10-Q

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 March 31, 2021

or

☐    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 April 30, 2021, the registrant had 484,021,123 common units outstanding.

CHENIERE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

	Definitions	1
Part I. Financial Information
Item 1.	Consolidated Financial Statements	3
	Consolidated Statements of Income	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Partners’ Equity	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7
	Note 1—Nature of Operations and Basis of Presentation	7
	Note 2—Unitholders’ Equity	7
	Note 3—Restricted Cash	8
	Note 4—Accounts and Other Receivables	8
	Note 5—Inventory	8
	Note 6—Property, Plant and Equipment	8
	Note 7—Derivative Instruments	9
	Note 8—Other Non-Current Assets	12
	Note 9—Accrued Liabilities	12
	Note 10—Debt	12
	Note 11—Revenues from Contracts with Customers	14
	Note 12—Related Party Transactions	16
	Note 13—Net Income per Common Unit	21
	Note 14—Customer Concentration	22
	Note 15—Supplemental Cash Flow Information	22
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 4.	Controls and Procedures	36
Part II. Other Information
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 6.	Exhibits	38
	Signatures	39

i

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

1

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of March 31, 2021, 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. 

2

PART I.     FINANCIAL INFORMATION

ITEM 1.    CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per unit data)

(unaudited)

	Three Months Ended March 31,
	2021		2020
Revenues
LNG revenues	$	1,669	$	1,449
LNG revenues—affiliate	214		188
Regasification revenues	67		67
Other revenues	13		14
Total revenues	1,963		1,718
Operating costs and expenses
Cost of sales (excluding items shown separately below)	948		699
Cost of sales—affiliate	42		—
Operating and maintenance expense	149		152
Operating and maintenance expense—affiliate	34		33
Operating and maintenance expense—related party	10		—
General and administrative expense	2		2
General and administrative expense—affiliate	21		25
Depreciation and amortization expense	139		138
Impairment expense and loss on disposal of assets	—		5
Total operating costs and expenses	1,345		1,054
Income from operations	618		664
Other income (expense)
Interest expense, net of capitalized interest	(217)		(234)
Loss on modification or extinguishment of debt	(54)		(1)
Other income, net	—		6
Total other expense	(271)		(229)
Net income	$	347	$	435
Basic and diluted net income per common unit	$	0.64	$	0.84
Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation	484.0		348.6

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

3

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

	March 31,		December 31,
	2021		2020
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	1,219	$	1,210
Restricted cash	123		97
Accounts and other receivables, net	373		318
Accounts receivable—affiliate	98		184
Advances to affiliate	127		144
Inventory	103		107
Derivative assets	16		14
Other current assets	59		61
Other current assets—affiliate	2		—
Total current assets	2,120		2,135
Property, plant and equipment, net	16,734		16,723
Operating lease assets, net	97		99
Debt issuance costs, net	16		17
Non-current derivative assets	9		11
Other non-current assets, net	177		160
Total assets	$	19,153	$	19,145
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	11	$	12
Accrued liabilities	704		658
Accrued liabilities—related party	3		4
Current debt	850		—
Due to affiliates	31		53
Deferred revenue	101		137
Deferred revenue—affiliate	5		1
Current operating lease liabilities	8		7
Derivative liabilities	26		11
Total current liabilities	1,739		883
Long-term debt, net	16,732		17,580
Non-current operating lease liabilities	89		90
Non-current derivative liabilities	42		35
Other non-current liabilities	—		1
Other non-current liabilities—affiliate	16		17
Partners’ equity
Common unitholders’ interest (484.0 million units issued and outstanding at both March 31, 2021 and December 31, 2020)	738		714
General partner’s interest (2% interest with 9.9 million units issued and outstanding at March 31, 2021 and December 31, 2020)	(203)		(175)
Total partners’ equity	535		539
Total liabilities and partners’ equity	$	19,153	$	19,145

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

4

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(in millions)

(unaudited)

Three Months Ended March 31, 2021
	Common Unitholders’ Interest			Subordinated Unitholder’s Interest			General Partner’s Interest			Total Partners’ Equity
	Units	Amount		Units	Amount		Units	Amount
Balance at December 31, 2020	484.0	$	714	—	$	—	9.9	$	(175)	$	539
Net income	—	340		—	—		—	7		347
Distributions
Common units, $0.655/unit	—	(316)		—	—		—	—		(316)
General partner units	—	—		—	—		—	(35)		(35)
Balance at March 31, 2021	484.0	$	738	—	$	—	9.9	$	(203)	$	535

Three Months Ended March 31, 2020
	Common Unitholders’ Interest			Subordinated Unitholder’s Interest			General Partner’s Interest			Total Partners’ Equity
	Units	Amount		Units	Amount		Units	Amount
Balance at December 31, 2019	348.6	$	1,792	135.4	$	(996)	9.9	$	(81)	$	715
Net income	—	307		—	119		—	9		435
Distributions
Common units, $0.63/unit	—	(220)		—	—		—	—		(220)
Subordinated units, $0.63/unit	—	—		—	(85)		—	—		(85)
General partner units	—	—		—	—		—	(25)		(25)
Balance at March 31, 2020	348.6	$	1,879	135.4	$	(962)	9.9	$	(97)	$	820

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

5

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Three Months Ended March 31,
	2021		2020
Cash flows from operating activities
Net income	$	347	$	435
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	139		138
Amortization of debt issuance costs, premium and discount	8		9
Loss on modification or extinguishment of debt	54		1
Total losses (gains) on derivatives, net	2		(21)
Net cash provided by settlement of derivative instruments	20		5
Impairment expense and loss on disposal of assets	—		5
Other	3		3
Changes in operating assets and liabilities:
Accounts and other receivables, net	(56)		38
Accounts receivable—affiliate	86		67
Advances to affiliate	18		17
Inventory	4		19
Accounts payable and accrued liabilities	24		(100)
Accrued liabilities—related party	(1)		—
Due to affiliates	(20)		(13)
Deferred revenue	(36)		(61)
Other, net	(6)		(3)
Other, net—affiliate	2		(4)
Net cash provided by operating activities	588		535
Cash flows from investing activities
Property, plant and equipment, net	(146)		(317)
Net cash used in investing activities	(146)		(317)
Cash flows from financing activities
Proceeds from issuances of debt	1,500		—
Repayments of debt	(1,500)		—
Debt issuance and other financing costs	(19)		(7)
Debt extinguishment costs	(40)		—
Distributions to owners	(351)		(330)
Other	3		—
Net cash used in financing activities	(407)		(337)
Net increase (decrease) in cash, cash equivalents and restricted cash	35		(119)
Cash, cash equivalents and restricted cash—beginning of period	1,307		1,962
Cash, cash equivalents and restricted cash—end of period	$	1,342	$	1,843

Balances per Consolidated Balance Sheets:

	March 31,
	2021
Cash and cash equivalents	$	1,219
Restricted cash	123
Total cash, cash equivalents and restricted cash	$	1,342

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

6

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Through our subsidiary, SPL, we are currently operating five natural gas liquefaction Trains and are constructing one additional Train that is expected to be substantially completed in the first half of 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal. Through our subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks, two marine berths and vaporizers and an additional marine berth that is under construction. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”).

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 fiscal year ended December 31, 2020.

Results of operations for the three months ended March 31, 2021 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2021.

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

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

NOTE 2—UNITHOLDERS’ EQUITY

The common 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 accumulated operating surplus as defined in the partnership agreement.

Although common unitholders are not obligated to fund losses of the Partnership, its capital account, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continues 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 as additional target levels are met, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.

As of March 31, 2021, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.4% by BX CQP Target Holdco L.L.C. (“BX CQP Target Holdco”) and other affiliates of The Blackstone Group

7

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) and 8.0% by the public. All of our 2% general partner interest was held by Cheniere. BX CQP Target Holdco’s equity interests are 50.01% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone and 49.99% owned by BIF IV Cypress Aggregator (Delaware) LLC, an affiliate of Brookfield. The ownership of BX CQP Target Holdco, Blackstone and Brookfield are based on their most recent filings with the SEC.

NOTE 3—RESTRICTED CASH

Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of March 31, 2021 and December 31, 2020, we had $123 million and $97 million of restricted cash, respectively.

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

NOTE 4—ACCOUNTS AND OTHER RECEIVABLES

As of March 31, 2021 and December 31, 2020, accounts and other receivables, net consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
SPL trade receivable	$	349	$	300
Other accounts receivable	24		18
Total accounts and other receivables, net	$	373	$	318

NOTE 5—INVENTORY

As of March 31, 2021 and December 31, 2020, inventory consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Materials	$	82	$	81
LNG	11		8
Natural gas	9		17
Other	1		1
Total inventory	$	103	$	107

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

As of March 31, 2021 and December 31, 2020, property, plant and equipment, net consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	16,909	$	16,908
LNG terminal construction-in-process	2,300		2,154
Accumulated depreciation	(2,481)		(2,344)
Total LNG terminal costs, net	16,728		16,718
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(24)		(24)
Total fixed assets, net	6		5
Property, plant and equipment, net	$	16,734	$	16,723

8

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows depreciation expense during the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
Depreciation expense	$	138	$	137

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”).

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 or fair value 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 March 31, 2021 and December 31, 2020, 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
	March 31, 2021								December 31, 2020
	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)	$	(4)	$	(3)	$	(36)	$	(43)	$	1	$	(1)	$	(21)	$	(21)

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 events deriving fair value, 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 March 31, 2021 and December 31, 2020, 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 incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.

9

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2021:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$(36)	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.350) - $0.168 / $(0.001)

(1)    Unobservable inputs were weighted by the relative fair value of the instruments.

Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
Balance, beginning of period	$	(21)	$	24
Realized and mark-to-market gains (losses):
Included in cost of sales	(12)		25
Purchases and settlements:
Purchases	1		1
Settlements	(4)		(3)
Transfers into Level 3, net (1)	—		2
Balance, end of period	$	(36)	$	49
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(12)	$	25

(1)    Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty on a net basis. 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 any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

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 remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years.

The notional natural gas position of our Liquefaction Supply Derivatives was approximately 5,023 TBtu and 4,970 TBtu as of March 31, 2021 and December 31, 2020, respectively, of which 91 TBtu for each of the periods were for a natural gas supply contract that SPL has with a related party.

10

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 Sheets Location	March 31, 2021		December 31, 2020
Derivative assets	$	16	$	14
Non-current derivative assets	9		11
Total derivative assets	25		25
Derivative liabilities	(26)		(11)
Non-current derivative liabilities	(42)		(35)
Total derivative liabilities	(68)		(46)
Derivative liability, net	$	(43)	$	(21)

(1)    Does not include collateral posted with counterparties by us of $11 million and $4 million, which are included in other current assets in our Consolidated Balance Sheets as of March 31, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of both March 31, 2021 and December 31, 2020.

The following table shows the gain (loss) from changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Income during the three months ended March 31, 2021 and 2020 (in millions):

	Consolidated Statements of Income Location (1)	Three Months Ended March 31,
		2021		2020
Liquefaction Supply Derivatives	Cost of sales	$	(2)	$	21

(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.

Consolidated Balance Sheets 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):

	Liquefaction Supply Derivatives
As of March 31, 2021
Gross assets	$	68
Offsetting amounts	(43)
Net assets	$	25
Gross liabilities	$	(76)
Offsetting amounts	8
Net liabilities	$	(68)
As of December 31, 2020
Gross assets	$	69
Offsetting amounts	(44)
Net assets	$	25
Gross liabilities	$	(48)
Offsetting amounts	2
Net liabilities	$	(46)

11

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—OTHER NON-CURRENT ASSETS

As of March 31, 2021 and December 31, 2020, other non-current assets, net consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Advances made to municipalities for water system enhancements	$	83	$	84
Advances and other asset conveyances to third parties to support LNG terminal	33		33
Advances made under EPC and non-EPC contracts	22		9
Tax-related prepayments and receivables	17		17
Information technology service prepayments	5		6
Other	17		11
Total other non-current assets, net	$	177	$	160

NOTE 9—ACCRUED LIABILITIES

As of March 31, 2021 and December 31, 2020, accrued liabilities consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Interest costs and related debt fees	$	226	$	203
Accrued natural gas purchases	382		374
LNG terminal and related pipeline costs	80		71
Other accrued liabilities	16		10
Total accrued liabilities	$	704	$	658

NOTE 10—DEBT

As of March 31, 2021 and December 31, 2020, our debt consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Long-term debt:
SPL — 4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 SPL Working Capital Facility”)	$	12,797	$	13,650
Cheniere Partners — 4.000% to 5.625% senior notes due between October 2025 and March 2031 and credit facilities (“2019 CQP Credit Facilities”)	4,100		4,100
Unamortized premium, discount and debt issuance costs, net	(165)		(170)
Total long-term debt, net	16,732		17,580
Current debt:
SPL — current portion of 6.25% senior secured notes due March 2022 (“2022 SPL Senior Notes”) (1)	853		—
Unamortized premium, discount and debt issuance costs, net	(3)		—
Total current debt	850		—
Total debt, net	$	17,582	$	17,580

(1)$147 million of the 2022 SPL Senior Notes is categorized as long-term debt because the proceeds from the expected sale of approximately $147 million aggregate principal amount of 2.95% Senior Secured Notes due 2037, expected to be issued in the second half of 2021 pursuant to a note purchase agreement entered into by SPL in February 2021, are expected to be used to refinance a portion of 2022 SPL Senior Notes.

12

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Issuances and Redemptions

The following table shows the issuances and redemptions of long-term debt during the three months ended March 31, 2021 (in millions):

Issuances	Principal Amount Issued
CQP — 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”) (1)	$	1,500
Redemptions	Amount Redeemed
CQP — 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) (1)	$	1,500

(1)Proceeds of the 2031 CQP Senior Notes, together with cash on hand, were used to redeem all of our outstanding 2025 CQP Senior Notes, resulting in the recognition of debt extinguishment costs of $54 million for the three months ended March 31, 2021 relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2021 (in millions):

	2020 SPL Working Capital Facility (1)		2019 CQP Credit Facilities
Original facility size	$	1,200	$	1,500
Less:
Outstanding balance	—		—
Commitments prepaid or terminated	—		750
Letters of credit issued	413		—
Available commitment	$	787	$	750
Priority ranking	Senior secured		Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Weighted average interest rate of outstanding balance	n/a		n/a
Maturity date	March 19, 2025		May 29, 2024

(1)The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

Restrictive Debt Covenants

The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us and our restricted subsidiaries’ ability to make certain investments or pay dividends or distributions.

As of March 31, 2021, we and SPL were in compliance with all covenants related to our respective debt agreements.

13

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Interest Expense

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

	Three Months Ended March 31,
	2021		2020
Total interest cost	$	247	$	254
Capitalized interest	(30)		(20)
Total interest expense, net of capitalized interest	$	217	$	234

Fair Value Disclosures

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

	March 31, 2021				December 31, 2020
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	16,950	$	18,680	$	16,950	$	19,113
Senior notes — Level 3 (2)	800		953		800		1,036
Credit facilities (3)	—		—		—		—

(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

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

(3)The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty. 

NOTE 11—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
LNG revenues (1)	$	1,669	$	1,449
LNG revenues—affiliate	214		188
Regasification revenues	67		67
Other revenues	13		14
Total revenues	$	1,963	$	1,718

(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three months ended March 31, 2020, we recognized $16 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, which would have been recognized subsequent to March 31, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have such revenues during the three months ended March 31, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

14

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Contract Assets

The following table shows our contract assets, net, which are classified as other current assets and other non-current assets, net on our Consolidated Balance Sheets (in millions):

	March 31,		December 31,
	2021		2020
Contract assets, net	$	1	$	—

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the three months ended March 31, 2021 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

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):

	Three Months Ended March 31, 2021
Deferred revenues, beginning of period	$	137
Cash received but not yet recognized in revenue	101
Revenue recognized from prior period deferral	(137)
Deferred revenues, end of period	$	101

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

	Three Months Ended March 31, 2021
Deferred revenues—affiliate, beginning of period	$	1
Cash received but not yet recognized in revenue	5
Revenue recognized from prior period deferral	(1)
Deferred revenues—affiliate, end of period	$	5

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 March 31, 2021 and December 31, 2020:

	March 31, 2021			December 31, 2020
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	51.4	9	$	52.1	9
LNG revenues—affiliate	0.2		3	0.1		1
Regasification revenues	2.1		5	2.1		5
Total revenues	$	53.7		$	54.3

(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.

15

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)The table above excludes substantially all variable consideration under our SPAs and TUAs. 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 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. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 51% and 44% of our LNG revenues from contracts included in the table above during the three months ended March 31, 2021 and 2020, respectively, were related to variable consideration received from customers. During each of the three months ended March 31, 2021 and 2020, approximately 3% of our regasification revenues were related to variable consideration received from customers.

We may enter 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 12—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
LNG revenues—affiliate
Cheniere Marketing Agreements	$	210	$	182
Contracts for Sale and Purchase of Natural Gas and LNG	4		6
Total LNG revenues—affiliate	214		188
Cost of sales—affiliate
Cheniere Marketing Agreements	34		—
Contracts for Sale and Purchase of Natural Gas and LNG	8		—
Total Cost of sales—affiliate	42		—
Operating and maintenance expense—affiliate
Services Agreements	34		33
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	10		—
General and administrative expense—affiliate
Services Agreements	21		25

As of March 31, 2021 and December 31, 2020, we had $98 million and $184 million, respectively, of accounts receivable—affiliate, under the agreements described below.

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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. (“Bechtel”) had control of, and was commissioning, Train 5 of the Liquefaction Project.

Cheniere Marketing Letter Agreements

In February 2021, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 31 cargoes to be delivered between 2021 and 2026 at a price of 115% of Henry Hub plus $1.72 per MMBtu.

In December 2020, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 30 cargoes scheduled for delivery in 2021 at a price of 115% of Henry Hub plus $0.728 per MMBtu.

In December 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes that were delivered in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.

Facility Swap Agreement

In August 2020, SPL entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.

Natural Gas Transportation and Storage Agreements

SPL is party to various natural gas transportation and storage agreements and CTPL is party to an operational balancing agreement with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to 10 years with extension rights. This related party is partially owned by Brookfield, who acquired a portion of our limited partner interests in September 2020 through its purchase of a portion of BX CQP Target Holdco’s equity interests. We recorded operating and maintenance expense—related party of $10 million in the three months ended March 31, 2021 and accrued liabilities—related party of $3 million and $4 million as of March 31, 2021 and December 31, 2020, respectively, with this related party.

Services Agreements

As of March 31, 2021 and December 31, 2020, we had $127 million and $144 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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Cheniere Partners Services Agreement

We have a services agreement with Cheniere Terminals, a 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 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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

CTPL MSA

CTPL has a management services agreement (the “CTPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the operations and business of the Creole Trail Pipeline, excluding those matters provided for under the CTPL O&M Agreement. The services include, among other services, exercising the day-to-day management of CTPL’s affairs and business, managing CTPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of CTPL’s business and operations, providing contract administration services for all contracts associated with the Creole Trail Pipeline and obtaining insurance. CTPL is required to reimburse Cheniere Terminals for the aggregate of all costs and expenses incurred in the course of performing the services under the CTPL MSA.

Natural Gas Supply Agreement

SPL is party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. This related party is partially owned by Blackstone, who also partially owns our limited partner interests. The term of the agreement is for five years, which can commence no earlier than November 1, 2021 and no later than November 1, 2022, following the achievement of contractually-defined conditions precedent.

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 advanced payments of annual ad valorem taxes 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 shall grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal as early as 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to the dollar-for-dollar credit applied to the ad valorem tax levied against the Sabine Pass LNG terminal in the given year.

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 obligations. We had $3 million and $2 million in due to affiliates and $16 million and $17 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing as of March 31, 2021 and December 31, 2020, respectively.

19

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

SPL has an agreement with CCL that allows them to sell and purchase natural gas from each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under this agreement is recorded as LNG revenues—affiliate.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with Cheniere Terminals 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 Cheniere Terminals a portion of its future revenues. Accordingly, Tug Services distributed $1 million during each of the three months ended March 31, 2021 and 2020 to Cheniere Terminals, 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 months ended March 31, 2021 and 2020.

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 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.

20

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 13—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 (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statements of Partners’ Equity. On April 26, 2021, we declared a $0.660 distribution per common unit and the related distribution to our general partner and IDR holders that will be paid on May 14, 2021 to unitholders of record as of May 6, 2021 for the period from January 1, 2021 to March 31, 2021.

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

The 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 March 31, 2021
Net income	$	347
Declared distributions	356		320		—		7		29
Assumed allocation of undistributed net loss (1)	$	(9)	(8)		—		—		—
Assumed allocation of net income			$	312	$	—	$	7	$	29
Weighted average units outstanding			484.0		—
Basic and diluted net income per unit			$	0.64	$	—
Three Months Ended March 31, 2020
Net income	$	435
Declared distributions	336		223		87		6		20
Assumed allocation of undistributed net income (1)	$	99	70		27		2		—
Assumed allocation of net income			$	293	$	114	$	8	$	20
Weighted average units outstanding			348.6		135.4
Basic and diluted net income per unit			$	0.84	$	0.84

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

21

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 14—CUSTOMER CONCENTRATION

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

	Percentage of Total Revenues from External Customers		Percentage of Accounts Receivable, Net from External Customers
	Three Months Ended March 31,		March 31,	December 31,
	2021	2020	2021	2020
Customer A	27%	28%	23%	31%
Customer B	15%	15%	15%	21%
Customer C	18%	15%	25%	*
Customer D	14%	16%	*	22%
Customer E	*	*	19%	*
Customer F	*	11%	*	*

* Less than 10%

NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2021		2020
Cash paid during the period for interest on debt, net of amounts capitalized	$	185	$	211

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $229 million and $219 million as of March 31, 2021 and 2020, respectively.

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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 (the “Securities Act”), 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;

•statements regarding the outbreak of COVID-19 and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing credit worthiness of our contractual counterparties, any disruptions in our operations or construction of our Trains and the health and safety of Cheniere’s employees, and on our customers, the global economy and the demand for LNG; 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

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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 fiscal year ended December 31, 2020. 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

•Results of Operations 

•Liquidity and Capital Resources 

•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 in 2006. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Through our subsidiary, SPL, we are currently operating five natural gas liquefaction Trains and are constructing one additional Train that is expected to be substantially completed in the first half of 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal, one of the largest LNG production facilities in the world. Through our 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 17 Bcfe, two existing marine berths and one under construction that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters and vaporizers with regasification capacity of approximately 4 Bcf/d. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines.

Overview of Significant Events

Our significant events since January 1, 2021 and through the filing date of this Form 10-Q include the following:  

Operational

•As of April 30, 2021, more than 1,250 cumulative LNG cargoes totaling over 85 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

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Financial

•We completed the following financing transactions:

◦In February 2021, SPL entered into a note purchase agreement for the sale of approximately $147 million aggregate principal amount of 2.95% Senior Secured Notes due 2037 (the “2.95% SPL 2037 Senior Secured Notes”) on a private placement basis. The 2.95% SPL 2037 Senior Secured Notes are expected to be issued in the second half of 2021, and the net proceeds are expected to be used to refinance a portion of SPL’s outstanding Senior Secured Notes due 2022. The 2.95% SPL 2037 Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years.

◦In March 2021, Cheniere Partners issued an aggregate principal amount of approximately $1.5 billion of 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”). The net proceeds of the 2031 CQP Senior Notes, along with cash on hand, were used to refinance the 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) and to pay fees and expenses in connection with the refinancing.

•In February 2021, Fitch Ratings (“Fitch”) changed the outlook of SPL’s senior secured notes rating to positive from stable and the outlook of our long-term issuer default rating and senior unsecured notes rating to positive from stable.

•In April 2021, S&P Global Ratings changed the outlook on our ratings to positive from negative.

Results of Operations

The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Project (including both operational and commissioning volumes) during the three months ended March 31, 2021 and 2020:

(1) The three months ended March 31, 2021 excludes eight TBtu that were loaded at our affiliate’s facility.

Net income

	Three Months Ended March 31,
(in millions, except per share data)	2021		2020		Change
Net income	$	347	$	435	$	(88)
Basic and diluted net income per common unit	0.64		0.84		(0.20)

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Net income decreased by $88 million during the three months ended March 31, 2021 from the comparable period in 2020, primarily as the result of increased loss on the extinguishment of the 2025 CQP Senior Notes and decreased margins due to the increased pricing of natural gas feedstock and less volume sold as well as the non-recurrence of commodity-related derivative gains from the three months ended March 31, 2020, partially offset by decreased interest expense, net of capitalized interest.

We enter into derivative instruments to manage our exposure to commodity-related marketing and price risk. Derivative instruments are reported at fair value on our Consolidated Financial Statements. In some cases, the underlying transactions being economically hedged are accounted for under the accrual method of accounting, 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 March 31,
(in millions, except volumes)	2021		2020		Change
LNG revenues	$	1,669	$	1,449	$	220
LNG revenues—affiliate	214		188		26
Regasification revenues	67		67		—
Other revenues	13		14		(1)
Total revenues	$	1,963	$	1,718	$	245
LNG volumes recognized as revenues (in TBtu) (1)	325		327		(2)

(1)    Excludes volume associated with cargoes for which customers notified us that they would not take delivery and includes eight TBtu that were loaded at our affiliate’s facility.

Total revenues increased during the three months ended March 31, 2021 from the comparable period in 2020, primarily as a result of increased revenues per MMBtu. LNG revenues during the three months ended March 31, 2020 also included $16 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, which would have been recognized subsequent to March 31, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have such revenues during the three months ended March 31, 2021.

Also included in LNG revenues are sales of certain unutilized natural gas procured for the liquefaction process and gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery. We recognized revenues of $48 million and $56 million during the three months ended March 31, 2021 and 2020, respectively, related to these transactions.

Operating costs and expenses

	Three Months Ended March 31,
(in millions)	2021		2020		Change
Cost of sales	$	948	$	699	$	249
Cost of sales—affiliate	42		—		42
Operating and maintenance expense	149		152		(3)
Operating and maintenance expense—affiliate	34		33		1
Operating and maintenance expense—related party	10		—		10
General and administrative expense	2		2		—
General and administrative expense—affiliate	21		25		(4)
Depreciation and amortization expense	139		138		1
Impairment expense and loss on disposal of assets	—		5		(5)
Total operating costs and expenses	$	1,345	$	1,054	$	291

Total operating costs and expenses increased during the three months ended March 31, 2021 from the three months ended March 31, 2020, primarily as a result of increased cost of sales (including affiliate). Cost of sales includes costs incurred

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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 months ended March 31, 2021 from the comparable period in 2020 primarily due to the increase in pricing of natural gas feedstock. Cost of sales also includes variable transportation and storage costs and other costs to convert natural gas into LNG.

Cost of sales—affiliate increased during the three months ended March 31, 2021 as a result of the cost of cargoes procured from our affiliate to fulfill our commitments to our long-term customers during operational constraints.

Operating and maintenance expense (including affiliate and related party) primarily includes costs associated with operating and maintaining the Liquefaction Project. The increase in operating and maintenance expense (including affiliate and related party) during the three months ended March 31, 2021 from the comparable period in 2020 was primarily related to increased third-party service and maintenance costs and increased natural gas transportation and storage capacity demand charges paid to third parties and related parties. Operating and maintenance expense (including affiliates) also includes payroll and benefit costs of operations personnel, insurance and regulatory costs and other operating costs.

Other (income) expense

	Three Months Ended March 31,
(in millions)	2021		2020		Change
Interest expense, net of capitalized interest	$	217	$	234	$	(17)
Loss on modification or extinguishment of debt	54		1		53
Other expense (income), net	—		(6)		6
Total other expense	$	271	$	229	$	42

Interest expense, net of capitalized interest, decreased during the three months ended March 31, 2021 from the comparable period in 2020 primarily as a result of lower interest costs as a result of refinancing higher cost debt. During the three months ended March 31, 2021 and 2020, we incurred $247 million and $254 million of total interest cost, respectively, of which we capitalized $30 million and $20 million, respectively, which was primarily related to interest costs incurred to construct the remaining assets of the Liquefaction Project.

Loss on modification or extinguishment of debt increased during the three months ended March 31, 2021 from the comparable period in 2020, due to the recognition of $54 million of debt extinguishment costs relating to the payment of early redemption fees and premiums and write off of unamortized debt issuance costs with the redemption of the 2025 CQP Senior Notes.

Other (income) expense, net decreased during the three months ended March 31, 2021 from the comparable period in 2020 due to a decrease in interest income earned and lower cash balances.

Liquidity and Capital Resources

The following table provides a summary of our liquidity position at March 31, 2021 and December 31, 2020 (in millions):

	March 31,		December 31,
	2021		2020
Cash and cash equivalents	$	1,219	$	1,210
Restricted cash designated for the Liquefaction Project	123		97
Available commitments under the following credit facilities:
$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 SPL Working Capital Facility”)	787		787
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”)	750		750

CQP Senior Notes

The $1.1 billion of 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”), $1.5 billion of 4.500% Senior Notes due 2029 (the “2029 CQP Senior Notes”) and the 2031 CQP Senior Notes (collectively, the “CQP Senior Notes”), are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing its guarantee,

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Sabine Pass LP (each a “Guarantor” and collectively, the “CQP Guarantors”). The CQP Senior Notes are governed by the same base indenture (the “CQP Base Indenture”). The 2026 CQP Senior Notes are further governed by the Second Supplemental Indenture, the 2029 CQP Senior Notes are further governed by the Third Supplemental Indenture and the 2031 CQP Senior Notes are further governed by a Fifth Supplemental Indenture. The indentures governing the CQP Senior Notes contain terms and events of default and certain covenants that, among other things, limit our ability and the CQP Guarantors’ ability 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, 2021 for the 2026 CQP Senior Notes, October 1, 2024 for the 2029 CQP Senior Notes and March 1, 2026 for the 2031 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, 2021 for the 2026 CQP Senior Notes, October 1, 2024 for the 2029 CQP Senior Notes and March 1, 2024 for the 2031 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 105.625% of the aggregate principal amount of the 2026 CQP Senior Notes, 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes and 104.000% of the aggregate principal amount of the 2031 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, 2021 through the maturity date of October 1, 2026 for the 2026 CQP Senior Notes, October 1, 2024 through the maturity date of October 1, 2029 for the 2029 CQP Senior Notes and March 1, 2026 through the maturity date of March 1, 2031 for the 2031 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. In the event that the aggregate amount of our secured indebtedness and the secured indebtedness of the CQP 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 our existing and future tangible and intangible assets and our rights and the rights of the CQP Guarantors and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 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.

The CQP Guarantors’ guarantees are full and unconditional, subject to certain release provisions including (1) the sale, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the CQP 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 indenture governing the CQP Senior Notes. In the event of a default in payment of the principal or interest by us, whether at maturity of the CQP Senior Notes or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the CQP Guarantors to enforce the guarantee.

The rights of holders of the CQP Senior Notes against the CQP Guarantors may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit the Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the CQP Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

The following tables include summarized financial information of Cheniere Partners (“Parent Issuer”), and the CQP Guarantors (together with the Parent Issuer, the “Obligor Group”) on a combined basis. Investments in and equity in the earnings of SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”), which are not currently members of the Obligor Group, have been excluded. Intercompany balances and transactions between entities in the Obligor Group have been eliminated. Although the creditors of the Obligor Group have no

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claim against the Non-Guarantors, the Obligor Group may gain access to the assets of the Non-Guarantors upon bankruptcy, liquidation or reorganization of the Non-Guarantors due to its investment in these entities. However, such claims to the assets of the Non-Guarantors would be subordinated to the any claims by the Non-Guarantors’ creditors, including trade creditors. See Sabine Pass LNG Terminal—SPL Senior Notes for additional detail on restrictions of Non-Guarantor debt.

Summarized Balance Sheets (in millions)	March 31,		December 31,
	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	1,219	$	1,210
Accounts receivable from Non-Guarantors	24		46
Other current assets	39		42
Current assets—affiliate	119		137
Total current assets	1,401		1,435
Property, plant and equipment, net	2,477		2,493
Other non-current assets, net	115		117
Total assets	$	3,993	$	4,045
LIABILITIES
Current liabilities
Due to affiliates	$	121	$	156
Deferred revenue from Non-Guarantors	21		22
Other current liabilities	123		100
Total current liabilities	265		278
Long-term debt, net	4,056		4,060
Other non-current liabilities	83		85
Non-current liabilities—affiliate	16		17
Total liabilities	$	4,420	$	4,440

Summarized Statement of Income (in millions)	Three Months Ended March 31, 2021
Revenues	$	80
Revenues from Non-Guarantors	132
Total revenues	212
Operating costs and expenses	44
Operating costs and expenses—affiliate	48
Total operating costs and expenses	92
Income from operations	120
Net income	10

2019 CQP Credit Facilities

We have a $750 million revolving credit facility under the 2019 CQP Credit Facilities. Borrowings under the 2019 CQP Credit Facilities will be used to fund the development and construction of Train 6 of the Liquefaction Project and for general corporate purposes, subject to a sublimit, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit. As of both March 31, 2021 and December 31, 2020, we had $750 million of available commitments and no letters of credit issued or loans outstanding under the 2019 CQP Credit Facilities.

The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain

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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 and secured by a first priority lien (subject to permitted encumbrances) on substantially all of our and the CQP Guarantors’ existing and future tangible and intangible assets and rights and equity interests in the CQP Guarantors (except, in each case, for certain excluded properties set forth in the 2019 CQP Credit Facilities).

Sabine Pass LNG Terminal 

Liquefaction Facilities

The Liquefaction Project is one of the largest LNG production facilities in the world. We are currently operating five Trains and two marine berths at the Liquefaction Project, and are constructing one additional Train that is expected to be substantially completed in the first half of 2022, and a third marine berth. We have achieved substantial completion of the first five Trains of the Liquefaction Project and commenced commercial operating activities for each Train at various times starting in May 2016. The following table summarizes the project completion and construction status of Train 6 of the Liquefaction Project as of March 31, 2021:

	Train 6
Overall project completion percentage	83.0%
Completion percentage of:
Engineering	99.6%
Procurement	99.9%
Subcontract work	64.9%
Construction	61.7%
Date of expected substantial completion	1H 2022

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 and non-FTA countries through December 31, 2050, 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 and non-FTA countries through December 31, 2050, 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 through December 31, 2050, in an amount up to a combined total of 503.3 Bcf/yr of natural gas (approximately 10 mtpa).

In December 2020, the DOE announced a new policy in which it would no longer issue short-term export authorizations separately from long-term authorizations. Accordingly, the DOE amended each of SPL’s long-term authorizations to include short-term export authority, and vacated the short-term orders.

An application was filed in September 2019 seeking authorization to make additional exports from the Liquefaction Project to FTA countries for a 25-year term and to non-FTA countries for a 20-year term in an amount up to the equivalent of approximately 153 Bcf/yr of natural gas, for a total Liquefaction Project export capacity of approximately 1,662 Bcf/yr. The terms of the authorizations are requested to commence on the date of first commercial export from the Liquefaction Project of the volumes contemplated in the application. In April 2020, the DOE issued an order authorizing SPL to export to FTA countries related to this application, for which the term was subsequently extended through December 31, 2050, but has not yet issued an order authorizing SPL to export to non-FTA countries for the corresponding LNG volume. A corresponding application for authorization to increase the total LNG production capacity of the Liquefaction Project from the currently authorized level to approximately 1,662 Bcf/yr was also submitted to the FERC and is currently pending.

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Customers

SPL has entered into fixed price long-term SPAs generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 17 years (plus extension rights) for Trains 1 through 6 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 75% of the total production capacity from these Trains, potentially increasing up to approximately 85% after giving effect to an SPA that Cheniere has committed to provide to us. 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 generally equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, 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 generally sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel 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 $2.9 billion for Trains 1 through 5. After giving effect to an SPA that Cheniere has committed to provide to SPL, the annual fixed fee portion to be paid by the third-party SPA customers would increase to at least $3.3 billion, which is expected to occur upon the date of first commercial delivery of Train 6.

In addition, Cheniere Marketing has agreements with SPL to purchase: (1) at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers, (2) up to 30 cargoes scheduled for delivery in 2021 at a price of 115% of Henry Hub plus $0.728 per MMBtu and (3) up to 31 cargoes to be delivered between 2021 and 2026 at a price of 115% of Henry Hub plus $1.72 per MMBtu.

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 March 31, 2021, SPL had secured up to approximately 4,974 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to conditions precedent.

Construction

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the Liquefaction Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks 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 the third marine berth that is currently under construction. As of March 31, 2021, we have incurred $2.0 billion under this contract.

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. Approximately 2 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

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Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1 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 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 each of the three months ended March 31, 2021 and 2020, SPL recorded $32 million as operating and maintenance expense under this partial TUA assignment agreement.

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

Capital Resources

We currently expect that SPL’s capital resources requirements with respect to 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 2020 SPL Working Capital Facility, 2019 CQP Credit Facilities, cash flows from operations and equity contributions from us, SPL will have adequate financial resources available to meet its currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the Liquefaction Project. 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 March 31, 2021 and December 31, 2020 (in millions):

	March 31,		December 31,
	2021		2020
Senior notes (1)	$	17,750	$	17,750
Credit facilities outstanding balance (2)	—		—
Letters of credit issued (3)	413		413
Available commitments under credit facilities (3)	1,537		1,537
Total capital resources from borrowings and available commitments (4)	$	19,700	$	19,700

(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”), 4.500% Senior Secured Notes due 2030 (the “2030 SPL Senior Notes”) and 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) (collectively, the “SPL Senior Notes”) and our CQP Senior Notes.

(2)         Includes outstanding balances under the 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities, inclusive of any portion of the 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities that may be used for general corporate purposes.

(3)        Consists of 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities.

(4)        Does not include equity contributions that may be available from Cheniere’s borrowings and available cash and cash equivalents.

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SPL Senior Notes

The SPL Senior Notes are governed by a common indenture (the “SPL Indenture”) and the terms of the 2037 SPL Senior Notes are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes are secured on a pari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied.

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, 2030 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, 2030 SPL Senior Notes and 2037 SPL Senior Notes, in which case the time period is within six months of the respective dates of maturity), redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

SPL 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 2020 SPL Working Capital Facility. 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 and are fully amortizing according to a fixed sculpted amortization schedule.

In February 2021, SPL entered into a note purchase agreement for the sale of approximately $147 million aggregate principal amount of the 2.95% SPL 2037 Senior Secured Notes on a private placement basis. The 2.95% SPL 2037 Senior Secured Notes are expected to be issued in the second half of 2021, and the net proceeds are expected to be used to refinance a portion of SPL’s outstanding Senior Secured Notes due 2022. The 2.95% SPL 2037 Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years.

2020 SPL Working Capital Facility

In March 2020, SPL entered into the 2020 SPL Working Capital Facility with aggregate commitments of $1.2 billion, which replaced the $1.2 billion Amended and Restated SPL Working Capital Facility (the “2015 SPL Working Capital Facility”). The 2020 SPL Working Capital Facility is intended to be used for loans to SPL, swing line loans to SPL and the issuance of letters of credit on behalf of SPL, primarily for (1) the refinancing of the 2015 SPL Working Capital Facility, (2) fees and expenses related to the 2020 SPL Working Capital Facility, (3) SPL and its future subsidiaries’ gas purchase obligations and (4) SPL and certain of its future subsidiaries’ general corporate purposes. SPL may, from time to time, request increases in the commitments under the 2020 SPL Working Capital Facility of up to $800 million. As of both March 31, 2021 and December 31, 2020, SPL had $787 million of available commitments, $413 million aggregate amount of issued letters of credit and no outstanding borrowings under the 2020 SPL Working Capital Facility.

The 2020 SPL Working Capital Facility matures on March 19, 2025, but may be extended with consent of the lenders. The 2020 SPL Working Capital Facility provides for mandatory prepayments under customary circumstances.

The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL is restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, satisfaction of a 12-month forward-looking and backward-looking

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1.25:1.00 debt service reserve ratio test. The obligations of SPL under the 2020 SPL Working Capital Facility are secured by substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries of SPL on a pari passu basis by a first priority lien with the SPL Senior Notes.

Restrictive Debt Covenants

As of March 31, 2021, we and SPL were in compliance with all covenants related to our respective debt agreements.

LIBOR

The use of LIBOR is expected to be phased out by June 2023. It is currently unclear whether LIBOR will be utilized beyond that date or whether it will be replaced by a particular rate. We intend to continue working with our lenders to pursue any amendments to our debt agreements that are currently subject to LIBOR following LIBOR cessation and will continue to monitor, assess and plan for the phase out of LIBOR.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash for the three months ended March 31, 2021 and 2020 (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. 

	Three Months Ended March 31,
	2021		2020
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities	$	588	$	535
Proceeds from issuances of debt	1,500		—
Other	3		—
	$	2,091	$	535
Uses of cash, cash equivalents and restricted cash:
Property, plant and equipment, net	$	(146)	$	(317)
Repayments of debt	(1,500)		—
Debt issuance and other financing costs	(19)		(7)
Debt extinguishment costs	(40)		—
Distributions to owners	(351)		(330)
	(2,056)		(654)
Net increase (decrease) in cash, cash equivalents and restricted cash	$	35	$	(119)

Operating Cash Flows

Our operating cash net inflows during the three months ended March 31, 2021 and 2020 were $588 million and $535 million, respectively. The $53 million increase in operating cash inflows in 2021 compared to 2020 was primarily related to cash provided by working capital primarily from payment timing differences, partially offset by the payment of early redemption fees and premiums associated with the redemption of the 2025 CQP Senior Notes.

Proceeds from Issuance of Debt, Repayments of Debt, Debt Issuance and Other Financing Costs and Debt Extinguishment Costs

During the three months ended March 31, 2021, we issued an aggregate principal amount of $1.5 billion of the 2031 CQP Senior Notes and incurred $19 million of debt issuance costs related to this issuance. The proceeds from this issuance, together with cash on hand, were used to redeem all of the outstanding 2025 CQP Senior Notes, and we paid $40 million of debt extinguishment costs, mainly related to premiums associated with this redemption.

During the three months ended March 31, 2020, we entered into the 2020 SPL Working Capital Facility to replace the 2015 SPL Working Capital Facility. We incurred $7 million of debt issuance costs primarily related to up-front fees paid.

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Property, Plant and Equipment, net

Cash outflows for property, plant and equipment were primarily for the construction costs for the Liquefaction Project. These costs are capitalized as construction-in-process until achievement of substantial completion.

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 three months ended March 31, 2021 and 2020:

						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
February 12, 2021	October 1 - December 31, 2020	$	0.655	$	—	$	316	$	—	$	7	$	27
February 14, 2020	October 1 - December 31, 2019	0.63		0.63		220		85		6		18

On April 26, 2021, we declared a $0.660 distribution per common unit and the related distribution to our general partner and incentive distribution right holders to be paid on May 14, 2021 to unitholders of record as of May 6, 2021 for the period from January 1, 2021 to March 31, 2021.

Off-Balance Sheet Arrangements

As of March 31, 2021, 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 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 fiscal year ended December 31, 2020.

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):

	March 31, 2021				December 31, 2020
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(43)	$	3	$	(21)	$	4

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

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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. 

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PART II.     OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. There have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2020.

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 fiscal year ended December 31, 2020.

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ITEM 6.    EXHIBITS

Exhibit No.	Description
4.1	Fifth Supplemental Indenture, dated as of March 11, 2021, among the Partnership, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture (Incorporated by reference to Exhibit 4.1 to the Partnership's Current Report on Form 8-K (SEC File No. 001-33366), filed on March 11, 2021)
10.1	Registration Rights Agreement, dated as of March 11, 2021, among the Partnership, the guarantors party thereto and J.P. Morgan Securities LLC (Incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 001-33366), filed on March 11, 2021)
10.2*	Change orders 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.: (i) the Change Order CO-00035 Impacts from Hurricanes Laura and Delta, dated December 22, 2020, (ii) the Change Order CO-00036 Third Berth - Add N2 Connection on Liquid & Hybrid SVT Loading Arm Apex, dated December 22, 2020, (iii) the Change Order CO-00037 Third Berth Design Vessels Update, dated December 22, 2020, (iv) the Change Order CO-00038 Train 6 PV-16002 & FV-15104 Valve Trim Upgrades, dated January 21, 2021, (v) the Change Order CO-00039 Third Berth Design Update to Supply Bunkering Fuel, dated February 11, 2021, (vi) the Change Order CO-00040 LNG Benchmark 7 Elevation Change, dated February 11, 2021, (vii) the Change Order CO-00041 Costs to Comply with SPL FTZ (Excluding Pipe Spools), dated February 12, 2021 and (viii) the Change Order CO-00042 COVID-19 Impacts 1Q2021, dated March 12, 2021
22.1*	List of Issuers and Guarantor Subsidiaries
31.1*	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1**	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
104*	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*	Filed herewith.
**	Furnished herewith.

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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:	May 3, 2021	By:	/s/ Zach Davis
			Zach Davis
			Senior Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	May 3, 2021	By:	/s/ Leonard E. Travis
			Leonard E. Travis
			Senior Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

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EX-10.2

Exhibit 10.2

CHANGE ORDER

Impacts from Hurricanes Laura and Delta

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00035 DATE OF CHANGE ORDER: December 22, 2020

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.2 of the Agreement (Change Orders Requested by Contractor), Parties agree this Change Order includes final and agreed-upon impacts to the Project caused by Hurricanes Laura (August 2020) and Delta (October 2020), and critical assistance provided by Contractor to Owner's O&M due to impacts caused by Hurricane Delta.

2.The detailed cost breakdown for this Change Order is detailed in Exhibits A.1, A.2 and A.3 of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)

1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34)	$	7,299,785
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,024,192,358
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	2,937,860
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,027,130,218

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33)	$	(9,733,372)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	447,962,628
10.	The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
11.	The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	447,962,628

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)	$	2,472,154,986
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	2,937,860
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,475,092,846

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a):N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit B

Adjustment to Minimum Acceptance Criteria for Subproject 6(a):N/A

Adjustment to Performance Guarantees for Subproject 6(a):N/A

Adjustment to Design Basis for Subproject 6(a):N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b):N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ KM Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: _____ Contractor _____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order.Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect.This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Senior Project Manager
Title	Title
January 7, 2021	December 22, 2020
Date of Signing	Date of Signing

CHANGE ORDER

Third Berth - Add N2 Connection on Liquid & Hybrid SVT Loading Arm Apex

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00036 DATE OF CHANGE ORDER: December 22, 2020

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor's engineering, procurement and construction services to modify the Third Berth Liquid Arms (00K-2403A/D) and Hybrid Loading Arm (00K-2403B) to add a new connection at the Apex elbow which will facilitate supply of Nitrogen for purging liquid arm and vapor vent out.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)

1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35)	$	10,237,645
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,027,130,218
4.	The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,027,130,218

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, & 25-27, 30-31, 33)	$	(9,733,372)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	447,962,628
10.	The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	492,448
11.	The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	448,455,076

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)	$	2,475,092,846
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	492,448
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,475,585,294

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified : N/A

Adjustment to other Changed Criteria for Subproject 6(a): N/A

Adjustment to Payment Schedule for Subproject 6(a): N/A

Adjustment to Minimum Acceptance Criteria for Subproject 6(a):N/A

Adjustment to Performance Guarantees for Subproject 6(a):N/A

Adjustment to Design Basis for Subproject 6(a):N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B

Adjustment to Design Basis for Subproject 6(b):N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials:

/s/ MDR Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order.Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect.This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Senior Project Manager
Title	Title
January 13, 2021	December 22, 2020
Date of Signing	Date of Signing

CHANGE ORDER

Third Berth Design Vessels Update

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00037 DATE OF CHANGE ORDER: December 22, 2020

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor's engineering and procurement services to perform an analysis to confirm the adequacy of the Third Berth design to accommodate 200,000m3 and Q4000 LNG vessels.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)

1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35)	$	10,237,645
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,027,130,218
4.	The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,027,130,218

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36)	$	(9,240,924)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	448,455,076
10.	The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	144,247
11.	The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	448,599,323

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)....................................................	$	2,475,585,294
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	144,247
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)................................	$	2,475,729,541

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a):N/A

Adjustment to Payment Schedule for Subproject 6(a): N/A

Adjustment to Minimum Acceptance Criteria for Subproject 6(a): N/A

Adjustment to Performance Guarantees for Subproject 6(a):N/A

Adjustment to Design Basis for Subproject 6(a):N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B

Adjustment to Design Basis for Subproject 6(b):N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ KM Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Senior Project Manager
Title	Title
January 4, 2021	December 28, 2020
Date of Signing	Date of Signing

CHANGE ORDER

Train 6 PV-16002 & FV-15104 Valve Trim Upgrades

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00038 DATE OF CHANGE ORDER: January 21, 2021

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s cost to remove the original Train 6 Design Basis valves PV-16002 and FV-15104 (“Original Valves”) and install in their place the SPL O&M-supplied PV-16002 and FV-15104 fully assembled warehouse valve bodies with upgraded trim and internals (“Upgraded Valves”). The Upgraded Valves are designed to increase operation efficiency between defrost cycles. Upon removal of the Original Valves, Contractor shall furnish to SPL O&M warehouse for asset transfer.

2.The equipment warranty coverage for the Upgraded Valves shall be maintained by Owner; however, Contractor shall warranty the installation. Additionally, Contractor shall continue to maintain the equipment warranty coverage for the Original Valves unless Owner later elects for Contractor to assign the warranty for the Original Valves to Owner.

3.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)

1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35)	$	10,237,645
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,027,130,218
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	46,801
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,027,177,019

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37)	$	(9,096,677)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	448,599,323
10.	The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
11.	The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	448,599,323

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)....................................................	$	2,475,729,541
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	46,801
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)................................	$	2,475,776,342

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a):N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit B

Adjustment to Minimum Acceptance Criteria for Subproject 6(a):N/A

Adjustment to Performance Guarantees for Subproject 6(a):N/A

Adjustment to Design Basis for Subproject 6(a): Yes; see Section 1 above.

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ KM Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Senior Project Manager
Title	Title
February 11, 2021	January 21, 2021
Date of Signing	Date of Signing

CHANGE ORDER

Third Berth Design Update to Supply Bunkering Fuel

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00039 DATE OF CHANGE ORDER: February 11, 2021

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order includes Contractor’s cost to perform an evaluation of the feasibility of loading small-scale LNG carriers or barges that would supply LNG as bunkering fuel at the Third Berth. The detailed scope of services of this Change Order is detailed in Exhibit C of this Change Order.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)

1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38)	$	10,284,446
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,027,177,019
4.	The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,027,177,019

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37)	$	(9,096,677)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	448,599,323
10.	The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	698,868
11.	The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	449,298,191

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)	$	2,475,776,342
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	698,868
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,476,475,210

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a):N/A

Adjustment to Payment Schedule for Subproject 6(a):

Adjustment to Minimum Acceptance Criteria for Subproject 6(a):N/A

Adjustment to Performance Guarantees for Subproject 6(a):N/A

Adjustment to Design Basis for Subproject 6(a):N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ KM Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Senior Project Manager
Title	Title
February 15, 2021	February 12, 2021
Date of Signing	Date of Signing

CHANGE ORDER

LNG Benchmark 7 Elevation Change

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00040 DATE OF CHANGE ORDER: February 11, 2021

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.2 of the Agreement (Change Orders Requested by Contractor), the Parties agree this Change Order includes Contractor’s engineering, procurement and construction costs to perform the following services to accommodate the change in the revised plant monument Benchmark LNG 7:

a.Revise all impacted design drawings to reflect the current plant monument Benchmark LNG 7 elevation of 10.598’ NAVD 88, including raising the Third Berth Loading Platform and Trestle, Dolphins, site grade and drainage to reflect the 1.137’ correction factor.

b.Redesign for trestle abutments, Trestle Piperack Module 4 as well as reassessments of foundations for Module 3 Trestle Piperack due to elevation change.

c.Rework of piping design and cable trays in Module 4 to allow tie-in to existing tie-in pipe rack elevations on land.

d.Modification to Outfall to maintain the same crossing location of the condensate line with resulting shorter culvert length.

e.Civil soil improvement Works to incorporate these changes to revised plant monument Benchmark LNG 7 height.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)

1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38)	$	10,284,446
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,027,177,019
4.	The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,027,177,019

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39)	$	(8,397,809)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	449,298,191
10.	The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	2,239,459
11.	The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	451,537,650

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)	$	2,476,475,210
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	2,239,459
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,478,714,669

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a):N/A

Adjustment to Payment Schedule for Subproject 6(a):

Adjustment to Minimum Acceptance Criteria for Subproject 6(a):N/A

Adjustment to Performance Guarantees for Subproject 6(a):N/A

Adjustment to Design Basis for Subproject 6(a):N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): Yes; see Exhibit B

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ KM Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Senior Project Manager
Title	Title
February 15, 2021	February 12, 2021
Date of Signing	Date of Signing

CHANGE ORDER

Costs to Comply with SPL FTZ (Excluding Pipe Spools)

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00041 DATE OF CHANGE ORDER: February 12, 2021

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (Change Orders Requested by Owner), the Parties agree this Change Order reflects Contractor’s costs to comply with Owner’s Foreign-Trade-Zone No. 291 in Cameron, Louisiana (the “FTZ”) for FTZ entries, bonded transports, final receipt and forecasted removal / return costs of all material (excluding Above-Ground pipe spools imported from Turkey).

2.The Parties previously executed Change Order CO-00004 (Foreign Trade Zone), dated 2 July 2019, which defines responsibilities of Owner and Contractor with respect to FTZ compliance.

3.The Parties previously executed Change Order CO-00013 ((Cost to Comply with SPL FTZ (FTZ Entries, Bonded Transports and Receipt for AG Pipe Spools Only)), dated 26 February 2020, which included the costs to comply with FTZ for Above-Ground spools imported from Turkey.

4.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

5.Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)

1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38)	$	10,284,446
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,027,177,019
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	325,840
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,027,502,859

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37)	$	(6,158,350)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	451,537,650
10.	The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
11.	The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	451,537,650

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)	$	2,478,714,669
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	325,840
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,479,040,509

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria for Subproject 6(a) (insert N/A if no changes or impact; attach additional documentation if necessary):N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes, see Exhibit B

Adjustment to Minimum Acceptance Criteria for Subproject 6(a):N/A

Adjustment to Performance Guarantees for Subproject 6(a):N/A

Adjustment to Design Basis for Subproject 6(a):N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria for Subproject 6(b) (insert N/A if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement for Subproject 6(b): N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ KM Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Sr. Project Manager
Title	Title
February 23, 2021	February 12, 2021
Date of Signing	Date of Signing

CHANGE ORDER

COVID-19 Impacts 1Q2021

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 7, 2018 CHANGE ORDER NUMBER: CO-00042 DATE OF CHANGE ORDER: March 12, 2021

The Agreement between the Parties listed above is changed as follows:

1.Pursuant to Article 6.2 of the Agreement (Change Orders Requested by Contractor), Parties agree this Change Order includes Contractor’s costs for the first quarter of 2021 (“Q1”) (actuals through January 2021 and forecasted costs through March 2021), in response to the novel coronavirus (COVID-19) outbreak event.

This Change Order is based on the following assumptions and qualifications for Q1:

i.Contractor’s Houston home office personnel have worked and shall continue working effectively remotely or in the Houston home office.

ii.Contractor has been able to keep the Jobsite open throughout the event and shall continue doing so, to the extent reasonably possible, to advance the Work at the current rate of progress (or better if possible), with no planned shutdown in Q1.

iii.Contractor shall continue to put forth diligent mitigation efforts to minimize impacts caused by the event to the extent reasonably practical, including but not limited to: increased craft professional hours for additional cleaning, disinfecting, etc.; increased bussing services to support social distancing; additional cleaning stations, waste management services, etc.; quarantine requirements for supplier technical support (international and others); continued COVID-19 testing costs and hours (excluding quarantine time); increased professional staff for contact tracing efforts; and additional safety PPE, communication materials (e.g., posters, signs, etc.).

iv.No major COVID-19 infection outbreak on the Jobsite resulting in: (i) Site shutdown of all or critical scopes of the Work; or (ii) absenteeism at or above the twenty percent (20%) level for a sustained duration of more than four (4) Weeks. Should either of these triggers occur, the Parties shall jointly collaborate on mitigation actions and plans for shutdown accordingly.

v.Existing government (local, state and/or federal) guidelines, executive orders, actions or directives as of 9 March 2021 shall remain unchanged through the end of Q1. New government orders shall be subject to separate notices and Change Orders, if applicable.

vi.Owner’s operations and other professional staff personnel shall continue to support the Contractor’s activities for the Project in support of the Work.

vii.Subcontractors and Suppliers shall continue to provide uninterrupted support for construction activities either at Site or remotely if possible.

viii.Any changes in the above assumptions and qualifications and additional costs beyond Q1 are excluded from this Change Order; and may be part of a separate Change Order in accordance with Article 6.2 of the Agreement.

2.Contractor has not experienced schedule impacts on the critical path of the CPM Schedule through 9 March 2021; and should all the qualifications and assumptions above remain as stated, Contractor does not anticipate any schedule impacts to the Project on the critical path of the CPM Schedule through Q1. In the event of the occurrence of any impacts to the critical path of the CPM Schedule, Contractor shall notify Owner in accordance with Article 6.5 of the Agreement.

3.The detailed cost breakdown of this Change Order is provided in Exhibit A of this Change Order.

4.Schedule C-3 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit B of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)

1.	The original Contract Price Applicable to Subproject 6(a) was	$	2,016,892,573
2.	Net change for Contract Price Applicable to Subproject 6(a) by previously authorized Change Orders (#01-08, 10-13, 15, 17-18, 21-22, 24, 28-29, 31-32, 34-35, 38, 41)	$	10,610,286
3.	The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,027,502,859
4.	The Contract Price Applicable to Subproject 6(a) will be increased by this Change Order in the amount of	$	2,188,468
5.	The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of	$	—
6.	The Contract Price Applicable to Subproject 6(a) including this Change Order will be	$	2,029,691,327

Adjustment to Contract Price Applicable to Subproject 6(b)

7.	The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was	$	457,696,000
8.	Net change for Contract Price Applicable to Subproject 6(b) by previously authorized Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37)	$	(6,158,350)
9.	The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	451,537,650
10.	The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
11.	The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order	$	—
12.	The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	45,153,765

Adjustment to Contract Price

13.	The original Contract Price for Subproject 6(a) and Subproject 6(b) was (add lines 1 and 7)	$	2,474,588,573
14.	The Contract Price prior to this Change Order was (add lines 3 and 9)	$	2,479,040,509
15.	The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	2,188,468
16.	The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,481,228,977

Adjustment to dates in Project Schedule for Subproject 6(a)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(a):N/A

Adjustment to Payment Schedule for Subproject 6(a): Yes; see Exhibit B of this Change Order

Adjustment to Minimum Acceptance Criteria for Subproject 6(a):N/A

Adjustment to Performance Guarantees for Subproject 6(a):N/A

Adjustment to Design Basis for Subproject 6(a):N/A

Other adjustments to liability or obligations of Contractor or Owner under the Agreement for Subproject 6(a): N/A

Adjustment to dates in Project Schedule for Subproject 6(b)

The following dates are modified: N/A

Adjustment to other Changed Criteria for Subproject 6(b): N/A

Adjustment to Payment Schedule for Subproject 6(b): N/A

Adjustment to Design Basis for Subproject 6(b): N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ KM Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

/s/ David Craft	/s/ Kane McIntosh
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Project Manager
Title	Title
March 22, 2021	March 16, 2021
Date of Signing	Date of Signing

EX-22.1

Exhibit 22.1

Cheniere Energy Partners, L.P.

List of Issuers and Guarantor Subsidiaries

The following entities are guarantors of the 5.625% Senior Notes due 2026, 4.500% Senior Notes due 2029 and 4.000% Senior Notes due 2031 issued by Cheniere Energy Partners, L.P.

Entity	Jurisdiction of Organization	Role
Cheniere Energy Partners, L.P.	Delaware	Issuer
Cheniere Energy Investments, LLC	Delaware	Guarantor
Sabine Pass LNG-GP, LLC	Delaware	Guarantor
Sabine Pass LNG, L.P.	Delaware	Guarantor
Sabine Pass Tug Services, LLC	Delaware	Guarantor
Cheniere Pipeline GP Interests, LLC	Delaware	Guarantor
Cheniere Creole Trail Pipeline, L.P.	Delaware	Guarantor

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Jack A. Fusco, certify that:

1.    I have reviewed this quarterly report on Form 10-Q of Cheniere Energy Partners, L.P.;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)    Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d)    Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 3, 2021

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Zach Davis, certify that:

1.    I have reviewed this quarterly report on Form 10-Q of Cheniere Energy Partners, L.P.;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)    Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d)    Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 3, 2021

/s/ Zach Davis

Zach Davis

Chief Financial Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

EX-32.1

Exhibit 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

In connection with the quarterly report of Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended March 31, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: May 3, 2021

/s/ Jack A. Fusco

Jack A. Fusco

Chief Executive Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

EX-32.2

Exhibit 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

In connection with the quarterly report of Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended March 31, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Zach Davis, Chief Financial Officer of Cheniere Energy Partners GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: May 3, 2021

/s/ Zach Davis

Zach Davis

Chief Financial Officer of

Cheniere Energy Partners GP, LLC, the general partner of

Cheniere Energy Partners, L.P.

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2021	Apr. 30, 2021
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2021
Document Transition Report	false
Entity File Number	001-33366
Entity Registrant Name	Cheniere Energy Partners, L.P.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	20-5913059
Entity Address, Address Line One	700 Milam Street
Entity Address, Address Line Two	Suite 1900
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	375-5000
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Trading Symbol	CQP
Security Exchange Name	NYSEAMER
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Units, Units Outstanding		484,021,123
Entity Central Index Key	0001383650
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q1

XML

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2021	Mar. 31, 2020
Revenues
Revenues		$ 1,963	$ 1,718
Operating costs and expenses
Cost of sales (excluding items shown separately below)		948	699
Cost of sales—affiliate		42	0
Operating and maintenance expense		149	152
Operating and maintenance expense—affiliate		34	33
Operating and maintenance expense—related party		10	0
General and administrative expense		2	2
General and administrative expense—affiliate		21	25
Depreciation and amortization expense		139	138
Impairment expense and loss on disposal of assets		0	5
Total operating costs and expenses		1,345	1,054
Income from operations		618	664
Other income (expense)
Interest expense, net of capitalized interest		(217)	(234)
Loss on modification or extinguishment of debt		(54)	(1)
Other income, net		0	6
Total other expense		(271)	(229)
Net income		$ 347	$ 435
Basic and diluted net income per common unit		$ 0.64	$ 0.84
Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation		484.0	348.6
LNG [Member]
Revenues
Revenues		$ 1,669	$ 1,449
Revenues from contracts with customers	[1]	1,669	1,449
LNG—affiliate [Member]
Revenues
Revenues from contracts with customers		214	188
Regasification [Member]
Revenues
Revenues from contracts with customers		67	67
Other [Member]
Revenues
Revenues from contracts with customers		$ 13	$ 14

[1] LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three months ended March 31, 2020, we recognized $16 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, which would have been recognized subsequent to March 31, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have such revenues during the three months ended March 31, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents	$ 1,219	$ 1,210
Restricted cash	123	97
Accounts and other receivables, net	373	318
Accounts receivable—affiliate	98	184
Advances to affiliate	127	144
Inventory	103	107
Derivative assets	16	14
Other current assets	59	61
Other current assets—affiliate	2	0
Total current assets	2,120	2,135
Property, plant and equipment, net	16,734	16,723
Operating lease assets, net	97	99
Debt issuance costs, net	16	17
Non-current derivative assets	9	11
Other non-current assets, net	177	160
Total assets	19,153	19,145
Current liabilities
Accounts payable	11	12
Accrued liabilities	704	658
Accrued liabilities—related party	3	4
Current debt	850	0
Due to affiliates	31	53
Deferred revenue	101	137
Deferred revenue—affiliate	5	1
Current operating lease liabilities	8	7
Derivative liabilities	26	11
Total current liabilities	1,739	883
Long-term debt, net	16,732	17,580
Non-current operating lease liabilities	89	90
Non-current derivative liabilities	42	35
Other non-current liabilities	0	1
Other non-current liabilities—affiliate	16	17
Partners’ equity
Common unitholders’ interest (484.0 million units issued and outstanding at both March 31, 2021 and December 31, 2020)	738	714
General partner’s interest (2% interest with 9.9 million units issued and outstanding at March 31, 2021 and December 31, 2020)	(203)	(175)
Total partners’ equity	535	539
Total liabilities and partners’ equity	$ 19,153	$ 19,145

XML

Consolidated Balance Sheets Parentheticals - shares shares in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2019
Cheniere Partners [Member]
General Partner Ownership Interest Percentage	2.00%	2.00%
Common Units [Member]
Limited Partners' Capital Account, Units Outstanding	484.0	484.0	348.6	348.6
General Partner [Member]
General Partners' Capital Account, Units Outstanding	9.9	9.9	9.9	9.9

XML

Consolidated Statements of Partners' Equity - USD ($) shares in Millions, $ in Millions	Total	Common Units [Member]	Subordinated Units [Member]	General Partner [Member]
Units, Outstanding, beginning of period at Dec. 31, 2019		348.6	135.4
Partners' equity, beginning of period at Dec. 31, 2019	$ 715	$ 1,792	$ (996)	$ (81)
General partner units, Outstanding, beginning of period at Dec. 31, 2019				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	435	307	119	$ 9
Distributions		$ (220)	$ (85)	(25)
Units, Outstanding, end of period at Mar. 31, 2020		348.6	135.4
Partners' equity, end of period at Mar. 31, 2020	820	$ 1,879	$ (962)	$ (97)
General partner units, Outstanding, end of period at Mar. 31, 2020				9.9
Units, Outstanding, beginning of period at Dec. 31, 2020		484.0	0.0
Partners' equity, beginning of period at Dec. 31, 2020	539	$ 714	$ 0	$ (175)
General partner units, Outstanding, beginning of period at Dec. 31, 2020				9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	347	340	$ 0	$ 7
Distributions		$ (316)		(35)
Units, Outstanding, end of period at Mar. 31, 2021		484.0	0.0
Partners' equity, end of period at Mar. 31, 2021	$ 535	$ 738	$ 0	$ (203)
General partner units, Outstanding, end of period at Mar. 31, 2021				9.9

XML

Consolidated Statements of Partners' Equity Parentheticals - $ / shares	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Common Units [Member]
Distributions Paid, Per Unit	$ 0.655	$ 0.63
Subordinated Units [Member]
Distributions Paid, Per Unit		$ 0.63

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Cash flows from operating activities
Net Income	$ 347	$ 435
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	139	138
Amortization of debt issuance costs, premium and discount	8	9
Loss on modification or extinguishment of debt	54	1
Total losses (gains) on derivatives, net	2	(21)
Net cash provided by settlement of derivative instruments	20	5
Impairment expense and loss on disposal of assets	0	5
Other	3	3
Changes in operating assets and liabilities:
Accounts and other receivables, net	(56)	38
Accounts receivable—affiliate	86	67
Advances to affiliate	18	17
Inventory	4	19
Accounts payable and accrued liabilities	24	(100)
Accrued liabilities—related party	(1)	0
Due to affiliates	(20)	(13)
Deferred revenue	(36)	(61)
Other, net	(6)	(3)
Other, net—affiliate	2	(4)
Net cash provided by operating activities	588	535
Cash flows from investing activities
Property, plant and equipment, net	(146)	(317)
Net cash used in investing activities	(146)	(317)
Cash flows from financing activities
Proceeds from issuances of debt	1,500	0
Repayments of debt	(1,500)	0
Debt issuance and other financing costs	(19)	(7)
Debt extinguishment costs	(40)	0
Distributions to owners	(351)	(330)
Other	3	0
Net cash used in financing activities	(407)	(337)
Net increase (decrease) in cash, cash equivalents and restricted cash	35	(119)
Cash, cash equivalents and restricted cash—beginning of period	1,307	1,962
Cash, cash equivalents and restricted cash—end of period	$ 1,342	$ 1,843

XML

Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2019
Balances per Consolidated Balance Sheets:
Cash and cash equivalents	$ 1,219	$ 1,210
Restricted cash	123	97
Total cash, cash equivalents and restricted cash	$ 1,342	$ 1,307	$ 1,843	$ 1,962

XML

Nature of Operations and Basis of Presentation

3 Months Ended

Mar. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

The Sabine Pass LNG terminal is located in Cameron Parish, Louisiana, on the Sabine-Neches Waterway less than four miles from the Gulf Coast. Through our subsidiary, SPL, we are currently operating five natural gas liquefaction Trains and are constructing one additional Train that is expected to be substantially completed in the first half of 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”) at the Sabine Pass LNG terminal. Through our subsidiary, SPLNG, we own and operate regasification facilities at the Sabine Pass LNG terminal, which includes pre-existing infrastructure of five LNG storage tanks, two marine berths and vaporizers and an additional marine berth that is under construction. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG terminal with a number of large interstate pipelines (the “Creole Trail Pipeline”).

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 fiscal year ended December 31, 2020.

Results of operations for the three months ended March 31, 2021 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2021.

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

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

XML

Unitholders' Equity

3 Months Ended

Mar. 31, 2021

Partners' Capital Notes [Abstract]

Unitholders' Equity

UNITHOLDERS’ EQUITY

The common 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 accumulated operating surplus as defined in the partnership agreement.

Although common unitholders are not obligated to fund losses of the Partnership, its capital account, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continues 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 as additional target levels are met, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.

As of March 31, 2021, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.4% by BX CQP Target Holdco L.L.C. (“BX CQP Target Holdco”) and other affiliates of The Blackstone Group

Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) and 8.0% by the public. All of our 2% general partner interest was held by Cheniere. BX CQP Target Holdco’s equity interests are 50.01% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone and 49.99% owned by BIF IV Cypress Aggregator (Delaware) LLC, an affiliate of Brookfield. The ownership of BX CQP Target Holdco, Blackstone and Brookfield are based on their most recent filings with the SEC.

XML

Restricted Cash

3 Months Ended

Mar. 31, 2021

Restricted Cash [Abstract]

Restricted Cash

RESTRICTED CASH

Restricted cash consists of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. As of March 31, 2021 and December 31, 2020, we had $123 million and $97 million of restricted cash, respectively.

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.

XML

Accounts and Other Receivables

3 Months Ended

Mar. 31, 2021

Receivables [Abstract]

Accounts and Other Receivables

ACCOUNTS AND OTHER RECEIVABLES

As of March 31, 2021 and December 31, 2020, accounts and other receivables, net consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
SPL trade receivable	$	349	$	300
Other accounts receivable	24		18
Total accounts and other receivables, net	$	373	$	318

XML

Inventory

3 Months Ended

Mar. 31, 2021

Inventory Disclosure [Abstract]

Inventory

INVENTORY

As of March 31, 2021 and December 31, 2020, inventory consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Materials	$	82	$	81
LNG	11		8
Natural gas	9		17
Other	1		1
Total inventory	$	103	$	107

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Property, Plant and Equipment

3 Months Ended

Mar. 31, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

As of March 31, 2021 and December 31, 2020, property, plant and equipment, net consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	16,909	$	16,908
LNG terminal construction-in-process	2,300		2,154
Accumulated depreciation	(2,481)		(2,344)
Total LNG terminal costs, net	16,728		16,718
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(24)		(24)
Total fixed assets, net	6		5
Property, plant and equipment, net	$	16,734	$	16,723

The following table shows depreciation expense during the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
Depreciation expense	$	138	$	137

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Derivative Instruments

3 Months Ended

Mar. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”).

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 or fair value 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 March 31, 2021 and December 31, 2020, 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
	March 31, 2021								December 31, 2020
	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)	$	(4)	$	(3)	$	(36)	$	(43)	$	1	$	(1)	$	(21)	$	(21)

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 events deriving fair value, 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 March 31, 2021 and December 31, 2020, 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 incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity, volatility and contract duration.

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 prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2021:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$(36)	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.350) - $0.168 / $(0.001)

(1)    Unobservable inputs were weighted by the relative fair value of the instruments.

Increases or decreases in basis, in isolation, would decrease or increase, respectively, the fair value of our Physical Liquefaction Supply Derivatives.

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
Balance, beginning of period	$	(21)	$	24
Realized and mark-to-market gains (losses):
Included in cost of sales	(12)		25
Purchases and settlements:
Purchases	1		1
Settlements	(4)		(3)
Transfers into Level 3, net (1)	—		2
Balance, end of period	$	(36)	$	49
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(12)	$	25

(1)    Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty on a net basis. 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 any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

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 remaining terms of the physical natural gas supply contracts range up to 10 years, some of which commence upon the satisfaction of certain events or states of affairs. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years.

The notional natural gas position of our Liquefaction Supply Derivatives was approximately 5,023 TBtu and 4,970 TBtu as of March 31, 2021 and December 31, 2020, respectively, of which 91 TBtu for each of the periods were for a natural gas supply contract that SPL has with a related party.

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 Sheets Location	March 31, 2021		December 31, 2020
Derivative assets	$	16	$	14
Non-current derivative assets	9		11
Total derivative assets	25		25
Derivative liabilities	(26)		(11)
Non-current derivative liabilities	(42)		(35)
Total derivative liabilities	(68)		(46)
Derivative liability, net	$	(43)	$	(21)

(1)    Does not include collateral posted with counterparties by us of $11 million and $4 million, which are included in other current assets in our Consolidated Balance Sheets as of March 31, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of both March 31, 2021 and December 31, 2020.

The following table shows the gain (loss) from changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Income during the three months ended March 31, 2021 and 2020 (in millions):

	Consolidated Statements of Income Location (1)	Three Months Ended March 31,
		2021		2020
Liquefaction Supply Derivatives	Cost of sales	$	(2)	$	21

(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.

Consolidated Balance Sheets 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):

	Liquefaction Supply Derivatives
As of March 31, 2021
Gross assets	$	68
Offsetting amounts	(43)
Net assets	$	25
Gross liabilities	$	(76)
Offsetting amounts	8
Net liabilities	$	(68)
As of December 31, 2020
Gross assets	$	69
Offsetting amounts	(44)
Net assets	$	25
Gross liabilities	$	(48)
Offsetting amounts	2
Net liabilities	$	(46)

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Other Non-Current Assets

3 Months Ended

Mar. 31, 2021

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS

As of March 31, 2021 and December 31, 2020, other non-current assets, net consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Advances made to municipalities for water system enhancements	$	83	$	84
Advances and other asset conveyances to third parties to support LNG terminal	33		33
Advances made under EPC and non-EPC contracts	22		9
Tax-related prepayments and receivables	17		17
Information technology service prepayments	5		6
Other	17		11
Total other non-current assets, net	$	177	$	160

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Accrued Liabilities

3 Months Ended

Mar. 31, 2021

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

As of March 31, 2021 and December 31, 2020, accrued liabilities consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Interest costs and related debt fees	$	226	$	203
Accrued natural gas purchases	382		374
LNG terminal and related pipeline costs	80		71
Other accrued liabilities	16		10
Total accrued liabilities	$	704	$	658

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Debt

3 Months Ended

Mar. 31, 2021

Debt Disclosure [Abstract]

Debt

DEBT

As of March 31, 2021 and December 31, 2020, our debt consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Long-term debt:
SPL — 4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 SPL Working Capital Facility”)	$	12,797	$	13,650
Cheniere Partners — 4.000% to 5.625% senior notes due between October 2025 and March 2031 and credit facilities (“2019 CQP Credit Facilities”)	4,100		4,100
Unamortized premium, discount and debt issuance costs, net	(165)		(170)
Total long-term debt, net	16,732		17,580
Current debt:
SPL — current portion of 6.25% senior secured notes due March 2022 (“2022 SPL Senior Notes”) (1)	853		—
Unamortized premium, discount and debt issuance costs, net	(3)		—
Total current debt	850		—
Total debt, net	$	17,582	$	17,580

(1)$147 million of the 2022 SPL Senior Notes is categorized as long-term debt because the proceeds from the expected sale of approximately $147 million aggregate principal amount of 2.95% Senior Secured Notes due 2037, expected to be issued in the second half of 2021 pursuant to a note purchase agreement entered into by SPL in February 2021, are expected to be used to refinance a portion of 2022 SPL Senior Notes.

Issuances and Redemptions

The following table shows the issuances and redemptions of long-term debt during the three months ended March 31, 2021 (in millions):

Issuances	Principal Amount Issued
CQP — 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”) (1)	$	1,500
Redemptions	Amount Redeemed
CQP — 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) (1)	$	1,500

(1)Proceeds of the 2031 CQP Senior Notes, together with cash on hand, were used to redeem all of our outstanding 2025 CQP Senior Notes, resulting in the recognition of debt extinguishment costs of $54 million for the three months ended March 31, 2021 relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2021 (in millions):

	2020 SPL Working Capital Facility (1)		2019 CQP Credit Facilities
Original facility size	$	1,200	$	1,500
Less:
Outstanding balance	—		—
Commitments prepaid or terminated	—		750
Letters of credit issued	413		—
Available commitment	$	787	$	750
Priority ranking	Senior secured		Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Weighted average interest rate of outstanding balance	n/a		n/a
Maturity date	March 19, 2025		May 29, 2024

(1)The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

Restrictive Debt Covenants

The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us and our restricted subsidiaries’ ability to make certain investments or pay dividends or distributions.

As of March 31, 2021, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

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

	Three Months Ended March 31,
	2021		2020
Total interest cost	$	247	$	254
Capitalized interest	(30)		(20)
Total interest expense, net of capitalized interest	$	217	$	234

Fair Value Disclosures

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

	March 31, 2021				December 31, 2020
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	16,950	$	18,680	$	16,950	$	19,113
Senior notes — Level 3 (2)	800		953		800		1,036
Credit facilities (3)	—		—		—		—

(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

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

(3)The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.

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Revenues from Contracts with Customers

3 Months Ended

Mar. 31, 2021

Revenue from Contract with Customer [Abstract]

Revenues from Contracts with Customers

REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers during the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
LNG revenues (1)	$	1,669	$	1,449
LNG revenues—affiliate	214		188
Regasification revenues	67		67
Other revenues	13		14
Total revenues	$	1,963	$	1,718

(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three months ended March 31, 2020, we recognized $16 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, which would have been recognized subsequent to March 31, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have such revenues during the three months ended March 31, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

Contract Assets

The following table shows our contract assets, net, which are classified as other current assets and other non-current assets, net on our Consolidated Balance Sheets (in millions):

	March 31,		December 31,
	2021		2020
Contract assets, net	$	1	$	—

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the three months ended March 31, 2021 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

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):

	Three Months Ended March 31, 2021
Deferred revenues, beginning of period	$	137
Cash received but not yet recognized in revenue	101
Revenue recognized from prior period deferral	(137)
Deferred revenues, end of period	$	101

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

	Three Months Ended March 31, 2021
Deferred revenues—affiliate, beginning of period	$	1
Cash received but not yet recognized in revenue	5
Revenue recognized from prior period deferral	(1)
Deferred revenues—affiliate, end of period	$	5

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 March 31, 2021 and December 31, 2020:

	March 31, 2021			December 31, 2020
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	51.4	9	$	52.1	9
LNG revenues—affiliate	0.2		3	0.1		1
Regasification revenues	2.1		5	2.1		5
Total revenues	$	53.7		$	54.3

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

We have elected the following 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)The table above excludes substantially all variable consideration under our SPAs and TUAs. 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 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. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately 51% and 44% of our LNG revenues from contracts included in the table above during the three months ended March 31, 2021 and 2020, respectively, were related to variable consideration received from customers. During each of the three months ended March 31, 2021 and 2020, approximately 3% of our regasification revenues were related to variable consideration received from customers.

We may enter 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.

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Related Party Transactions

3 Months Ended

Mar. 31, 2021

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
LNG revenues—affiliate
Cheniere Marketing Agreements	$	210	$	182
Contracts for Sale and Purchase of Natural Gas and LNG	4		6
Total LNG revenues—affiliate	214		188
Cost of sales—affiliate
Cheniere Marketing Agreements	34		—
Contracts for Sale and Purchase of Natural Gas and LNG	8		—
Total Cost of sales—affiliate	42		—
Operating and maintenance expense—affiliate
Services Agreements	34		33
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	10		—
General and administrative expense—affiliate
Services Agreements	21		25

As of March 31, 2021 and December 31, 2020, we had $98 million and $184 million, respectively, of accounts receivable—affiliate, under the agreements described below.

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. (“Bechtel”) had control of, and was commissioning, Train 5 of the Liquefaction Project.

Cheniere Marketing Letter Agreements

In February 2021, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 31 cargoes to be delivered between 2021 and 2026 at a price of 115% of Henry Hub plus $1.72 per MMBtu.

In December 2020, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 30 cargoes scheduled for delivery in 2021 at a price of 115% of Henry Hub plus $0.728 per MMBtu.

In December 2019, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 43 cargoes that were delivered in 2020 at a price of 115% of Henry Hub plus $1.67 per MMBtu.

Facility Swap Agreement

In August 2020, SPL entered into an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be (i) 115% of the applicable natural gas feedstock purchase price or (ii) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.

Natural Gas Transportation and Storage Agreements

SPL is party to various natural gas transportation and storage agreements and CTPL is party to an operational balancing agreement with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to 10 years with extension rights. This related party is partially owned by Brookfield, who acquired a portion of our limited partner interests in September 2020 through its purchase of a portion of BX CQP Target Holdco’s equity interests. We recorded operating and maintenance expense—related party of $10 million in the three months ended March 31, 2021 and accrued liabilities—related party of $3 million and $4 million as of March 31, 2021 and December 31, 2020, respectively, with this related party.

Services Agreements

As of March 31, 2021 and December 31, 2020, we had $127 million and $144 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 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 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.

CTPL MSA

CTPL has a management services agreement (the “CTPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the operations and business of the Creole Trail Pipeline, excluding those matters provided for under the CTPL O&M Agreement. The services include, among other services, exercising the day-to-day management of CTPL’s affairs and business, managing CTPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of CTPL’s business and operations, providing contract administration services for all contracts associated with the Creole Trail Pipeline and obtaining insurance. CTPL is required to reimburse Cheniere Terminals for the aggregate of all costs and expenses incurred in the course of performing the services under the CTPL MSA.

Natural Gas Supply Agreement

SPL is party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. This related party is partially owned by Blackstone, who also partially owns our limited partner interests. The term of the agreement is for five years, which can commence no earlier than November 1, 2021 and no later than November 1, 2022, following the achievement of contractually-defined conditions precedent.

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 advanced payments of annual ad valorem taxes 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 shall grant SPLNG a dollar-for-dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal as early as 2019. Beginning in September 2007, SPLNG entered into various agreements with Cheniere Marketing, pursuant to which Cheniere Marketing would pay SPLNG additional TUA revenues equal to any and all amounts payable by SPLNG to the Cameron Parish taxing authorities under the CEAs. In exchange for such amounts received as TUA revenues from Cheniere Marketing, SPLNG will make payments to Cheniere Marketing equal to the dollar-for-dollar credit applied to the ad valorem tax levied against the Sabine Pass LNG terminal in the given year.

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 obligations. We had $3 million and $2 million in due to affiliates and $16 million and $17 million of other non-current liabilities—affiliate resulting from these payments received from Cheniere Marketing as of March 31, 2021 and December 31, 2020, 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.

SPL has an agreement with CCL that allows them to sell and purchase natural gas from each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. Natural gas sold under this agreement is recorded as LNG revenues—affiliate.

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with Cheniere Terminals 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 Cheniere Terminals a portion of its future revenues. Accordingly, Tug Services distributed $1 million during each of the three months ended March 31, 2021 and 2020 to Cheniere Terminals, 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 months ended March 31, 2021 and 2020.

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 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.

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Net Income per Common Unit

3 Months Ended

Mar. 31, 2021

Earnings Per Share [Abstract]

Net Income per Common Unit

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 (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statements of Partners’ Equity. On April 26, 2021, we declared a $0.660 distribution per common unit and the related distribution to our general partner and IDR holders that will be paid on May 14, 2021 to unitholders of record as of May 6, 2021 for the period from January 1, 2021 to March 31, 2021.

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

The 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 March 31, 2021
Net income	$	347
Declared distributions	356		320		—		7		29
Assumed allocation of undistributed net loss (1)	$	(9)	(8)		—		—		—
Assumed allocation of net income			$	312	$	—	$	7	$	29
Weighted average units outstanding			484.0		—
Basic and diluted net income per unit			$	0.64	$	—
Three Months Ended March 31, 2020
Net income	$	435
Declared distributions	336		223		87		6		20
Assumed allocation of undistributed net income (1)	$	99	70		27		2		—
Assumed allocation of net income			$	293	$	114	$	8	$	20
Weighted average units outstanding			348.6		135.4
Basic and diluted net income per unit			$	0.84	$	0.84

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

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Customer Concentration

3 Months Ended

Mar. 31, 2021

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

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

	Percentage of Total Revenues from External Customers		Percentage of Accounts Receivable, Net from External Customers
	Three Months Ended March 31,		March 31,	December 31,
	2021	2020	2021	2020
Customer A	27%	28%	23%	31%
Customer B	15%	15%	15%	21%
Customer C	18%	15%	25%	*
Customer D	14%	16%	*	22%
Customer E	*	*	19%	*
Customer F	*	11%	*	*

* Less than 10%

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2021

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31,
	2021		2020
Cash paid during the period for interest on debt, net of amounts capitalized	$	185	$	211

The balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate) was $229 million and $219 million as of March 31, 2021 and 2020, respectively.

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Nature of Operations and Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation, Policy

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 fiscal year ended December 31, 2020.

Income Taxes, Policy

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

Recent Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The optional expedients were available to be used upon issuance of this guidance but we have not yet applied the guidance because we have not yet modified any of our existing contracts for reference rate reform. Once we apply an optional expedient to a modified contract and adopt this standard, the guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time the optional expedients are no longer available.

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Accounts and Other Receivables (Tables)

3 Months Ended

Mar. 31, 2021

Receivables [Abstract]

Schedule of Accounts and Other Receivables

As of March 31, 2021 and December 31, 2020, accounts and other receivables, net consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
SPL trade receivable	$	349	$	300
Other accounts receivable	24		18
Total accounts and other receivables, net	$	373	$	318

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Inventory (Tables)

3 Months Ended

Mar. 31, 2021

Inventory Disclosure [Abstract]

Schedule of Inventory

As of March 31, 2021 and December 31, 2020, inventory consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Materials	$	82	$	81
LNG	11		8
Natural gas	9		17
Other	1		1
Total inventory	$	103	$	107

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

As of March 31, 2021 and December 31, 2020, property, plant and equipment, net consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
LNG terminal costs
LNG terminal and interconnecting pipeline facilities	$	16,909	$	16,908
LNG terminal construction-in-process	2,300		2,154
Accumulated depreciation	(2,481)		(2,344)
Total LNG terminal costs, net	16,728		16,718
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(24)		(24)
Total fixed assets, net	6		5
Property, plant and equipment, net	$	16,734	$	16,723

Schedule of Depreciation and Offsets to LNG Terminal Costs

The following table shows depreciation expense during the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
Depreciation expense	$	138	$	137

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value of Derivative Assets and Liabilities

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 March 31, 2021 and December 31, 2020, 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
	March 31, 2021								December 31, 2020
	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)	$	(4)	$	(3)	$	(36)	$	(43)	$	1	$	(1)	$	(21)	$	(21)

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of March 31, 2021:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Physical Liquefaction Supply Derivatives	$(36)	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.350) - $0.168 / $(0.001)

(1)    Unobservable inputs were weighted by the relative fair value of the instruments.

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives during the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
Balance, beginning of period	$	(21)	$	24
Realized and mark-to-market gains (losses):
Included in cost of sales	(12)		25
Purchases and settlements:
Purchases	1		1
Settlements	(4)		(3)
Transfers into Level 3, net (1)	—		2
Balance, end of period	$	(36)	$	49
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(12)	$	25

(1)    Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

Fair Value of Derivative Instruments by Balance Sheet Location

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 Sheets Location	March 31, 2021		December 31, 2020
Derivative assets	$	16	$	14
Non-current derivative assets	9		11
Total derivative assets	25		25
Derivative liabilities	(26)		(11)
Non-current derivative liabilities	(42)		(35)
Total derivative liabilities	(68)		(46)
Derivative liability, net	$	(43)	$	(21)

(1)    Does not include collateral posted with counterparties by us of $11 million and $4 million, which are included in other current assets in our Consolidated Balance Sheets as of March 31, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of both March 31, 2021 and December 31, 2020.

Derivative Instruments, Gain (Loss)

The following table shows the gain (loss) from changes in the fair value, settlements and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Income during the three months ended March 31, 2021 and 2020 (in millions):

	Consolidated Statements of Income Location (1)	Three Months Ended March 31,
		2021		2020
Liquefaction Supply Derivatives	Cost of sales	$	(2)	$	21

(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.

Derivative Net Presentation on Consolidated Balance Sheets

The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions):

	Liquefaction Supply Derivatives
As of March 31, 2021
Gross assets	$	68
Offsetting amounts	(43)
Net assets	$	25
Gross liabilities	$	(76)
Offsetting amounts	8
Net liabilities	$	(68)
As of December 31, 2020
Gross assets	$	69
Offsetting amounts	(44)
Net assets	$	25
Gross liabilities	$	(48)
Offsetting amounts	2
Net liabilities	$	(46)

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Other Non-Current Assets (Tables)

3 Months Ended

Mar. 31, 2021

Other Assets, Noncurrent [Abstract]

Schedule of Other Non-Current Assets

As of March 31, 2021 and December 31, 2020, other non-current assets, net consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Advances made to municipalities for water system enhancements	$	83	$	84
Advances and other asset conveyances to third parties to support LNG terminal	33		33
Advances made under EPC and non-EPC contracts	22		9
Tax-related prepayments and receivables	17		17
Information technology service prepayments	5		6
Other	17		11
Total other non-current assets, net	$	177	$	160

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Accrued Liabilities (Tables)

3 Months Ended

Mar. 31, 2021

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

As of March 31, 2021 and December 31, 2020, accrued liabilities consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Interest costs and related debt fees	$	226	$	203
Accrued natural gas purchases	382		374
LNG terminal and related pipeline costs	80		71
Other accrued liabilities	16		10
Total accrued liabilities	$	704	$	658

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Debt (Tables)

3 Months Ended

Mar. 31, 2021

Debt Disclosure [Abstract]

Schedule of Debt Instruments

As of March 31, 2021 and December 31, 2020, our debt consisted of the following (in millions):

	March 31,		December 31,
	2021		2020
Long-term debt:
SPL — 4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 SPL Working Capital Facility”)	$	12,797	$	13,650
Cheniere Partners — 4.000% to 5.625% senior notes due between October 2025 and March 2031 and credit facilities (“2019 CQP Credit Facilities”)	4,100		4,100
Unamortized premium, discount and debt issuance costs, net	(165)		(170)
Total long-term debt, net	16,732		17,580
Current debt:
SPL — current portion of 6.25% senior secured notes due March 2022 (“2022 SPL Senior Notes”) (1)	853		—
Unamortized premium, discount and debt issuance costs, net	(3)		—
Total current debt	850		—
Total debt, net	$	17,582	$	17,580

(1)$147 million of the 2022 SPL Senior Notes is categorized as long-term debt because the proceeds from the expected sale of approximately $147 million aggregate principal amount of 2.95% Senior Secured Notes due 2037, expected to be issued in the second half of 2021 pursuant to a note purchase agreement entered into by SPL in February 2021, are expected to be used to refinance a portion of 2022 SPL Senior Notes.

Schedule of Debt Issuances And Redemptions

The following table shows the issuances and redemptions of long-term debt during the three months ended March 31, 2021 (in millions):

Issuances	Principal Amount Issued
CQP — 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”) (1)	$	1,500
Redemptions	Amount Redeemed
CQP — 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) (1)	$	1,500

(1)Proceeds of the 2031 CQP Senior Notes, together with cash on hand, were used to redeem all of our outstanding 2025 CQP Senior Notes, resulting in the recognition of debt extinguishment costs of $54 million for the three months ended March 31, 2021 relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2021 (in millions):

	2020 SPL Working Capital Facility (1)		2019 CQP Credit Facilities
Original facility size	$	1,200	$	1,500
Less:
Outstanding balance	—		—
Commitments prepaid or terminated	—		750
Letters of credit issued	413		—
Available commitment	$	787	$	750
Priority ranking	Senior secured		Senior secured
Interest rate on available balance	LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%		LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%
Weighted average interest rate of outstanding balance	n/a		n/a
Maturity date	March 19, 2025		May 29, 2024

(1)The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

Schedule of Interest Expense

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

	Three Months Ended March 31,
	2021		2020
Total interest cost	$	247	$	254
Capitalized interest	(30)		(20)
Total interest expense, net of capitalized interest	$	217	$	234

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	March 31, 2021				December 31, 2020
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	16,950	$	18,680	$	16,950	$	19,113
Senior notes — Level 3 (2)	800		953		800		1,036
Credit facilities (3)	—		—		—		—

(1)The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

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

(3)The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty

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Revenues from Contracts with Customers (Tables)

3 Months Ended

Mar. 31, 2021

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table represents a disaggregation of revenue earned from contracts with customers during the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
LNG revenues (1)	$	1,669	$	1,449
LNG revenues—affiliate	214		188
Regasification revenues	67		67
Other revenues	13		14
Total revenues	$	1,963	$	1,718

(1)LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three months ended March 31, 2020, we recognized $16 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, which would have been recognized subsequent to March 31, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have such revenues during the three months ended March 31, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

Contract with Customer, Asset

The following table shows our contract assets, net, which are classified as other current assets and other non-current assets, net on our Consolidated Balance Sheets (in millions):

	March 31,		December 31,
	2021		2020
Contract assets, net	$	1	$	—

Contract Balances Reconciliation

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

	Three Months Ended March 31, 2021
Deferred revenues, beginning of period	$	137
Cash received but not yet recognized in revenue	101
Revenue recognized from prior period deferral	(137)
Deferred revenues, end of period	$	101

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

	Three Months Ended March 31, 2021
Deferred revenues—affiliate, beginning of period	$	1
Cash received but not yet recognized in revenue	5
Revenue recognized from prior period deferral	(1)
Deferred revenues—affiliate, end of period	$	5

Transaction Price Allocated to Future Performance Obligations

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 March 31, 2021 and December 31, 2020:

	March 31, 2021			December 31, 2020
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	51.4	9	$	52.1	9
LNG revenues—affiliate	0.2		3	0.1		1
Regasification revenues	2.1		5	2.1		5
Total revenues	$	53.7		$	54.3

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

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2021

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income for the three months ended March 31, 2021 and 2020 (in millions):

	Three Months Ended March 31,
	2021		2020
LNG revenues—affiliate
Cheniere Marketing Agreements	$	210	$	182
Contracts for Sale and Purchase of Natural Gas and LNG	4		6
Total LNG revenues—affiliate	214		188
Cost of sales—affiliate
Cheniere Marketing Agreements	34		—
Contracts for Sale and Purchase of Natural Gas and LNG	8		—
Total Cost of sales—affiliate	42		—
Operating and maintenance expense—affiliate
Services Agreements	34		33
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	10		—
General and administrative expense—affiliate
Services Agreements	21		25

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Net Income per Common Unit (Tables)

3 Months Ended

Mar. 31, 2021

Earnings Per Share [Abstract]

Schedule of Net Income per Common Unit

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 March 31, 2021
Net income	$	347
Declared distributions	356		320		—		7		29
Assumed allocation of undistributed net loss (1)	$	(9)	(8)		—		—		—
Assumed allocation of net income			$	312	$	—	$	7	$	29
Weighted average units outstanding			484.0		—
Basic and diluted net income per unit			$	0.64	$	—
Three Months Ended March 31, 2020
Net income	$	435
Declared distributions	336		223		87		6		20
Assumed allocation of undistributed net income (1)	$	99	70		27		2		—
Assumed allocation of net income			$	293	$	114	$	8	$	20
Weighted average units outstanding			348.6		135.4
Basic and diluted net income per unit			$	0.84	$	0.84

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

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Customer Concentration (Tables)

3 Months Ended

Mar. 31, 2021

Risks and Uncertainties [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

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

	Percentage of Total Revenues from External Customers		Percentage of Accounts Receivable, Net from External Customers
	Three Months Ended March 31,		March 31,	December 31,
	2021	2020	2021	2020
Customer A	27%	28%	23%	31%
Customer B	15%	15%	15%	21%
Customer C	18%	15%	25%	*
Customer D	14%	16%	*	22%
Customer E	*	*	19%	*
Customer F	*	11%	*	*

* Less than 10%

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Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2021

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Three Months Ended March 31,
	2021		2020
Cash paid during the period for interest on debt, net of amounts capitalized	$	185	$	211

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Nature of Operations and Basis of Presentation (Details)	3 Months Ended
	Mar. 31, 2021 item milliontonnes / yr unit mi trains
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains Operating | trains	5
Number of Liquefaction LNG Trains Constructing | trains	1
Total Production Capability | milliontonnes / yr	30
Number Of LNG Storage Tanks | unit	5
Number of Marine Berths Operating | item	2
Number of Marine Berths Constructing | item	1
Creole Trail Pipeline [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length of Natural Gas Pipeline | mi	94

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Unitholders' Equity (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Maximum [Member]
Other Ownership Interests [Line Items]
Number of days after quarter end distribution is paid	45 days
General Partner [Member] | Minimum [Member]
Other Ownership Interests [Line Items]
Distributions entitled by General Partner, Percentage	2.00%
Incentive Distribution, Quarterly Distribution Additional Target Percentage	15.00%
General Partner [Member] | Maximum [Member]
Other Ownership Interests [Line Items]
Incentive Distribution, Quarterly Distribution Additional Target Percentage	50.00%
Cheniere Partners [Member]
Other Ownership Interests [Line Items]
General Partner Ownership Interest Percentage	2.00%	2.00%
Cheniere [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	48.60%
General Partner Ownership Interest Percentage	100.00%
BX CQP Target Holdco LLC and Other Blackstone and Brookfield Affiliates [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	41.40%
Public [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	8.00%
BIP Chinook Holdco LLC [Member] | BX CQP Target Holdco LLC [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	50.01%
BIF IV Cypress Aggregator (Delaware) LLC [Member] | BX CQP Target Holdco LLC [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	49.99%

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Restricted Cash (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	$ 123	$ 97
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Current restricted cash	$ 123	$ 97

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Accounts and Other Receivables (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Receivables [Abstract]
SPL trade receivable	$ 349	$ 300
Other accounts receivable	24	18
Total accounts and other receivables, net	$ 373	$ 318

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Inventory (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Inventory [Line Items]
Inventory	$ 103	$ 107
Materials [Member]
Inventory [Line Items]
Inventory	82	81
LNG [Member]
Inventory [Line Items]
Inventory	11	8
Natural gas [Member]
Inventory [Line Items]
Inventory	9	17
Other [Member]
Inventory [Line Items]
Inventory	$ 1	$ 1

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Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 16,734	$ 16,723
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(2,481)	(2,344)
Property, plant and equipment, net	16,728	16,718
LNG terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	16,909	16,908
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,300	2,154
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	30	29
Accumulated depreciation	(24)	(24)
Property, plant and equipment, net	$ 6	$ 5

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Property, Plant and Equipment - Schedule of Depreciation and Offsets to LNG Terminal Costs (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Property, Plant and Equipment [Abstract]
Depreciation	$ 138	$ 137

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Derivative Instruments - Narrative (Details) - tbtu	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	5,023	4,970
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	10 years
Financial Liquefaction Supply Derivatives | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	3 years
SPL [Member] | Natural Gas Supply Agreement [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	91	91

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (43)	$ (21)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(4)	1
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(3)	(1)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (36)	$ (21)

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Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - USD ($)		3 Months Ended
		Mar. 31, 2021	Dec. 31, 2020
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability		$ (43,000,000)	$ (21,000,000)
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability		(36,000,000)	$ (21,000,000)
Physical Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability		(36,000,000)
Physical Liquefaction Supply Derivatives [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	(0.350)
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	0.168
Physical Liquefaction Supply Derivatives [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	$ (0.001)

[1] Unobservable inputs were weighted by the relative fair value of the instruments.

XML

Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2021	Mar. 31, 2020
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (21)	$ 24
Realized and mark-to-market gains (losses):
Included in cost of sales		(12)	25
Purchases and settlements:
Purchases		1	1
Settlements		(4)	(3)
Transfers into Level 3, net	[1]	0	2
Balance, end of period		(36)	49
Change in unrealized gains (losses) relating to instruments still held at end of period		$ (12)	$ 25

[1] Transferred into Level 3 as a result of unobservable market, or out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Mar. 31, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Derivative assets		$ 16	$ 14
Non-current derivative assets		9	11
Total derivative assets	[1]	25	25
Derivative liabilities		(26)	(11)
Non-current derivative liabilities		(42)	(35)
Total derivative liabilities	[1]	(68)	(46)
Derivative liability, net	[1]	(43)	(21)
Derivative, collateral posted by us		11	4
Natural Gas Supply Agreement [Member]
Derivatives, Fair Value [Line Items]
Derivative liability, net		0	0
Derivative assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	16	14
Non-current derivative assets [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative assets	[1]	9	11
Derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	(26)	(11)
Non-current derivative liabilities [Member]
Derivatives, Fair Value [Line Items]
Non-current derivative liabilities	[1]	$ (42)	$ (35)

[1] Does not include collateral posted with counterparties by us of $11 million and $4 million, which are included in other current assets in our Consolidated Balance Sheets as of March 31, 2021 and December 31, 2020, respectively. Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of both March 31, 2021 and December 31, 2020.

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Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2021	Mar. 31, 2020
Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ (2)	$ 21

[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.

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Derivative Instruments - Balance Sheet Presentation Table (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (43)	$ (21)
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	68	69
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	(43)	(44)
Derivative Assets (Liabilities), at Fair Value, Net	25	25
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(76)	(48)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	8	2
Derivative Assets (Liabilities), at Fair Value, Net	$ (68)	$ (46)

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Other Non-Current Assets (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Other Assets, Noncurrent [Abstract]
Advances made to municipalities for water system enhancements	$ 83	$ 84
Advances and other asset conveyances to third parties to support LNG terminal	33	33
Advances made under EPC and non-EPC contracts	22	9
Tax-related prepayments and receivables	17	17
Information technology service prepayments	5	6
Other	17	11
Other non-current assets, net	$ 177	$ 160

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Accrued Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Accrued Liabilities, Current [Abstract]
Interest costs and related debt fees	$ 226	$ 203
Accrued natural gas purchases	382	374
LNG terminal and related pipeline costs	80	71
Other accrued liabilities	16	10
Total accrued liabilities	$ 704	$ 658

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Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions		Mar. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Long-term Debt, Net		$ 16,732	$ 17,580
Current debt		850	0
Total Debt, Net		17,582	17,580
Long-term Debt [Member]
Debt Instrument [Line Items]
Unamortized premium, discount and debt issuance costs, net		(165)	(170)
Current Debt
Debt Instrument [Line Items]
Unamortized premium, discount and debt issuance costs, net		(3)	0
2022 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long Term Portion of Current Senior Notes		147
2.95% 2037 SPL Senior Secured Notes
Debt Instrument [Line Items]
Debt Instrument, Face Amount		147
SPL [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		12,797	13,650
Current portion of senior secured notes	[1]	$ 853	0
SPL [Member] | Senior Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.20%
SPL [Member] | Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.25%
SPL [Member] | 2022 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.25%
SPL [Member] | 2.95% 2037 SPL Senior Secured Notes
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.95%
Cheniere Partners [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 4,100	$ 4,100
Cheniere Partners [Member] | Senior Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.00%
Cheniere Partners [Member] | Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.625%

[1] $147 million of the 2022 SPL Senior Notes is categorized as long-term debt because the proceeds from the expected sale of approximately $147 million aggregate principal amount of 2.95% Senior Secured Notes due 2037, expected to be issued in the second half of 2021 pursuant to a note purchase agreement entered into by SPL in February 2021, are expected to be used to refinance a portion of 2022 SPL Senior Notes.

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Debt - Schedule of Issuances and Redemptions (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2021	Mar. 31, 2020
Debt Instrument [Line Items]
Loss on modification or extinguishment of debt		$ (54)	$ (1)
Cheniere Partners [Member] | 2031 CQP Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.00%
Debt Instrument, Face Amount	[1]	$ 1,500
Cheniere Partners [Member] | 2025 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.25%
Repayments of Long-term Debt	[1]	$ 1,500

[1] Proceeds of the 2031 CQP Senior Notes, together with cash on hand, were used to redeem all of our outstanding 2025 CQP Senior Notes, resulting in the recognition of debt extinguishment costs of $54 million for the three months ended March 31, 2021 relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

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Debt - Credit Facilities Table (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021 USD ($) Rate
2020 SPL Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Original facility size	$ 1,200	[1]
Outstanding balance	0	[1]
Commitments prepaid or terminated	0	[1]
Letters of credit issued	413	[1]
Available commitment	$ 787	[1]
Debt Instrument, Description of Variable Rate Basis	LIBOR or base rate
Debt Instrument, Maturity Date	Mar. 19, 2025	[1]
2020 SPL Working Capital Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.10%
2020 SPL Working Capital Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%
2020 SPL Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.125%
2020 SPL Working Capital Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.75%
2020 SPL Working Capital Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.125%
2020 SPL Working Capital Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.75%
2019 CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Original facility size	$ 1,500
Outstanding balance	0
Commitments prepaid or terminated	750
Letters of credit issued	0
Available commitment	$ 750
Debt Instrument, Description of Variable Rate Basis	LIBOR or base rate
Debt Instrument, Maturity Date	May 29, 2024
2019 CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.25%
2019 CQP Credit Facilities [Member] | London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	2.125%
2019 CQP Credit Facilities [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	0.25%
2019 CQP Credit Facilities [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate | Rate	1.125%

[1] The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL pays a commitment fee equal to an annual rate of 0.1% to 0.3% (depending on the then-current rating of SPL), which accrues on the daily amount of the total commitment less the sum of (1) the outstanding principal amount of loans, (2) letters of credit issued and (3) the outstanding principal amount of swing line loans.

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Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Debt Disclosure [Abstract]
Total interest cost	$ 247	$ 254
Capitalized interest	(30)	(20)
Total interest expense, net of capitalized interest	$ 217	$ 234

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Mar. 31, 2021	Dec. 31, 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 17,582	$ 17,580
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	16,950	16,950
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	800	800
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	18,680	19,113
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[2]	953	1,036
Credit facilities [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[3]	0	0
Credit facilities [Member] | Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	[3]	$ 0	$ 0

[1] The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.

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

[3] The Level 3 estimated fair value approximates the principal amount because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty

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Revenues from Contracts with Customers - Narrative (Details)	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	51.00%	44.00%
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	3.00%	3.00%

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Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2021	Mar. 31, 2020
Disaggregation of Revenue [Line Items]
Total revenues		$ 1,963	$ 1,718
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	[1]	1,669	1,449
Total revenues		1,669	1,449
Suspension Fees and LNG Cover Damages Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		0	16
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		214	188
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		67	67
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 13	$ 14

[1] LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three months ended March 31, 2020, we recognized $16 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, which would have been recognized subsequent to March 31, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have such revenues during the three months ended March 31, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

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Revenues from Contracts with Customers - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Contract assets, net	$ 1	$ 0
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	137
Cash received but not yet recognized in revenue	101
Revenue recognized from prior period deferral	(137)
Deferred revenues, end of period	101
Deferred revenues—affiliate, beginning of period	1
Cash received but not yet recognized in revenue	5
Revenue recognized from prior period deferral	(1)
Deferred revenues—affiliate, end of period	$ 5

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Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		Mar. 31, 2021	Dec. 31, 2020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 54.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 53.7
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 52.1
Weighted Average Recognition Timing	[1]		9 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 51.4
Weighted Average Recognition Timing	[1]	9 years
LNG—affiliate [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 0.1
Weighted Average Recognition Timing	[1]		1 year
LNG—affiliate [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 0.2
Weighted Average Recognition Timing	[1]	3 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 2.1
Weighted Average Recognition Timing	[1]		5 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 2.1
Weighted Average Recognition Timing	[1]	5 years

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

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 214	$ 188
Cost of sales—affiliate	42	0
Operating and maintenance expense—affiliate	34	33
Operating and maintenance expense—related party	10	0
General and administrative expense—affiliate	21	25
Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	210	182
Cost of sales—affiliate	34	0
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	4	6
Cost of sales—affiliate	8	0
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	34	33
General and administrative expense—affiliate	21	25
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—related party	$ 10	$ 0

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Related Party Transactions - LNG Terminal Capacity Agreements (Details)	3 Months Ended
	Mar. 31, 2021 USD ($) Cargo	Dec. 31, 2020 USD ($)
Related Party Transaction [Line Items]
Accounts receivable—affiliate	$ 98,000,000	$ 184,000,000
SPL [Member] | Affiliated Entity [Member] | Facility Swap Agreement [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
SPL [Member] | Cheniere Marketing [Member] | Cheniere Marketing SPA [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 3.00
SPL [Member] | Cheniere Marketing [Member] | 2021 - 2026 Letter Agreement
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 1.72
SPL [Member] | Cheniere Marketing [Member] | 2021 - 2026 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	31
SPL [Member] | Cheniere Marketing [Member] | 2021 Letter Agreement [Member]
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 0.728
SPL [Member] | Cheniere Marketing [Member] | 2021 Letter Agreement [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	30
SPL [Member] | Cheniere Marketing [Member] | 2020 Letter Agreement
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Purchase Price Per MMBtu	$ 1.67
SPL [Member] | Cheniere Marketing [Member] | 2020 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	43

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Related Party Transactions - Service Agreements (Details) - USD ($)	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Related Party Transaction [Line Items]
Advances to Affiliate Current	$ 127,000,000	$ 144,000,000
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to Affiliate Current	127,000,000	$ 144,000,000
Cheniere Terminals [Member] | Cheniere Partners Services Agreement [Member]
Related Party Transaction [Line Items]
Quarterly non-accountable overhead reimbursement charge	$ 3,000,000
SPL [Member] | Cheniere Terminals [Member] | Management Services Agreement [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	2.40%
Related Party Transaction, Committed Monthly Fee	$ 541,667
SPL [Member] | Cheniere Investments [Member] | Operation and Maintenance Agreement [Member]
Related Party Transaction [Line Items]
Monthly fee as a percentage of capital expenditures incurred in the previous month	0.60%
Related Party Transaction, Committed Monthly Fee	$ 83,333
SPLNG [Member] | Cheniere Terminals [Member] | Management Services Agreement [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	520,000
SPLNG [Member] | Cheniere Investments [Member] | Operation and Maintenance Agreement [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Committed Monthly Fee	$ 130,000
Related Party Transaction, Bonus Percentage of Salary Entitled Upon Meeting Certain Criteria	50.00%

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Related Party Transactions - Other Agreements (Details) - USD ($)	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Related Party Transaction [Line Items]
Operating and maintenance expense—related party	$ 10,000,000	$ 0
Accrued liabilities—related party	3,000,000		$ 4,000,000
Due to affiliates	31,000,000		53,000,000
Other non-current liabilities—affiliate	16,000,000		17,000,000
LNG revenues—affiliate	214,000,000	188,000,000
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—related party	10,000,000	0
SPLNG [Member] | Cooperative Endeavor Agreements [Member]
Related Party Transaction [Line Items]
Aggregate commitment under the Agreement	$ 25,000,000
Tax Initiative Agreement Term	10 years
SPLNG [Member] | Cheniere [Member] | Tax Sharing Agreement [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	$ 0
SPLNG [Member] | Cheniere Marketing [Member] | Cooperative Endeavor Agreements [Member]
Related Party Transaction [Line Items]
Due to affiliates	3,000,000		2,000,000
Other non-current liabilities—affiliate	16,000,000		17,000,000
SPLNG [Member] | Cheniere Marketing [Member] | LNG Terminal Export Agreement [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	0	0
Tug Services [Member] | Cheniere Terminals [Member] | Terminal Marine Services Agreement [Member]
Related Party Transaction [Line Items]
General Partner Distributions	$ 1,000,000	$ 1,000,000
SPL and CTPL [Member] | Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term	10 years
Operating and maintenance expense—related party	$ 10,000,000
Accrued liabilities—related party	$ 3,000,000		$ 4,000,000
SPL [Member] | Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term	5 years
SPL [Member] | Cheniere [Member] | Tax Sharing Agreement [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	$ 0
CTPL [Member] | Cheniere [Member] | Tax Sharing Agreement [Member]
Related Party Transaction [Line Items]
Income Taxes Paid, Net	$ 0

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Net Income per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			3 Months Ended
		Apr. 26, 2021	Mar. 31, 2021	Mar. 31, 2020
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income			$ 347	$ 435
Declared distributions			356	336
Assumed allocation of undistributed net income (loss)	[1]		$ (9)	$ 99
Weighted average units outstanding			484.0	348.6
Basic and diluted net income per unit			$ 0.64	$ 0.84
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income			$ 340	$ 307
Declared distributions			320	223
Assumed allocation of undistributed net income (loss)	[1]		(8)	70
Assumed allocation of net income			$ 312	$ 293
Weighted average units outstanding			484.0	348.6
Basic and diluted net income per unit			$ 0.64	$ 0.84
Common Units [Member] | Subsequent Event [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.660
Subordinated Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income			$ 0	$ 119
Declared distributions			0	87
Assumed allocation of undistributed net income (loss)	[1]		0	27
Assumed allocation of net income			$ 0	$ 114
Weighted average units outstanding			0.0	135.4
Basic and diluted net income per unit			$ 0	$ 0.84
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income			$ 7	$ 9
Declared distributions			7	6
Assumed allocation of undistributed net income (loss)	[1]		0	2
Assumed allocation of net income			7	8
IDR [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Declared distributions			29	20
Assumed allocation of undistributed net income (loss)	[1]		0	0
Assumed allocation of net income			$ 29	$ 20

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

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Customer Concentration - Schedule of Customer Concentration (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	27.00%	28.00%
Customer A [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	23.00%		31.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15.00%	15.00%
Customer B [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15.00%		21.00%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	15.00%
Customer C [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	25.00%
Customer D [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	14.00%	16.00%
Customer D [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			22.00%
Customer E [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%
Customer F [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		11.00%

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest on debt, net of amounts capitalized	$ 185	$ 211
Balance in property, plant and equipment, net funded with accounts payable and accrued liabilities (including affiliate)	$ 229	$ 219