receivable—affiliate	1		31		166		(32		)	166
Advances to affiliate	—		134		206		(115		)	225
Inventory	—		13		91		—			104
Derivative assets	—		—		17		—			17
Other current assets	—		13		54		—			67
Other current assets—affiliate	—		1		21		(21		)	1
Total current assets	1,010		202		1,391		(168		)	2,435

Property, plant and equipment, net	79		2,457		13,722		(26		)	16,232
Operating lease assets, net	—		87		21		(16		)	92
Debt issuance costs, net	11		—		9		—			20
Non-current derivative assets	—		—		37		—			37
Investments in subsidiaries	2,947		508		—		(3,455		)	—
Other non-current assets, net	—		25		132		—			157
Total assets	$	4,047	$	3,279	$	15,312	$	(3,665	)	$	18,973

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	7	$	67	$	—		$	74
Accrued liabilities	37		28		1,011		—			1,076
Due to affiliates	1		145		44		(146		)	44
Deferred revenue	—		21		101		—			122
Deferred revenue—affiliate	—		21		—		(21		)	—
Current operating lease liabilities	—		6		—		—			6
Derivative liabilities	—		—		8		—			8
Other current liabilities—affiliate	—		1		—		(1		)	—
Total current liabilities	38		229		1,231		(168		)	1,330

Long-term debt, net	3,208		—		13,512		—			16,720
Non-current operating lease liabilities	—		81		5		—			86
Non-current derivative liabilities	—		—		12		—			12
Other non-current liabilities	—		1		2		—			3
Other non-current liabilities—affiliate	—		21		16		(16		)	21

Partners’ equity	801		2,947		534		(3,481		)	801
Total liabilities and partners’ equity	$	4,047	$	3,279	$	15,312	$	(3,665	)	$	18,973

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)



Condensed Consolidating Balance Sheet
December 31, 2018
(in millions)

	Parent Issuer		Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—		$	—
Restricted cash	779		6		756		—			1,541
Accounts and other receivables	1		1		346		—			348
Accounts receivable—affiliate	1		40		113		(40		)	114
Advances to affiliate	—		104		210		(86		)	228
Inventory	—		12		87		—			99
Derivative assets	—		—		6		—			6
Other current assets	—		2		18		—			20
Other current assets—affiliate	—		—		21		(21		)	—
Total current assets	781		165		1,557		(147		)	2,356

Property, plant and equipment, net	79		2,128		13,209		(26		)	15,390
Debt issuance costs, net	1		—		12		—			13
Non-current derivative assets	—		—		31		—			31
Investments in subsidiaries	2,544		440		—		(2,984		)	—
Other non-current assets, net	—		26		158		—			184
Total assets	$	3,405	$	2,759	$	14,967	$	(3,157	)	$	17,974

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	4	$	11	$	—		$	15
Accrued liabilities	39		14		768		—			821
Due to affiliates	—		127		48		(126		)	49
Deferred revenue	—		25		91		—			116
Deferred revenue—affiliate	—		22		—		(21		)	1
Derivative liabilities	—		—		66		—			66
Total current liabilities	39		192		984		(147		)	1,068

Long-term debt, net	2,566		—		13,500		—			16,066
Non-current derivative liabilities	—		—		14		—			14
Other non-current liabilities	—		1		3		—			4
Other non-current liabilities—affiliate	—		22		—		—			22

Partners’ equity	800		2,544		466		(3,010		)	800
Total liabilities and partners’ equity	$	3,405	$	2,759	$	14,967	$	(3,157	)	$	17,974

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)



Condensed Consolidating Statement of Income
Three Months Ended June 30, 2019
(in millions)

	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated

Revenues
LNG revenues	$	—		$	—		$	1,171		$	—		$	1,171
LNG revenues—affiliate	—			—			455			—			455
Regasification revenues	—			67			—			—			67
Regasification revenues—affiliate	—			65			—			(65		)	—
Other revenues	—			12			—			—			12
Other revenues—affiliate	—			65			—			(65		)	—
Total revenues	—			209			1,626			(130		)	1,705

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			880			—			880
Cost of sales—affiliate	—			—			9			(9		)	—
Operating and maintenance expense	—			24			138			—			162
Operating and maintenance expense—affiliate	—			38			115			(116		)	37
General and administrative expense	1			—			2			—			3
General and administrative expense—affiliate	3			8			21			(5		)	27
Depreciation and amortization expense	—			20			118			—			138
Impairment expense and loss on disposal of assets	—			—			3			—			3
Total operating costs and expenses	4			90			1,286			(130		)	1,250

Income (loss) from operations	(4		)	119			340			—			455

Other income (expense)
Interest expense, net of capitalized interest	(37		)	(2		)	(191		)	—			(230		)
Equity earnings of subsidiaries	268			150			—			(418		)	—
Other income	5			1			1			—			7
Total other income (expense)	236			149			(190		)	(418		)	(223		)

Net income	$	232		$	268		$	150		$	(418	)	$	232

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)



Condensed Consolidating Statement of Income
Three Months Ended June 30, 2018
(in millions)

	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated

Revenues
LNG revenues	$	—		$	—		$	1,155		$	—		$	1,155
LNG revenues—affiliate	—			—			178			—			178
Regasification revenues	—			65			—			—			65
Regasification revenues—affiliate	—			66			—			(66		)	—
Other revenues	—			9			—			—			9
Other revenues—affiliate	—			80			—			(80		)	—
Total revenues	—			220			1,333			(146		)	1,407

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			2			695			1			698
Cost of sales—affiliate	—			—			7			(7		)	—
Operating and maintenance expense	—			14			84			—			98
Operating and maintenance expense—affiliate	—			42			107			(119		)	30
Development expense	—			—			1			—			1
General and administrative expense	1			—			1			—			2
General and administrative expense—affiliate	3			7			12			(5		)	17
Depreciation and amortization expense	—			19			87			—			106
Total operating costs and expenses	4			84			994			(130		)	952

Income (loss) from operations	(4		)	136			339			(16		)	455

Other income (expense)
Interest expense, net of capitalized interest	(34		)	(2		)	(148		)	—			(184		)
Derivative gain, net	3			—			—			—			3
Equity earnings of subsidiaries	313			193			—			(506		)	—
Other income	3			2			2			—			7
Total other income (expense)	285			193			(146		)	(506		)	(174		)

Net income	$	281		$	329		$	193		$	(522	)	$	281

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)



Condensed Consolidating Statement of Income
Six Months Ended June 30, 2019
(in millions)

	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated

Revenues
LNG revenues	$	—		$	—		$	2,538		$	—		$	2,538
LNG revenues—affiliate	—			—			760			—			760
Regasification revenues	—			133			—			—			133
Regasification revenues—affiliate	—			131			—			(131		)	—
Other revenues	—			23			—			—			23
Other revenues—affiliate	—			124			—			(124		)	—
Total revenues	—			411			3,298			(255		)	3,454

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			—			1,759			—			1,759
Cost of sales—affiliate	—			—			18			(18		)	—
Operating and maintenance expense	—			52			248			—			300
Operating and maintenance expense—affiliate	—			71			222			(227		)	66
General and administrative expense	2			1			3			—			6
General and administrative expense—affiliate	6			14			36			(8		)	48
Depreciation and amortization expense	1			37			214			—			252
Impairment expense and loss on disposal of assets	—			—			5			—			5
Total operating costs and expenses	9			175			2,505			(253		)	2,436

Income (loss) from operations	(9		)	236			793			(2		)	1,018

Other income (expense)
Interest expense, net of capitalized interest	(73		)	(3		)	(341		)	—			(417		)
Equity earnings of subsidiaries	690			458			—			(1,148		)	—
Other income	9			1			6			—			16
Total other income (expense)	626			456			(335		)	(1,148		)	(401		)

Net income	$	617		$	692		$	458		$	(1,150	)	$	617

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)



Condensed Consolidating Statement of Income
Six Months Ended June 30, 2018
(in millions)

	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated

Revenues
LNG revenues	$	—		$	—		$	2,170		$	—		$	2,170
LNG revenues—affiliate	—			—			681			—			681
Regasification revenues	—			130			—			—			130
Regasification revenues—affiliate	—			130			—			(130		)	—
Other revenues	—			19			—			—			19
Other revenues—affiliate	—			135			—			(135		)	—
Total revenues	—			414			2,851			(265		)	3,000

Operating costs and expenses
Cost of sales (excluding depreciation and amortization expense shown separately below)	—			2			1,533			—			1,535
Cost of sales—affiliate	—			—			15			(15		)	—
Operating and maintenance expense	—			31			162			—			193
Operating and maintenance expense—affiliate	—			74			210			(228		)	56
Development expense	—			—			1			—			1
General and administrative expense	2			1			3			—			6
General and administrative expense—affiliate	6			11			24			(6		)	35
Depreciation and amortization expense	1			37			173			—			211
Total operating costs and expenses	9			156			2,121			(249		)	2,037

Income (loss) from operations	(9		)	258			730			(16		)	963

Other income (expense)
Interest expense, net of capitalized interest	(68		)	(2		)	(299		)	—			(369		)
Derivative gain, net	11			—			—			—			11
Equity earnings of subsidiaries	676			435			—			(1,111		)	—
Other income	6			1			4			—			11
Total other income (expense)	625			434			(295		)	(1,111		)	(347		)

Net income	$	616		$	692		$	435		$	(1,127	)	$	616

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)



Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2019
(in millions)

	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by operating activities	$	621		$	723		$	450		$	(1,154	)	$	640

Cash flows from investing activities
Property, plant and equipment, net	—			(21		)	(567		)	3			(585		)
Investments in subsidiaries	(908		)	(806		)	—			1,714			—
Return of capital	503			390			—			(893		)	—
Other	—			—			(1		)	—			(1		)
Net cash used in investing activities	(405		)	(437		)	(568		)	824			(586		)

Cash flows from financing activities
Proceeds from issuances of debt	649			—			—			—			649
Debt issuance and deferred financing costs	(19		)	—			—						(19		)
Distributions to parent	—			(1,196		)	(848		)	2,044			—
Contributions from parent	—			908			806			(1,714		)	—
Distributions to owners	(616		)	—			—			—			(616		)
Other	—			3			—			—			3
Net cash provided by (used in) financing activities	14			(285		)	(42		)	330			17

Net increase (decrease) in cash, cash equivalents and restricted cash	230			1			(160		)	—			71
Cash, cash equivalents and restricted cash—beginning of period	779			6			756			—			1,541
Cash, cash equivalents and restricted cash—end of period	$	1,009		$	7		$	596		$	—		$	1,612

Balances per Condensed Consolidating Balance Sheet:



	June 30, 2019
	Parent Issuer		Guarantors		Non-Guarantors		Eliminations		Consolidated
Cash and cash equivalents	$	1,009	$	7	$	—	$	—	$	1,016
Restricted cash	—		—		596		—		596
Total cash, cash equivalents and restricted cash	$	1,009	$	7	$	596	$	—	$	1,612

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)



Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2018
(in millions)

	Parent Issuer			Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash flows provided by (used in) operating activities	$	(7	)	$	266		$	604		$	(58	)	$	805

Cash flows from investing activities
Property, plant and equipment, net	—			(18		)	(327		)	—			(345		)
Investments in subsidiaries	(112		)	(25		)	—			137			—
Return of capital	—			—			—			—			—
Distributions received from affiliates, net	277			—			—			(277		)	—
Net cash provided by (used in) investing activities	165			(43		)	(327		)	(140		)	(345		)

Cash flows from financing activities
Debt issuance and deferred financing costs	(1		)	—			—			—			(1		)
Distributions to parent	—			(335		)	—			335			—
Contributions from parent	—			112			25			(137		)	—
Distributions to owners	(527		)	—			—			—			(527		)
Net cash provided by (used in) financing activities	(528		)	(223		)	25			198			(528		)

Net increase (decrease) in cash, cash equivalents and restricted cash	(370		)	—			302			—			(68		)
Cash, cash equivalents and restricted cash—beginning of period	1,033			12			544			—			1,589
Cash, cash equivalents and restricted cash—end of period	$	663		$	12		$	846		$	—		$	1,521


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

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical 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 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,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” 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, 2018. 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 provide clean, secure and affordable energy to the world, while responsibly delivering a reliable, competitive and integrated source of LNG, in a safe and rewarding work environment. The liquefaction of natural gas into LNG allows it to be shipped economically from the United States where natural gas is abundant and inexpensive to produce to our international customers in areas where natural gas demand and infrastructure exist. Through our wholly owned subsidiary, SPL, we are in various stages of constructing and operating six 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. Trains 1 through 5 are operational and Train 6 is under construction. Each Train is expected to have a nominal production capacity, which is prior to adjusting for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities, of approximately 4.5 mtpa of LNG per Train. Through our wholly owned subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks with aggregate capacity of approximately 16.9 Bcfe, two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. We also own a 94-mile pipeline that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines through our wholly owned subsidiary, CTPL.

Overview of Significant Events

Our significant accomplishments since January 1, 2019 and through the filing date of this Form 10-Q include the following:

Strategic


•	In May 2019, the board of directors of our general partner made a positive final investment decision with respect to Train 6 of the Liquefaction Project and issued a full notice to proceed with construction to Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) in June 2019.

Operational


•	As of July 31, 2019, approximately 725 cumulative LNG cargoes have been produced, loaded and exported from the Liquefaction Project.


•	In March 2019, SPL achieved substantial completion of Train 5 of the Liquefaction Project and commenced operating activities.

Financial

•

In May 2019, we entered into five-year, $1.5 billion credit facilities (the “2019 CQP Credit Facilities”), which consist of a $750 million delayed draw term loan (“CQP Term Facility”) and a $750 million revolving credit facility (“CQP Revolving Facility”), to fund a portion of the development and construction of Train 6, a third LNG berth and supporting infrastructure at the Liquefaction Project.


•	In March 2019, the date of first commercial delivery was reached under the 20-year SPA with BG Gulf Coast LNG, LLC relating to Train 4 of the Liquefaction Project.

Liquidity and Capital Resources

The following table provides a summary of our liquidity position at June 30, 2019 and December 31, 2018 (in millions):



	June 30,		December 31,
	2019		2018
Cash and cash equivalents	$	1,016	$	—
Restricted cash designated for the following purposes:
Liquefaction Project	596		756
Cash held by us and our guarantor subsidiaries	—		785
Available commitments under the following credit facilities:
$1.2 billion SPL Working Capital Facility (“SPL Working Capital Facility”)	785		775
$1.5 billion 2019 CQP Credit Facilities	851		—
$2.8 billion Credit Facilities (“2016 CQP Credit Facilities”)	—		115

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, 2018.

CQP Senior Notes

The $1.5 billion of 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) and $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”) (collectively, the “CQP Senior Notes”) are jointly and severally guaranteed by each of our subsidiaries other than SPL (the “Guarantors”) and, subject to certain conditions governing its guarantee, Sabine Pass LP. The CQP Senior Notes are governed by the same base indenture (the “CQP Base Indenture”). The 2025 CQP Senior Notes are further governed by the First Supplemental Indenture (together with the CQP Base Indenture, the “2025 CQP Notes Indenture”) and the 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture (together with the CQP Base Indenture, the “2026 CQP Notes Indenture”). The 2025 CQP Notes Indenture and the 2026 CQP Notes Indenture contain customary terms and events of default and certain covenants that, among other things, limit our ability and the ability of the Guarantors to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

At any time prior to October 1, 2020 for the 2025 CQP Senior Notes and October 1, 2021 for the 2026 CQP Senior Notes, we may redeem all or a part of the applicable CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the CQP Senior Notes redeemed, plus the “applicable premium” set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2020 for the 2025 CQP Senior Notes and October 1, 2021 for the 2026 CQP Senior Notes, we may redeem up to 35% of the aggregate principal amount of the 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 and 105.625% of the aggregate principal amount of the 2026 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 for the 2025 CQP Senior Notes and October 1, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes, redeem the CQP Senior Notes, in whole or in part, at the redemption prices set forth in the respective indentures governing the CQP Senior Notes.

The 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. After applying the proceeds from the 2026 CQP Senior Notes, the CQP Senior Notes became unsecured. In the event that the aggregate amount of our secured indebtedness and the

secured indebtedness of the Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets, the CQP Senior Notes will be secured to the same extent as such obligations under the 2019 CQP Credit Facilities. The obligations under the 2019 CQP Credit Facilities are secured on a first-priority basis (subject to permitted encumbrances) with liens on substantially all the existing and future tangible and intangible assets and our rights and the rights of the Guarantors and equity interests in the Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities). The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of other senior secured obligations, which include the 2019 CQP Credit Facilities obligations and any future additional senior secured debt obligations.

2016 CQP Credit Facilities

In May 2019, the remaining commitments under the 2016 CQP Credit Facilities were terminated.

2019 CQP Credit Facilities

In May 2019, we entered into the 2019 CQP Credit Facilities, which consist of a $750 million term loan (“CQP Term Facility”) and a $750 million revolving credit facility (“CQP Revolving Facility”). Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the Liquefaction Project and subject to a sublimit, for general corporate purposes. The CQP Revolving Facility is also available for the issuance of letters of credit.

We pay a commitment fee equal to an annual rate of 30% of the margin for LIBOR loans multiplied by the average daily amount of the undrawn commitment, payable quarterly in arrears.

Sabine Pass LNG Terminal

Liquefaction Facilities

We are in various stages of 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. We have achieved substantial completion of Trains 1, 2, 3, 4 and 5 of the Liquefaction Project and commenced operating activities in May 2016, September 2016, March 2017, October 2017 and March 2019, respectively. The following table summarizes the status of Train 6 of the Liquefaction Project as of June 30, 2019:



		Train 6
Overall project completion percentage		32.4%
Completion percentage of:
Engineering		74.1%
Procurement		48.2%
Subcontract work		30.7%
Construction		2.1%
Date of expected substantial completion		1H 2023

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 2018, the DOE issued orders 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 January 2018, in an aggregate amount up to the equivalent of 600 Bcf of natural gas (however, exports under this order, when combined with exports under the orders above, may not exceed 1,509 Bcf/yr).

Customers

SPL has entered into fixed price SPAs generally with terms of at least 20 years (plus extension rights) with eight third parties for Trains 1 through 6 of the Liquefaction Project, including an agreement anticipated to be assigned from Cheniere Marketing, to make available an aggregate amount of LNG that is between approximately 75% to 85% of the expected aggregate adjusted nominal production capacity from these Trains. 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 per MMBtu of LNG equal to approximately 115% of Henry Hub. 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. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation related to, and operating and maintenance costs to produce, the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.3 billion for Trains 1 through 4 and increasing to $2.9 billion upon the date of first commercial delivery of Train 5, with the applicable fixed fees starting from the date of first commercial delivery from the applicable Train, as specified in each SPA.

In addition, Cheniere Marketing has agreements with SPL to purchase up to 20 cargoes totaling approximately 70 million MMBtu scheduled for delivery between May 3 and December 31, 2019 at a price of 115% of Henry Hub plus $2.00 per MMBtu and, 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 variability in natural gas needs for the Liquefaction Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of June 30, 2019, SPL had secured up to approximately 3,437 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 for the engineering, procurement and construction of Trains 1 through 6 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 price of the EPC contract for Train 6 of the Liquefaction Project is approximately $2.5 billion, including estimated costs for an optional third marine berth.

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, prior to inflation adjustments, 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, prior to inflation adjustments, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 5 of the Liquefaction Project, SPL gained access to substantially all 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 Train 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 months ended June 30, 2019 and 2018, SPL recorded $32 million and $7.5 million, respectively, and during the six months ended June 30, 2019 and 2018, SPL recorded $40 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 the Liquefaction Project will be financed through project debt and borrowings, cash flows under the SPAs and equity contributions from us. We believe that with the net

proceeds of borrowings, available commitments under the SPL Working Capital Facility, 2019 CQP Credit Facilities and cash flows from operations, we will have adequate financial resources available to meet our currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the Liquefaction Project. 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, 3, 4 and 5 subsequently achieved substantial completion in September 2016, March 2017, October 2017 and March 2019, respectively. We realized offsets to LNG terminal costs of $48 million in the six months ended June 30, 2019, 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 Train 5 of the Liquefaction Project during the testing phase for its construction. We did not realize any offsets to LNG terminal costs in the three months ended June 30, 2019 and the three and six months ended June 30, 2018. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.

The following table provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG Terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in Sources and Uses of Cash), at June 30, 2019 and December 31, 2018 (in millions):



	June 30,		December 31,
	2019		2018
Senior notes (1)	$	16,250	$	16,250
Credit facilities outstanding balance (2)	649		—
Letters of credit issued (3)	415		425
Available commitments under credit facilities (3)	1,636		775
Total capital resources from borrowings and available commitments	$	18,950	$	17,450

(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”), 4.200% Senior Secured Notes due 2028 (the “2028 SPL Senior Notes”) and 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) (collectively, the “SPL Senior Notes”) and our 2025 CQP Senior Notes and 2026 CQP Senior Notes.


(2)	Includes outstanding balances under the SPL Working Capital Facility and 2019 CQP Credit Facilities, inclusive of any portion of the 2019 CQP Credit Facilities that may be used for general corporate purposes.


(3)	Includes SPL Working Capital Facility and 2019 CQP Credit Facilities. Balance at December 31, 2018 did not include the letters of credit issued or available commitments under the terminated 2016 CQP Credit Facilities, which were not specifically for the Sabine Pass LNG Terminal.

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, 2018.

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. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025.

SPL Working Capital Facility

In September 2015, SPL entered into the SPL Working Capital Facility, which is intended to be used for loans to SPL (“Working Capital Loans”), the issuance of letters of credit on behalf of SPL, as well as for swing line loans to SPL (“Swing Line Loans”), primarily for certain working capital requirements related to developing and placing into operation the Liquefaction Project. SPL may, from time to time, request increases in the commitments under the SPL Working Capital Facility of up to $760 million and, upon the completion of the debt financing of Train 6 of the Liquefaction Project, request an incremental increase in commitments of up to an additional $390 million. As of June 30, 2019 and December 31, 2018, SPL had $785 million and $775 million of available commitments and $415 million and $425 million aggregate amount of issued letters of credit under the SPL Working Capital Facility, respectively. SPL did not have any amounts outstanding under the SPL Working Capital Facility as of both June 30, 2019 and December 31, 2018.

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.

Restrictive Debt Covenants

As of June 30, 2019, we and SPL were in compliance with all covenants related to our respective debt agreements.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the six months ended June 30, 2019 and 2018 (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.



	Six Months Ended June 30,
	2019			2018
Operating cash flows	$	640		$	805
Investing cash flows	(586		)	(345		)
Financing cash flows	17			(528		)

Net increase (decrease) in cash, cash equivalents and restricted cash	71			(68		)
Cash, cash equivalents and restricted cash—beginning of period	1,541			1,589
Cash, cash equivalents and restricted cash—end of period	$	1,612		$	1,521

Operating Cash Flows

Our operating cash net inflows during the six months ended June 30, 2019 and 2018 were $640 million and $805 million, respectively. The $165 million decrease in operating cash inflows in 2019 compared to 2018 was primarily related to increased operating costs and expenses, partially offset by increased cash receipts from the sale of LNG cargoes, as a result of an additional Train that was operating at the Liquefaction Project in 2019. In addition to Trains 1 through 4 of the Liquefaction Project that were operational during both the six months ended June 30, 2019 and 2018, Train 5 was operational for approximately four months during the six months ended June 30, 2019.

Investing Cash Flows

Investing cash net outflows during the six months ended June 30, 2019 and 2018 were $586 million and $345 million, respectively, and were primarily used to fund the construction costs for the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion.

Financing Cash Flows

Financing cash net inflows of $17 million during the six months ended June 30, 2019 was primarily a result of $649 million of borrowings under the 2019 CQP Credit Facilities partially offset by $616 million of distributions to unitholders. Financing cash net outflows of $528 million during the six months ended June 30, 2018 was primarily a result of $527 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. The following provides a summary of distributions paid by us during the six months ended June 30, 2019 and 2018:



						Total Distribution (in millions)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Distribution Per Subordinated Unit		Common Units		Subordinated Units		General Partner Units		Incentive Distribution Rights
May 15, 2019	January 1 - March 31, 2019	$	0.60	$	0.60	$	209	$	81	$	6	$	13
February 14, 2019	October 1 - December 31, 2018	0.59		0.59		206		80		6		12

May 15, 2018	January 1 - March 31, 2018	0.55		0.55		192		74		5		6
February 14, 2018	October 1 - December 31, 2017	0.50		0.50		174		68		5		1

On July 26, 2019, we declared a $0.61 distribution per common unit and subordinated unit and the related distribution to our general partner and incentive distribution right holders to be paid on August 14, 2019 to unitholders of record as of August 6, 2019 for the period from April 1, 2019 to June 30, 2019.

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. Such available cash could be generated through new business development or fees received from Cheniere Marketing under an amended and restated variable capacity rights agreement 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. The ending of the subordination period and conversion of the subordinated units into common units will depend upon future business development.

Results of Operations

Our consolidated net income was $232 million, or $0.44 per common unit (basic and diluted), in the three months ended June 30, 2019, compared to $281 million, or $0.55 per common unit (basic and diluted), in the three months ended June 30, 2018.

This $49 million decrease in net income was primarily a result of increased interest expense, net of capitalized interest, due to a decrease in the portion of total interest costs that could be capitalized as Train 5 of the Liquefaction Project completed construction in March 2019.

Our consolidated net income was $617 million, or $1.19 per common unit (basic and diluted), in the six months ended June 30, 2019, compared to $616 million, or $1.22 per common unit (basic and diluted), in the six months ended June 30, 2018. Net income was comparable between the periods primarily due to increased income from operations from an additional Train in operation in the six months ended June 30, 2019, partially offset by increased interest expense, net of capitalized interest, due to a decrease in the portion of total interest costs that could be capitalized for Train 5 of the Liquefaction Project.

We enter into derivative instruments to manage our exposure to changing interest rates and commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions economically hedged receive accrual accounting treatment, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, use of derivative instruments may increase the volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors.

Revenues



	Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except volumes)	2019		2018		Change		2019		2018		Change
LNG revenues	$	1,171	$	1,155	$	16	$	2,538	$	2,170	$	368
LNG revenues—affiliate	455		178		277		760		681		79
Regasification revenues	67		65		2		133		130		3
Other revenues	12		9		3		23		19		4
Total revenues	$	1,705	$	1,407	$	298	$	3,454	$	3,000	$	454

LNG volumes recognized as revenues (in TBtu)	305		222		83		568		463		105

We begin recognizing LNG revenues from the Liquefaction Project following the substantial completion and the commencement of operating activities of the respective Trains. In addition to Trains 1 through 4 of the Liquefaction Project that were operational during both the six months ended June 30, 2019 and 2018, Train 5 of the Liquefaction Project was operational for approximately four months during the six months ended June 30, 2019. The increase in revenues for the three and six months ended June 30, 2019 from the comparable periods in 2018 was primarily attributable to the increased volumes of LNG sold following the achievement of substantial completion of Train 5 of the Liquefaction Project, partially offset by decreased revenues per MMBtu. We expect our LNG revenues to increase in the future upon Train 6 of the Liquefaction Project becoming operational.

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 $48 million corresponding to 10 TBtu of LNG in the six months ended June 30, 2019 that related to the sale of commissioning cargoes. We did not realize any offsets to LNG terminal costs in the three months ended June 30, 2019 and the three and six months ended June 30, 2018.

Also included in LNG revenues are gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery and the sale of natural gas procured for the liquefaction process. During the three months ended June 30, 2019 and 2018, we realized gains of $34 million and $37 million, respectively, from these transactions and other revenues. During the six months ended June 30, 2019 and 2018, we realized gains of $79 million and $60 million, respectively, from these transactions and other revenues.

Operating costs and expenses



	Three Months Ended June 30,							Six Months Ended June 30,
(in millions)	2019		2018		Change			2019		2018		Change
Cost of sales	$	880	$	698	$	182		$	1,759	$	1,535	$	224
Operating and maintenance expense	162		98		64			300		193		107
Operating and maintenance expense—affiliate	37		30		7			66		56		10
Development expense	—		1		(1		)	—		1		(1		)
General and administrative expense	3		2		1			6		6		—
General and administrative expense—affiliate	27		17		10			48		35		13
Depreciation and amortization expense	138		106		32			252		211		41
Impairment expense and loss on disposal of assets	3		—		3			5		—		5
Total operating costs and expenses	$	1,250	$	952	$	298		$	2,436	$	2,037	$	399

Our total operating costs and expenses increased during the three and six months ended June 30, 2019 from the three and six months ended June 30, 2018, primarily as a result of an additional Train that was operating between each of the periods and increased third-party service and maintenance costs from additional maintenance and related activities at the Liquefaction Project.

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. Cost of sales increased during the three and six months ended June 30, 2019 from the three and six months ended June 30, 2018 due to increased volumes of natural gas feedstock for our LNG sales as a result of substantial completion of Train 5 of the Liquefaction Project, partially offset by decreased pricing of natural gas feedstock between the quarterly periods. Partially offsetting the increase in cost of natural gas feedstock was an increase in fair value of the derivatives associated with hedges to secure natural gas feedstock for the Liquefaction Project, due to a favorable shift in the long-term forward prices. Cost of sales also includes variable transportation and storage costs and other costs to convert natural gas into LNG.

Operating and maintenance expense primarily includes costs associated with operating and maintaining the Liquefaction Project. The increase in operating and maintenance expense (including affiliates) during the three and six months ended June 30, 2019 from the three and six months ended June 30, 2018 was primarily related to: (1) increased cost of maintenance and related activities at the Liquefaction Project, (2) increased TUA reservation charges paid to Total from payments under the partial TUA assignment agreement and (3) increased natural gas transportation and storage capacity demand charges paid to third parties from operating Train 5 of the Liquefaction Project following its substantial completion. Operating and maintenance expense (including affiliates) also includes payroll and benefit costs of operations personnel, insurance and regulatory costs and other operating costs.

Depreciation and amortization expense increased during the three and six months ended June 30, 2019 from the three and six months ended June 30, 2018 as a result of Train 5 of the Liquefaction Project becoming operational, as the related assets began depreciating upon reaching substantial completion.

Other expense (income)



	Three Months Ended June 30,								Six Months Ended June 30,
(in millions)	2019			2018			Change		2019			2018			Change
Interest expense, net of capitalized interest	$	230		$	184		$	46	$	417		$	369		$	48
Derivative gain, net	—			(3		)	3		—			(11		)	11
Other income	(7		)	(7		)	—		(16		)	(11		)	(5		)
Total other expense	$	223		$	174		$	49	$	401		$	347		$	54

Interest expense, net of capitalized interest, increased during the three and six months ended June 30, 2019 compared to the three and six months ended June 30, 2018, primarily as a result of a decrease in the portion of total interest costs that could be capitalized as an additional Train of the Liquefaction Project completed construction between the periods. For the three months ended June 30, 2019 and 2018, we incurred $237 million and $234 million of total interest cost, respectively, of which we capitalized $7 million and $50 million, respectively, primarily for the construction of the Liquefaction Project. For the six months ended June 30, 2019 and 2018, we incurred $472 million and $466 million of total interest cost, respectively, of which we capitalized $55 million and $97 million, respectively, primarily for the construction of the Liquefaction Project.

Derivative gain, net decreased during the three and six months ended June 30, 2019 compared to the three and six months ended June 30, 2018, as we no longer held interest rate swaps used to hedge a portion of the variable interest payments on our credit facilities, as they were terminated in October 2018.

Off-Balance Sheet Arrangements

As of June 30, 2019, 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, 2018.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see Note 1—Nature of Operations and Basis of Presentation 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 for the commissioning and operation of the Liquefaction Project (“Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):



	June 30, 2019				December 31, 2018
	Fair Value		Change in Fair Value		Fair Value			Change in Fair Value
Liquefaction Supply Derivatives	$	34	$	1	$	(43	)	$	7

ITEM 4. CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our 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. Other than as discussed below, 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, 2018.

In February 2018, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a Corrective Action Order (the “CAO”) to SPL in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG terminal. These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to SPL returning the tanks to service. We continue to coordinate with PHMSA and FERC to address the matters relating to the February 2018 leak, including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and remediation will have a material adverse impact on our financial results or operations.


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, 2018.


ITEM 6.	EXHIBITS



Exhibit No.		Description
10.1		Credit and Guaranty Agreement, dated May 29, 2019, among the Partnership, as Borrower, certain subsidiaries of the Partnership, as Subsidiary Guarantors, the lenders from time to time party thereto, Natixis, Société Générale, The Bank of Nova Scotia, Wells Fargo Bank, as Issuing Banks, MUFG Bank, LTD as Administrative Agent and Sole Coordinating Lead Arranger, and certain arrangers and other participants (Incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 001-33366), filed on June 3, 2019)
10.2*		Amended and Restated Senior Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement, dated September 4, 2015, as amended by (a) Third Omnibus Amendment, dated as of May 23, 2018; (b) Fourth Omnibus Amendment, dated as of September 17, 2018; and (c) Fifth Omnibus Amendment, Consent and Waiver, dated as of May 29, 2019, among SPL, as Borrower, The Bank of Nova Scotia, as Senior Issuing Bank and Senior Facility Agent, ABN Amro Capital USA LLC, HSBC Bank USA, National Association and ING Capital LLC, as Senior Issuing Banks, Société Générale, as Swing Line Lender and Common Security Trustee, and the senior lenders party thereto from time to time
10.3*		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated December 20, 2012, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: the Change Order CO-00045 Letter of Credit Reduction and Extension, dated June 7, 2019
10.4*		Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: the Change Order CO-00001 Modifications to Insurance Language Change Order, dated June 3, 2019
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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*		Inline XBRL Taxonomy Extension Schema Document
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		Inline XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document



*	Filed herewith.
**	Furnished herewith.

SIGNATURES

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



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

Date:	August 7, 2019	By:	/s/ Michael J. Wortley
			Michael J. Wortley
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)

Date:	August 7, 2019	By:	/s/ Leonard E. Travis
			Leonard E. Travis
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)