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 June 30, 2022

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 July 29, 2022, the registrant had 484,030,123 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 (Deficit)	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—Trade and Other Receivables, Net of Current Expected Credit Losses	8
	Note 5—Inventory	8
	Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation	9
	Note 7—Derivative Instruments	9
	Note 8—Accrued Liabilities	12
	Note 9—Debt	13
	Note 10—Revenues from Contracts with Customers	14
	Note 11—Related Party Transactions	16
	Note 12—Net Income per Common Unit	20
	Note 13—Customer Concentration	22
	Note 14—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	33
Item 4.	Controls and Procedures	33
Part II. Other Information
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 6.	Exhibits	35
	Signatures	36

i

DEFINITIONS

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

Common Industry and Other Terms

ASU	Accounting Standards Update
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
FASB	Financial Accounting Standards Board
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
IPM agreements	integrated production marketing agreements in which the gas producer sells to us gas on a global LNG index price, less a fixed liquefaction fee, shipping and other costs
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; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
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; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
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 June 30, 2022, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

Unless the context requires otherwise, references to “CQP,” “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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Revenues
LNG revenues	$	2,959	$	1,597	$	5,447	$	3,266
LNG revenues—affiliate	1,135		211		1,892		425
LNG revenues—related party	4		—		4		—
Regasification revenues	68		67		136		134
Other revenues	15		14		30		27
Total revenues	4,181		1,889		7,509		3,852
Operating costs and expenses
Cost of sales (excluding items shown separately below)	3,144		888		5,706		1,836
Cost of sales—affiliate	57		12		62		54
Cost of sales—related party	1		1		1		1
Operating and maintenance expense	191		168		361		317
Operating and maintenance expense—affiliate	41		35		79		69
Operating and maintenance expense—related party	15		12		27		22
Development expense	—		1		—		1
General and administrative expense (recovery)	(3)		3		—		5
General and administrative expense—affiliate	24		21		47		42
Depreciation and amortization expense	156		138		309		277
Other	—		6		—		6
Total operating costs and expenses	3,626		1,285		6,592		2,630
Income from operations	555		604		917		1,222
Other income (expense)
Interest expense, net of capitalized interest	(216)		(209)		(419)		(426)
Loss on modification or extinguishment of debt	—		—		—		(54)
Other income, net	3		—		3		—
Total other expense	(213)		(209)		(416)		(480)
Net income	$	342	$	395	$	501	$	742
Basic and diluted net income per common unit	$	0.25	$	0.73	$	0.13	$	1.38
Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation	484.0		484.0		484.0		484.0

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)

	June 30,		December 31,
	2022		2021
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	1,111	$	876
Restricted cash and cash equivalents	78		98
Trade and other receivables, net of current expected credit losses	723		580
Accounts receivable—affiliate	485		232
Accounts receivable—related party	—		1
Advances to affiliate	136		141
Inventory	170		176
Current derivative assets	153		21
Other current assets	104		87
Total current assets	2,960		2,212
Property, plant and equipment, net of accumulated depreciation	16,861		16,830
Operating lease assets	94		98
Debt issuance costs, net of accumulated amortization	10		12
Derivative assets	36		33
Other non-current assets, net	169		173
Total assets	$	20,130	$	19,358
LIABILITIES AND PARTNERS' EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	31	$	21
Accrued liabilities	1,576		1,073
Accrued liabilities—related party	6		4
Current debt, net of discount and debt issuance costs	1,497		—
Due to affiliates	58		67
Deferred revenue	124		155
Deferred revenue—affiliate	—		1
Current operating lease liabilities	9		8
Current derivative liabilities	478		16
Total current liabilities	3,779		1,345
Long-term debt, net of premium, discount and debt issuance costs	15,693		17,177
Operating lease liabilities	85		89
Derivative liabilities	3,178		11
Other non-current liabilities—affiliate	20		18
Partners' equity (deficit)
Common unitholders’ interest (484.0 million units issued and outstanding at both June 30, 2022 and December 31, 2021)	(2,043)		1,024
General partner’s interest (2% interest with 9.9 million units issued and outstanding at June 30, 2022 and December 31, 2021)	(582)		(306)
Total partners' equity (deficit)	(2,625)		718
Total liabilities and partners' equity (deficit)	$	20,130	$	19,358

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 (DEFICIT)

(in millions)

(unaudited)

Three and Six Months Ended June 30, 2022
	Common Unitholders’ Interest			General Partner’s Interest			Total Partners’ Deficit
	Units	Amount		Units	Amount
Balance at December 31, 2021	484.0	$	1,024	9.9	$	(306)	$	718
Net income	—	157		—	2		159
Novated IPM Agreement (see Note 14)	—	(2,712)		—	—		(2,712)
Distributions
Common units, $0.700/unit	—	(339)		—	—		(339)
General partner units	—	—		—	(56)		(56)
Balance at March 31, 2022	484.0	(1,870)		9.9	(360)		(2,230)
Net income	—	335		—	7		342
Distributions
Common units, $1.05/unit	—	(508)		—	—		(508)
General partner units	—	—		—	(229)		(229)
Balance at June 30, 2022	484.0	$	(2,043)	9.9	$	(582)	$	(2,625)

Three and Six Months Ended June 30, 2021
	Common Unitholders’ Interest			General Partner’s Interest			Total Partners’ Equity
	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
Net income	—	387		—	8		395
Distributions
Common units, $0.660/unit	—	(320)		—	—		(320)
General partner units	—	—		—	(39)		(39)
Balance at June 30, 2021	484.0	$	805	9.9	$	(234)	$	571

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)

	Six Months Ended June 30,
	2022		2021
Cash flows from operating activities
Net income	$	501	$	742
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	309		277
Amortization of debt issuance costs, premium and discount	15		15
Loss on modification or extinguishment of debt	—		54
Losses (gains) on derivative instruments, net	819		(54)
Net cash provided by (used for) settlement of derivative instruments	(37)		18
Other	16		13
Changes in operating assets and liabilities:
Trade and other receivables, net of current expected credit losses	(208)		32
Accounts receivable—affiliate	(269)		119
Advances to affiliate	7		3
Inventory	4		(9)
Accounts payable and accrued liabilities	491		(48)
Accrued liabilities—related party	2		—
Due to affiliates	5		(13)
Deferred revenue	(31)		(32)
Other, net	(39)		(49)
Other, net—affiliate	1		7
Net cash provided by operating activities	1,586		1,075
Cash flows from investing activities
Property, plant and equipment	(239)		(316)
Net cash used in investing activities	(239)		(316)
Cash flows from financing activities
Proceeds from issuances of debt	—		1,500
Redemptions and repayments of debt	—		(1,500)
Debt issuance and other financing costs	—		(20)
Debt extinguishment costs	—		(40)
Distributions to owners	(1,132)		(710)
Other	—		8
Net cash used in financing activities	(1,132)		(762)
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	215		(3)
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	974		1,307
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$	1,189	$	1,304

Balances per Consolidated Balance Sheet:

	June 30,
	2022
Cash and cash equivalents	$	1,111
Restricted cash and cash equivalents	78
Total cash, cash equivalents and restricted cash and cash equivalents	$	1,189

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

We own the natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”) which has six operational Trains, with Train 6 achieving substantial completion on February 4, 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include five LNG storage tanks, vaporizers and two marine berths, with 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”).

We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive final investment decision.

As of June 30, 2022, Cheniere owned 48.6% of our limited partner interest in the form of 239.9 million of our common units. Cheniere also owns 100% of our general partner interest and our incentive distribution rights (“IDRs”).

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of CQP have been prepared in accordance with GAAP for interim financial information and in accordance 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, 2021.

Results of operations for the three and six months ended June 30, 2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2022.

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

ASU 2020-04

In March 2020, the FASB issued 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, which entitle the unitholders to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. Although common unitholders are not obligated to fund losses of the Partnership, their 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 IDRs, which allow the general partner to receive a higher percentage of quarterly distributions of available cash from

7

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

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 we have paid to date have been made from accumulated operating surplus as defined in the partnership agreement.

As of June 30, 2022, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.4% by CQP Target Holdco L.L.C. (“CQP Target Holdco”) and other affiliates of Blackstone 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. CQP Target Holdco’s equity interests are 50.00% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone and 50.00% owned by BIF IV Cypress Aggregator (Delaware) LLC, an affiliate of Brookfield. The ownership of CQP Target Holdco, Blackstone and Brookfield are based on their most recent filings with the SEC.

NOTE 3—RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents consist 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 June 30, 2022 and December 31, 2021, we had $78 million and $98 million of restricted cash and cash equivalents, 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—TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

Trade and other receivables, net of current expected credit losses consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
Trade receivables	$	648	$	546
Other receivables	75		34
Total trade and other receivables, net of current expected credit losses	$	723	$	580

NOTE 5—INVENTORY

Inventory consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
Materials	$	95	$	86
LNG	34		45
Natural gas	41		43
Other	—		2
Total inventory	$	170	$	176

8

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 6—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
LNG terminal
Terminal and interconnecting pipeline facilities	$	19,447	$	16,973
Construction-in-process	609		2,746
Accumulated depreciation	(3,199)		(2,893)
Total LNG terminal, net of accumulated depreciation	16,857		16,826
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(26)		(25)
Total fixed assets, net of accumulated depreciation	4		4
Property, plant and equipment, net of accumulated depreciation	$	16,861	$	16,830

The following table shows depreciation expense and offsets to LNG terminal costs (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Depreciation expense	$	155	$	137	$	307	$	275
Offsets to LNG terminal costs (1)	—		—		148		—

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts, including those under SPL’s IPM agreement, for the 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, in which case such changes are capitalized.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis (in millions):

	Fair Value Measurements as of
	June 30, 2022								December 31, 2021
	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	$	(15)	$	(3,456)	$	(3,467)	$	2	$	(13)	$	38	$	27

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

9

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.

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 and volatility.

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 and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of June 30, 2022 and December 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	$(3,456)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.845) - $0.765 / $0.032
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	97% - 604% / 217%

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

(2)Spread contemplates U.S. dollar-denominated pricing.

Increases or decreases in basis or pricing spreads, 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 (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021			2022		2021
Balance, beginning of period	$	(3,162)	$	(36)		$	38	$	(21)
Realized and mark-to-market gains (losses):
Included in cost of sales	(309)		67			63		58
Purchases and settlements:
Purchases (1)	8		1			(3,549)		—
Settlements	7		1			(8)		(4)
Balance, end of period	$	(3,456)	$	33		$	(3,456)	$	33
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(309)	$	67		$	63	$	58

(1)Includes any assignments during the period.

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 and the unconditional contractual right of set-off 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 depending on the position of the derivative. 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.

10

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Liquefaction Supply Derivatives

SPL holds Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The remaining minimum terms of the Physical Liquefaction Supply Derivatives range up to 15 years, some of which commence upon the satisfaction of certain conditions precedent. The terms of the Financial Liquefaction Supply Derivatives range up to approximately two years.

The forward notional amount for our Liquefaction Supply Derivatives was approximately 5,484 TBtu and 5,194 TBtu as of June 30, 2022 and December 31, 2021, respectively, excluding notional amounts associated with extension options that were uncertain to be taken as of June 30, 2022.

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Income (in millions):

	Gain (Loss) Recognized in Consolidated Statements of Income
Consolidated Statements of Income Location (1)	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
LNG revenues	$	4	$	—	$	4	$	—
Cost of sales	(298)		56		(823)		54

(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.

Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets

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	June 30, 2022		December 31, 2021
Current derivative assets	$	153	$	21
Derivative assets	36		33
Total derivative assets	189		54
Current derivative liabilities	(478)		(16)
Derivative liabilities	(3,178)		(11)
Total derivative liabilities	(3,656)		(27)
Derivative asset (liability), net	$	(3,467)	$	27

(1)Does not include collateral posted with counterparties by us of $9 million and $7 million, as of June 30, 2022 and December 31, 2021, respectively, which are included in other current assets in our Consolidated Balance Sheets.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Consolidated Balance Sheets Presentation

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

	Liquefaction Supply Derivatives
As of June 30, 2022
Gross assets	$	232
Offsetting amounts	(43)
Net assets	$	189
Gross liabilities	$	(3,681)
Offsetting amounts	25
Net liabilities	$	(3,656)
As of December 31, 2021
Gross assets	$	79
Offsetting amounts	(25)
Net assets	$	54
Gross liabilities	$	(33)
Offsetting amounts	6
Net liabilities	$	(27)

NOTE 8—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
Natural gas purchases	$	1,160	$	786
Interest costs and related debt fees	203		180
LNG terminal and related pipeline costs	195		101
Other accrued liabilities	18		6
Total accrued liabilities	$	1,576	$	1,073

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 9—DEBT

Debt consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
SPL:
Senior Secured Notes:
5.625% due 2023	$	1,500	$	1,500
5.75% due 2024	2,000		2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.27% weighted average rate due 2037	1,282		1,282
Total SPL Senior Secured Notes	13,132		13,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Total debt - SPL	13,132		13,132
CQP:
Senior Notes:
4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
Total CQP Senior Notes	4,200		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Total debt - CQP	4,200		4,200
Total debt	17,332		17,332
Short-term debt	(1,497)		—
Unamortized premium, discount and debt issuance costs, net	(142)		(155)
Total long-term debt, net of premium, discount and debt issuance costs	$	15,693	$	17,177

Credit Facilities

Below is a summary of our credit facilities outstanding as of June 30, 2022 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities
Total facility size	$	1,200	$	750
Less:
Outstanding balance	—		—
Letters of credit issued	363		—
Available commitment	$	837	$	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%
Commitment fees on undrawn balance	0.15%		0.49%
Maturity date	March 19, 2025		May 29, 2024

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. We and SPL are restricted from making distributions under agreements governing our and SPL’s indebtedness generally until, among other requirements, deposits are made into any required debt

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

service reserve accounts and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.

As of June 30, 2022, 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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Total interest cost	$	223	$	241	$	447	$	488
Capitalized interest	(7)		(32)		(28)		(62)
Total interest expense, net of capitalized interest	$	216	$	209	$	419	$	426

Fair Value Disclosures

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

	June 30, 2022				December 31, 2021
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	16,050	$	15,429	$	16,050	$	17,496
Senior notes — Level 3 (2)	1,282		1,204		1,282		1,466

(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.

The estimated fair value of our credit facilities approximates the principal amount outstanding 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 10—REVENUES FROM CONTRACTS WITH CUSTOMERS

The following table represents a disaggregation of revenue earned from contracts with customers (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021			2022		2021
LNG revenues	$	2,955	$	1,597		$	5,443	$	3,266
LNG revenues—affiliate	1,135		211			1,892		425
LNG revenues—related party	4		—			4		—
Regasification revenues	68		67			136		134
Other revenues	15		14			30		27
Total revenues from customers	4,177		1,889			7,505		3,852
Net derivative gain (1)	4		—			4		—
Total revenues	$	4,181	$	1,889		$	7,509	$	3,852

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

Contract Assets and Liabilities

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

	June 30,		December 31,
	2022		2021
Contract assets, net of current expected credit losses	$	1	$	1

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Six Months Ended June 30, 2022
Deferred revenue, beginning of period	$	155
Cash received but not yet recognized in revenue	124
Revenue recognized from prior period deferral	(155)
Deferred revenue, end of period	$	124

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

	Six Months Ended June 30, 2022
Deferred revenue—affiliate, beginning of period	$	3
Cash received but not yet recognized in revenue	5
Revenue recognized from prior period deferral	(3)
Deferred revenue—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:

	June 30, 2022			December 31, 2021
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	52.3	9	$	49.3	9
LNG revenues—affiliate	2.1		3	2.1		3
Regasification revenues	1.7		2	1.9		4
Total revenues	$	56.1		$	53.3

(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 75% and 55% of our LNG revenues from contracts included in the table above during the three months ended June 30, 2022 and 2021, respectively, and approximately 72% and 53% of our LNG revenues from contracts included in the table above during the six months ended June 30, 2022 and 2021, respectively, were related to variable consideration received from customers. Approximately 100% and 91% of our LNG revenues—affiliate from contracts included in the table above during the three and six months ended June 30, 2022 and 2021, respectively, were related to variable consideration received from customers. During each of the three and six months ended June 30, 2022, approximately 6% of our regasification revenues were related to variable consideration received from customers and during each of the three and six months ended June 30, 2021, approximately 5% of our regasification revenues were related to variable consideration received from customers.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

Termination Agreement with Chevron

In June 2022, Chevron U.S.A. Inc. (“Chevron”) entered into an agreement with SPLNG providing for the early termination of the TUA between the parties for a lump sum fee of $765 million (the “Termination Fee”). Upon SPLNG’s receipt of the Termination Fee, obligations pursuant to the TUA will terminate, including Chevron’s obligation to pay SPLNG capacity payments totaling $125 million annually (adjusted for inflation) through 2029. The termination agreement became effective on July 6, 2022, and we will recognize revenue, inclusive of the Termination Fee, over the remaining 2022 period.

NOTE 11—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Income (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
LNG revenues—affiliate
Cheniere Marketing Agreements	$	1,100	$	209	$	1,845	$	419
Contracts for Sale and Purchase of Natural Gas and LNG	35		2		47		6
Total LNG revenues—affiliate	1,135		211		1,892		425
LNG revenues—related party
Natural Gas Transportation and Storage Agreements	4		—		4		—
Cost of sales—affiliate
Cheniere Marketing Agreements	—		—		—		34
Contracts for Sale and Purchase of Natural Gas and LNG	57		12		62		20
Total cost of sales—affiliate	57		12		62		54
Cost of sales—related party
Natural Gas Transportation and Storage Agreements	1		1		1		1
Operating and maintenance expense—affiliate
Services Agreements	41		35		79		69
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	15		12		27		22
General and administrative expense—affiliate
Services Agreements	24		21		47		42

As of June 30, 2022 and December 31, 2021, we had $485 million and $232 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. The Base SPA was subsequently amended to remove certain conditions related to the sale of LNG from Trains 5 and 6

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

Cheniere Marketing Letter Agreements

In May 2022, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 32 TBtu of LNG to be delivered between 2023 and 2025 at a price of 115% of Henry Hub plus $3.00 per MMBtu.

Cheniere Marketing has letter agreements with SPL to purchase up to 306 cargoes of LNG to be delivered between 2022 and 2027 at a weighted average price of $1.95 plus 115% of Henry Hub.

SPL and Cheniere Marketing had a letter agreement for the sale of up to 30 cargoes of LNG that were delivered in 2021 at a price of 115% of Henry Hub plus $0.728 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 indirectly acquired a portion of our limited partner interests in September 2020 through its purchase of a portion of CQP Target Holdco’s equity interests. We recorded accrued liabilities—related party of $6 million and $4 million as of June 30, 2022 and December 31, 2021, respectively, with this related party.

Services Agreements

As of June 30, 2022 and December 31, 2021, we had $136 million and $141 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.

CQP 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 through 2042. 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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 through 2029. 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) through 2029 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 necessary services required to operate and maintain the Liquefaction Project. After each Train of the Liquefaction Project 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 is required to 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 through 2042. 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 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 is required to pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, SPL is required to pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train through 2042.

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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

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 as of June 30, 2022 and December 31, 2021, respectively, and $15 million of other non-current liabilities—affiliate as of both June 30, 2022 and December 31, 2021, from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third party costs incurred by Cheniere Marketing with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG Terminal.

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. Tug Services distributed $4 million and $3 million during the three months ended June 30, 2022 and 2021, respectively, and $5 million and $4 million during the six months ended June 30, 2022 and 2021, respectively, to Cheniere Terminals, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ Equity (Deficit).

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG terminal export agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG Terminal.  SPLNG did not record any revenues associated with this agreement during the three and six months ended June 30, 2022 and 2021.

19

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

State Tax Sharing Agreements

SPLNG, SPL and CTPL each have a state tax sharing agreement with Cheniere.  Under these agreements, Cheniere has agreed to prepare and file all state and local tax returns which each of the entities 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, each of the respective entities will pay to Cheniere an amount equal to the state and local tax that each of the entities would be required to pay if its state and local tax liability were calculated on a separate company basis. To date, there have been no state and local tax payments demanded by Cheniere under the tax sharing agreements. The agreements for SPLNG, SPL and CTPL are effective for tax returns due on or after January 2008, August 2012 and May 2013, respectively.

NOTE 12—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 (Deficit). On July 25, 2022, we declared a cash distribution of $1.060 per common unit to unitholders of record as of August 4, 2022 and the related general partner distribution to be paid on August 12, 2022. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.285 per unit.

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.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Total		Limited Partner Common Units		General Partner Units		IDR
Three Months Ended June 30, 2022
Net income	$	342
Declared distributions	743		513		15		215
Assumed allocation of undistributed net loss (1)	$	(401)	(393)		(8)		—
Assumed allocation of net income			$	120	$	7	$	215
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	0.25
Three Months Ended June 30, 2021
Net income	$	395
Declared distributions	361		322		7		32
Assumed allocation of undistributed net income (1)	$	34	33		1		—
Assumed allocation of net income			$	355	$	8	$	32
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	0.73
Six Months Ended June 30, 2022
Net income	$	501
Declared distributions	1,476		1,021		30		425
Assumed allocation of undistributed net loss (1)	$	(975)	(955)		(20)		—
Assumed allocation of net income			$	66	$	10	$	425
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	0.13
Six Months Ended June 30, 2021
Net income	$	742
Declared distributions	716		641		14		61
Assumed allocation of undistributed net income (1)	$	26	25		1		—
Assumed allocation of net income			$	666	$	15	$	61
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	1.38

(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 (loss).

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 13—CUSTOMER CONCENTRATION

The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended June 30,		Six Months Ended June 30,		June 30,	December 31,
	2022	2021	2022	2021	2022	2021
Customer A	23%	26%	26%	27%	20%	28%
Customer B	18%	18%	16%	16%	19%	17%
Customer C	18%	17%	18%	18%	13%	*
Customer D	16%	16%	15%	16%	16%	14%
Customer E	14%	12%	13%	12%	*	12%
Customer F	*	*	*	*	*	12%

* Less than 10%

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Six Months Ended June 30,
	2022		2021
Cash paid during the period for interest on debt, net of amounts capitalized	$	377	$	410

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $332 million and $252 million as of June 30, 2022 and 2021, respectively.

Novation of IPM Agreement from Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”)

In March 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project, SPL and CCL Stage III, formerly a wholly owned direct subsidiary of Cheniere that merged with and into Corpus Christi Liquefaction, LLC, entered into an agreement to assign to SPL an IPM agreement to purchase 140,000 MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023. The transaction has been accounted for as a transfer between entities under common control, which required us to recognize the obligations assumed at the historical basis of Cheniere. Upon the transfer, which occurred on March 15, 2022, we recognized $2.7 billion in distributions to Cheniere’s common unitholder interest within our Consolidated Statements of Partners’ Equity (Deficit) based on our assumption of current derivative liabilities and derivative liabilities of $142 million and $2.6 billion, respectively, which represented a non-cash financing activity

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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 terminal, liquefaction facility, pipeline facility 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 regarding our future sources of liquidity and cash requirements;

•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 COVID-19 pandemic and its impact on our business and operating results, including any customers not taking delivery of LNG cargoes, the ongoing creditworthiness 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

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made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the fiscal year ended December 31, 2021. 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 

•Overview of Significant Events

•Results of Operations 

•Liquidity and Capital Resources 

•Summary of Critical Accounting Estimates

•Recent Accounting Standards

Overview

We are a publicly traded Delaware limited partnership formed in 2006 by Cheniere. 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.

LNG is natural gas (methane) in liquid form. The LNG we produce is shipped all over the world, turned back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking and other industrial uses. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.

We own the natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, which has six operational Trains, with Train 6 achieving substantial completion on February 4, 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include 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 (the “Creole Trail Pipeline”).

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Our customer arrangements provide us with significant, stable and long-term cash flows. We contract our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells to us gas on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted approximately 80% of the total production capacity from the Liquefaction Project with approximately 16 years of weighted average remaining life as of June 30, 2022. In March 2022, the DOE authorized the export of an additional 152.64 Bcf/yr of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December 31, 2050 to non-FTA countries, that were previously authorized for FTA countries only. For further discussion of the contracted future cash flows under our revenue arrangements, see the liquidity and capital resources disclosures in our annual report on Form 10-K for the fiscal year ended December 31, 2021.

We remain focused on operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive final investment decision.

Additionally, we are committed to the responsible and proactive management of our most important environmental, social and governance (“ESG”) impacts, risks and opportunities. In June 2022, Cheniere published its 2021 Corporate Responsibility (“CR”) report, which details our approach and progress on ESG issues, including Cheniere’s recently announced collaboration with natural gas midstream companies, methane detection technology providers and leading academic institutions to implement quantification, monitoring, reporting and verification of greenhouse gas emissions at natural gas gathering, processing, transmission and storage systems specific to our supply chain, as well as our contributions to energy security during a critical time in history. Additionally, Cheniere commenced providing Cargo Emissions Tags (“CE Tags”) to its customers in June 2022. The CE Tags provide customers with estimated greenhouse gas (“GHG”) emissions data associated with each LNG cargo produced at the Liquefaction Project and are provided for both free-on-board (“FOB”) and delivered ex-ship (“DES”) LNG cargoes. Cheniere’s CR report is available at cheniere.com/our-responsibility/reporting-center. Information on our website, including the CR report, is not incorporated by reference into this Quarterly Report on Form 10-Q.

Overview of Significant Events

Our significant events since January 1, 2022 and through the filing date of this Form 10-Q include the following:  

Strategic

•In June 2022, SPL entered into an SPA with Chevron U.S.A Inc. (“Chevron”) to sell Chevron approximately 1.0 mtpa of LNG between 2026 and 2042.

•In February 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project:

◦Cheniere Marketing entered into agreements to novate to SPL SPAs entered into with ENN LNG (Singapore) Pte Ltd. and a subsidiary of Glencore plc, with effective dates of January 1, 2023 and February 17, 2022, respectively, aggregating approximately 21 million tonnes of LNG to be delivered between 2023 and 2035.

◦Our board of directors approved the entry by SPL into (i) an agreement to novate to SPL an IPM agreement between Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”), formerly a wholly owned direct subsidiary of Cheniere (as purchaser) that merged with and into Corpus Christi Liquefaction, LLC, and Tourmaline Oil Marketing Corp., a subsidiary of Tourmaline Oil Corp (as supplier), to purchase 140,000 MMBtu per day of natural gas at a price based on Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023 (the “Tourmaline IPM”) and (ii) a FOB SPA with Cheniere Marketing International LLP to sell LNG associated with the natural gas to be supplied under the IPM agreement. The agreement to assign the Tourmaline IPM agreement from CCL Stage III to SPL was executed and the assignment was effective on March 15, 2022.

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Operational

•As of July 30, 2022, approximately 1,750 cumulative LNG cargoes totaling approximately 120 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

•On February 4, 2022, substantial completion of Train 6 of the Liquefaction Project was achieved.

Financial

•In February 2022, we announced the initiation of quarterly distributions to be comprised of a base amount plus a variable amount, which began with the distribution related to the first quarter of 2022. The variable amount takes into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of the business.

Results of Operations

The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Project during the six months ended June 30, 2022 and 2021:

(1) The six months ended June 30, 2021 excludes eight TBtu under our contracts that were loaded at our affiliate’s facility.

Net income

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except per share data)	2022		2021		Variance		2022		2021		Variance
Net income	$	342	$	395	$	(53)	$	501	$	742	$	(241)
Basic and diluted net income per common unit	0.25		0.73		(0.48)		0.13		1.38		(1.25)

Net income decreased by $53 million and $241 million during the three and six months ended June 30, 2022 from the comparable periods in 2021, respectively, primarily as a result of losses of $431 million and $862 million, respectively, on the derivative liability associated with the Tourmaline IPM agreement following its assignment to SPL from CCL Stage III in March 2022. See Overview of Significant Events for further discussion of the assignment. The associated losses following the assignment were primarily attributed to SPL’s lower credit risk profile relative to that of CCL Stage III, resulting in a higher derivative liability given reduced risk of SPL’s own nonperformance, and unfavorable shifts in the international forward commodity curve. Partially offsetting the decreases in net income during the periods were increases in gross margin per

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MMBtu on LNG delivered, largely due to higher margins on sales indexed to Henry Hub plus a mark up, generally at 115%, as a result of increases in the index, and increases in volume delivered, in part due to substantial completion and commencement of operations of Train 6 of the Liquefaction Project on February 4, 2022 (the “Train 6 Completion”).

Derivative instruments are utilized to manage our exposure to commodity-related marketing and price risk and are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM agreement, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery 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, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors, notwithstanding the operational intent to mitigate risk exposure over time.

As described in Overview of Significant Events, during the six months ended June 30, 2022, we entered into an SPA with a counterparty for approximately 1.0 mtpa of LNG to be delivered between 2026 and 2042. We expect our net income or loss in the future to be impacted by the revenues and associated expenses related to the commencement of this agreement.

Chevron entered into an agreement with SPLNG providing for the early termination of the TUA between the parties for a lump sum fee of $765 million (the “Termination Fee”). Upon SPLNG’s receipt of the Termination Fee, obligations pursuant to the TUA will terminate, including Chevron’s obligation to pay SPLNG capacity payments totaling $125 million annually (adjusted for inflation) through 2029, resulting in the acceleration of revenue recognition associated with the TUA.

Revenues

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except volumes)	2022		2021		Variance		2022		2021		Variance
LNG revenues	$	2,959	$	1,597	$	1,362	$	5,447	$	3,266	$	2,181
LNG revenues—affiliate	1,135		211		924		1,892		425		1,467
LNG revenues—related party	4		—		4		4		—		4
Regasification revenues	68		67		1		136		134		2
Other revenues	15		14		1		30		27		3
Total revenues	$	4,181	$	1,889	$	2,292	$	7,509	$	3,852	$	3,657
LNG volumes recognized as revenues (in TBtu) (1)	375		313		62		747		638		109

(1)The six months ended June 30, 2021 includes eight TBtu that were loaded at our affiliate’s facility.

Total revenues increased by approximately $2.3 billion and $3.7 billion during the three and six months ended June 30, 2022 from the comparable periods in 2021, respectively, primarily as a result of increased revenues per MMBtu due to appreciation in the Henry Hub index. To a lesser extent, revenues increased as a result of higher volumes of LNG delivered between the periods due to the addition of approximately 5 mtpa of production capacity following Train 6 Completion.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train. During the six months ended June 30, 2022, we realized offsets to LNG terminal costs of $148 million, corresponding to 13 TBtu that were related to the sale of commissioning cargoes from Train 6 of the Liquefaction Project. We did not realize any offsets to LNG terminal costs during the three months ended June 30, 2022 or the three and six months ended June 30, 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 $67 million and $12 million during the three months ended June 30, 2022 and 2021, respectively, and $121 million and $60 million during the six months ended June 30, 2022 and 2021, respectively, related to these transactions.

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Operating costs and expenses

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2022		2021		Variance		2022		2021		Variance
Cost of sales	$	3,144	$	888	$	2,256	$	5,706	$	1,836	$	3,870
Cost of sales—affiliate	57		12		45		62		54		8
Cost of sales—related party	1		1		—		1		1		—
Operating and maintenance expense	191		168		23		361		317		44
Operating and maintenance expense—affiliate	41		35		6		79		69		10
Operating and maintenance expense—related party	15		12		3		27		22		5
Development expense	—		1		(1)		—		1		(1)
General and administrative expense (recovery)	(3)		3		(6)		—		5		(5)
General and administrative expense—affiliate	24		21		3		47		42		5
Depreciation and amortization expense	156		138		18		309		277		32
Other	—		6		(6)		—		6		(6)
Total operating costs and expenses	$	3,626	$	1,285	$	2,341	$	6,592	$	2,630	$	3,962

Total operating costs and expenses increased by $2.3 billion and $4.0 billion during the three and six months ended June 30, 2022 from the comparable periods in 2021, respectively, primarily as a result of increased cost of sales. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to the extent those costs are not utilized for the commissioning process. Cost of sales also includes change in fair value of commodity derivatives to secure natural gas feedstock for the Liquefaction Project, costs associated with the sale of certain unutilized natural gas procured for the liquefaction process, variable transportation and storage costs and other costs to convert natural gas into LNG. Nearly all of the increase in both comparable periods was attributed to third party cost of sales, which increased $2.3 billion and $3.9 billion during the three and six months ended June 30, 2022, respectively, primarily as a result of increased pricing of natural gas feedstock as a result of higher U.S. natural gas prices and, to a lesser extent, from increased volume of LNG delivered. During the six months ended June 30, 2022, cost of sales additionally included an unfavorable change in the valuation associated with the Tourmaline IPM agreement that was assigned to SPL in March 2022, primarily as a result of credit risk as described in Net income above.

Operating and maintenance expense (including affiliate and related party) primarily includes costs associated with operating and maintaining the Liquefaction Project and also includes service and maintenance, insurance, regulatory costs and other operating costs. During the three and six months ended June 30, 2022, operating and maintenance expense increased from the comparable periods in 2021, primarily due to increased third party service and maintenance contract costs in addition to increased natural gas transportation and storage capacity demand charges following Train 6 Completion.

Other expense

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2022		2021		Variance		2022		2021		Variance
Interest expense, net of capitalized interest	$	216	$	209	$	7	$	419	$	426	$	(7)
Loss on modification or extinguishment of debt	—		—		—		—		54		(54)
Other income, net	(3)		—		(3)		(3)		—		(3)
Total other expense	$	213	$	209	$	4	$	416	$	480	$	(64)

Interest expense, net of capitalized interest, increased during the three months ended June 30, 2022 from the comparable period in 2021 primarily as a result of a lower portion of total interest costs eligible for capitalization following Train 6 Completion, which was offset by the reduction of outstanding debt between the periods. Interest expense, net of capitalized interest, decreased during the six months ended June 30, 2022 from the comparable period in 2021 primarily as a result of the reduction of outstanding debt between the periods, which was offset by the reduction in the portion of total interest costs eligible for capitalization following the Train 6 Completion.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Total interest cost	$	223	$	241	$	447	$	488
Capitalized interest	(7)		(32)		(28)		(62)
Total interest expense, net of capitalized interest	$	216	$	209	$	419	$	426

Loss on modification or extinguishment of debt decreased during the six months ended June 30, 2022 from the comparable period in 2021 due to the recognition of debt extinguishment costs relating to the payment of early redemption fees, premiums and write off of unamortized debt issuance costs with the redemption of the 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) in March 2021.

Liquidity and Capital Resources

The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash and cash equivalents and available commitments under our credit facilities. In the long term, we expect to meet our cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt offerings by us or our subsidiaries and equity offerings by us. The table below provides a summary of our available liquidity (in millions).

	June 30, 2022
Cash and cash equivalents	$	1,111
Restricted cash and cash equivalents designated for the Liquefaction Project	78
Available commitments under our credit facilities (1):
SPL’s Working capital revolving credit and letter of credit reimbursement agreement	837
CQP’s Credit facilities	750
Total available commitments under our credit facilities	1,587
Total available liquidity	$	2,776

(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of June 30, 2022. See Note 9—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

Our liquidity position subsequent to June 30, 2022 will be driven by future sources of liquidity and future cash requirements. Future sources of liquidity are expected to be composed of (1) cash receipts from executed contracts, under which we are contractually entitled to future consideration, and (2) additional sources of liquidity, from which we expect to receive cash although the cash is not underpinned by executed contracts. Future cash requirements are expected to be composed of (1) cash payments under executed contracts, under which we are contractually obligated to make payments, and (2) additional cash requirements, under which we expect to make payments although we are not contractually obligated to make the payments under executed contracts.

Although our sources and uses of cash are presented below from a consolidated standpoint, we and our subsidiary SPL operate with independent capital structures. Certain restrictions under debt instruments executed by our subsidiaries limit its ability to distribute cash, including the following:

•SPL is required to deposit all cash received into restricted cash and cash equivalents accounts under certain of their debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments. The majority of the cash held by SPL that is restricted to CQP relates to advance funding for operation and construction of the Liquefaction Project; and

•SPL is restricted by affirmative and negative covenants included in certain of its debt agreements in its ability to make certain payments, including distributions, unless specific requirements are satisfied.

Notwithstanding the restrictions noted above, we believe that sufficient flexibility exists to enable each independent capital structure to meet its currently anticipated cash requirements. The sources of liquidity at SPL primarily fund the cash

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requirements of SPL, and any remaining liquidity not subject to restriction, as supplemented by liquidity provided by SPLNG, is available to enable CQP to meet its cash requirements.

Supplemental Guarantor Information

The $1.5 billion of 4.500% Senior Notes due 2029, the $1.5 billion of 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”) and the $1.2 billion of 3.25% Senior Notes due 2032 (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, Sabine Pass LP (each a “Guarantor” and collectively, the “CQP Guarantors”).

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.

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The following tables include summarized financial information of CQP (the “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 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.

Summarized Balance Sheets (in millions)	June 30,		December 31,
	2022		2021
ASSETS
Current assets
Cash and cash equivalents	$	1,111	$	876
Accounts receivable from Non-Guarantors	32		49
Other current assets	55		53
Current assets—affiliate	136		137
Current assets with Non-Guarantors	—		1
Total current assets	1,334		1,116
Property, plant and equipment, net of accumulated depreciation	2,386		2,422
Other non-current assets, net	112		119
Total assets	$	3,832	$	3,657
LIABILITIES
Current liabilities
Due to affiliates	$	144	$	167
Deferred revenue from Non-Guarantors	22		22
Other current liabilities	125		95
Total current liabilities	291		284
Long-term debt, net of premium, discount and debt issuance costs	4,156		4,154
Other non-current liabilities	87		87
Non-current liabilities—affiliate	17		15
Total liabilities	$	4,551	$	4,540

Summarized Statement of Income (in millions)	Six Months Ended June 30, 2022
Revenues	$	168
Revenues from Non-Guarantors	268
Total revenues	436
Operating costs and expenses	105
Operating costs and expenses—affiliate	100
Total operating costs and expenses	205
Income from operations	231
Net income	141

31

Sources and Uses of Cash

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

	Six Months Ended June 30,
	2022		2021
Net cash provided by operating activities	$	1,586	$	1,075
Net cash used in investing activities	(239)		(316)
Net cash used in financing activities	(1,132)		(762)
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	$	215	$	(3)

Operating Cash Flows

Our operating cash net inflows during the six months ended June 30, 2022 and 2021 were $1.6 billion and $1.1 billion, respectively. The $511 million increase between the periods was primarily related to increases in cash payments on LNG delivered due to increases in price per MMBtu and volume of LNG delivered, which was partially offset by higher operating cash outflows primarily due to higher natural gas feedstock costs.

Investing Cash Flows

Cash outflows for property, plant and equipment were primarily for the construction costs for Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022. These costs are capitalized as construction-in-process until achievement of substantial completion.

Financing Cash Flows

Our financing cash net outflows during the six months ended June 30, 2022 and 2021 were $1.1 billion and $762 million, respectively. The $370 million increase between the periods was primarily related to increased cash distributions to unitholders of $422 million, partially offset by a decrease of $60 million related to debt activity, each described further below.

Debt Activity

During the six months ended June 30, 2021, we issued an aggregate principal amount of $1.5 billion of the 2031 CQP Senior Notes and paid $20 million of debt issuance costs related to this issuance. The proceeds of 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. We did not have any debt activity during the six months ended June 30, 2022.

Cash Distributions to Unitholders

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from accumulated operating surplus. The following provides a summary of distributions paid by us during the six months ended June 30, 2022 and 2021:

				Total Distribution (in millions)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Common Units		General Partner Units		Incentive Distribution Rights
May 13, 2022	January 1 - March 31, 2022	$	1.050	$	508	$	15	$	210
February 14, 2022	October 1 - December 31, 2021	0.700		339		8		47
May 14, 2021	January 1 - March 31, 2021	0.660		320		7		30
February 12, 2021	October 1 - December 31, 2020	0.655		316		7		27

32

In addition, Tug Services distributed $4 million and $3 million during the three months ended June 30, 2022 and 2021, respectively, and $5 million and $4 million during the six months ended June 30, 2022 and 2021, respectively, to Cheniere Terminals in accordance with their terminal marine service agreement, which is recognized as part of the distributions to our general partner interest holders.

On July 25, 2022, we declared a cash distribution of $1.060 per common unit to unitholders of record as of August 4, 2022 and the related general partner distribution to be paid on August 12, 2022. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.285 per unit.

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 December 31, 2021.

Recent Accounting Standards 

For a summary of recently issued accounting standards, see Note 1—Nature of Operations and Basis of Presentation of our Notes to Consolidated Financial Statements.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Marketing and Trading Commodity Price Risk

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

	June 30, 2022				December 31, 2021
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(3,467)	$	550	$	27	$	1

See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our derivative instruments.

ITEM 4.     CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the 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. 

33

PART II.     OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. Other than discussed below, 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, 2021.

Louisiana Department of Environmental Quality (“LDEQ”) Matter

Certain of our subsidiaries are in discussions with the LDEQ to resolve self-reported deviations arising from operation of the Sabine Pass LNG Terminal and the commissioning of the Liquefaction Project, and relating to certain requirements under its Title V Permit. The matter involves deviations self-reported to LDEQ pursuant to the Title V Permit and covering the time period from January 1, 2012 through March 25, 2016. On April 11, 2016, certain of our subsidiaries received a Consolidated Compliance Order and Notice of Potential Penalty (the “Compliance Order”) from LDEQ covering deviations self-reported during that time period. Certain of our subsidiaries continue to work with LDEQ to resolve the matters identified in the Compliance Order. We do not expect that any ultimate sanction will have a material adverse impact on our financial results.

Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Matter

In February 2018, the PHMSA issued a Corrective Action Order (the “CAO”) to SPL in connection with a minor LNG leak from one tank and minor vapor release from a second tank at the Sabine Pass LNG Terminal (the “2018 SPL tank incident”). These two tanks have been taken out of operational service while we conduct analysis, repair and remediation. On April 20, 2018, SPL and PHMSA executed a Consent Agreement and Order (the “Consent Order”) that replaces and supersedes the CAO. On July 9, 2019, PHMSA and FERC issued a joint letter setting out operating conditions required to be met prior to SPL returning the tanks to service. In July 2021, PHMSA issued a Notice of Probable Violation (“NOPV”) and Proposed Civil Penalty to SPL alleging violations of federal pipeline safety regulations relating to the 2018 SPL tank incident and proposing civil penalties totaling $2,214,900. On September 16, 2021, PHMSA issued an Amended NOPV that reduced the proposed penalty to $1,458,200. On October 12, 2021, SPL responded to the Amended NOPV, electing not to contest the alleged violations in the Amended NOPV and electing to pay the proposed reduced penalty. PHMSA notified SPL in a letter dated November 9, 2021 that the case was considered “closed.” On March 9, 2022, PHMSA and FERC issued conditional approval to return one of the two tanks to service. SPL continues to coordinate with PHMSA and FERC to address the matters relating to the 2018 SPL tank incident, including repair approach and related analysis. We do not expect that the Consent Order and related analysis, repair and remediation or resolution of the NOPV will have a material adverse impact on our financial results or operations.

ITEM 1A.    RISK FACTORS

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2021.

34

ITEM 6.    EXHIBITS

Exhibit No.	Description
10.1*	Consent and Amendment to the Credit and Guaranty Agreement, dated July 6, 2022, among the Partnership, as Borrower, certain subsidiaries of the Partnership, as Subsidiary Guarantors, the lenders from time to time party thereto, Natixis, Société Générale, The Bank of Nova Scotia, Wells Fargo Bank, as Issuing Banks, MUFG Bank, LTD as Administrative Agent and Sole Coordinating Lead Arranger, and certain arrangers and other participants
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-00063 FERC Condition 78, dated May 6, 2022, (ii) the Change Order CO-00064 FERC Impact to Pipe Installation, dated June 14, 2022, (iii) the Change Order CO-00065 Spill Containment Sil 2 Interlock, dated June 15, 2022 and (iv) the Change Order CO-00066 Marine Dredging and Management Oversight Provisional Sums Closure, dated June 16, 2022
22.1	List of Issuers and Guarantor Subsidiaries (Incorporated by reference to Exhibit 22.1 to the Partnership's Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 24, 2022)
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.

35

SIGNATURES

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

		CHENIERE ENERGY PARTNERS, L.P.
		By:	Cheniere Energy Partners GP, LLC, its general partner
Date:	August 3, 2022	By:	/s/ Zach Davis
			Zach Davis
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	August 3, 2022	By:	/s/ David Slack
			David Slack
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

36

EX-10.1

Exhibit 10.1

CONSENT AND AMENDMENT TO THE CREDIT AND GUARANTY AGREEMENT

This Consent and Amendment (this “Consent and Amendment”), dated as of July 6, 2022, to the Credit and Guaranty Agreement, dated as of May 29, 2019 (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”), by and among Cheniere Energy Partners, L.P. (“Borrower”), MUFG Bank, Ltd., as Administrative Agent (in such capacity, the “Administrative Agent”), the Lenders party thereto from time to time (referred to herein as the “Lenders”) and each other Person party thereto from time to time. All capitalized terms used herein and not otherwise defined shall have the meanings ascribed to such terms in the Credit Agreement.

WHEREAS, (i) pursuant to Section 6.13(a) of the Credit Agreement, the Borrower may not cancel or terminate any Material Contract to which it is a party or consent to or accept any cancellation or termination thereof, (ii) pursuant to Section 6.13(b) the Borrower may not terminate a terminal use agreement with an Anchor Customer, (iii) Section 8.01(o) of the Credit Agreement contains an Event of Default tied to any terminal use agreement or any guarantee thereof signed with an Anchor Customer ceasing to be valid and binding or in full force and effect and (iv) Section 6.10 of the Credit Agreement limits the Subsidiary Guarantors from entering into certain transactions with Affiliates;

WHEREAS, for an agreed consideration, the Borrower and Chevron U.S.A. Inc. (“Chevron”) intend to terminate: (i) that certain LNG Terminal Use Agreement, dated as of November 8, 2004, between Chevron and Sabine Pass LNG, L.P. (“SPLNG”) (as amended, restated, supplemented or otherwise modified from time to time, the “Chevron TUA”), (ii) the Omnibus Agreement dated as of November 8, 2004 between SPLNG and Chevron (as amended, restated, supplemented or otherwise modified from time to time, the “Chevron Omnibus Agreement”) and (iii) that certain Guaranty, dated as of December 15, 2004, from Chevron Corporation, relating to the foregoing (as amended, restated, supplemented or otherwise modified from time to time, the “Chevron Credit Support” and, together with the Chevron TUA and the Chevron Omnibus Agreement, the “Chevron Agreements”), in each case, which Chevron Agreements are Material Contracts;

WHEREAS, in connection with the termination of the Chevron Agreements, Sabine Pass Tug Services, LLC (“SPTS”), a Subsidiary Guarantor, Cheniere Marketing, LLC (“Cheniere Marketing”), an Affiliate of the Borrower, Total Gas & Power North America, Inc. (“Total”) and Chevron intend to amend that certain Terminal Marine Services Agreement, dated as of April 2, 2009 (as amended, restated, supplemented or otherwise modified from time to time, the “TMSA”), by and among SPTS, Cheniere Marketing, Total and Chevron, to assign or terminate Chevron’s obligations and interests therein;

WHEREAS, the Borrower has requested that the Administrative Agent and the Requisite Lenders provide the consents as set forth herein in connection with the proposed termination of the Chevron Agreements and amendment of the TMSA; and

WHEREAS, the Administrative Agent and the Requisite Lenders are willing to provide the consents as set forth herein;

NOW, THEREFORE, in consideration of the foregoing premises and the agreements, provisions and covenants herein contained, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto agree as follows:

Section 1.     Consents. Each of the Borrower, the Administrative Agent and the Lenders party to this Consent and Amendment (constituting the Requisite Lenders) hereby agrees:

1.1    notwithstanding the provisions set forth in Sections 6.13(a) and (b) of the Credit Agreement, that the Credit Parties shall be permitted to terminate the Chevron Agreements; and

1.2    notwithstanding the provisions set forth in Section 6.10 of the Credit Agreement, that SPTS shall be permitted to amend the TMSA to either (a) assign the obligations and interests of Chevron in the TMSA to Cheniere LNG Terminals, LLC or (b) remove Chevron as a party thereto and terminate its obligations and interests thereunder; and

1.3    notwithstanding the provisions set forth in Section 8.1(o) of the Credit Agreement, no Event of Default shall be deemed to have occurred under such Section as a result of the transactions contemplated by this Consent and Amendment.

Section 2.    Amendments to Credit Agreement. Each of the Borrower, the Administrative Agent and the Lenders party to this Consent and Amendment (constituting the Requisite Lenders) hereby agrees:

2.1    The definition of “Anchor Customer” is hereby amended by deleting the stricken text (indicated textually in the same manner as the following example: stricken text) and adding the double-underlined text (indicated textually in the same manner as the following example: double-underlined text):

“Anchor Customer” means Total Gas & Power North America, Inc., Chevron U.S.A., Inc. and any replacements for Total Gas & Power North America, Inc. or Chevron U.S.A. Inc., having (or having a guarantor with) a credit rating of not less than Baa3 by Moody’s and at least BBB- by S&P and engaged in the international Gas, petroleum or LNG business.

2.2    The definition of “SPLNG Omnibus Agreements” is hereby amended by deleting the stricken text (indicated textually in the same manner as the following example: stricken text) and adding the double-underlined text (indicated textually in the same manner as the following example: double-underlined text):

“SPLNG Omnibus Agreements” means (a)the Omnibus Agreement dated as of September 2, 2004 between Total Gas & Power North America, Inc. (successor to Total LNG USA, Inc.) and SPLNG and (b) the Omnibus Agreement dated as of November 8, 2004 between SPLNG and Chevron U.S.A., Inc.

2

2.3    Item 25 in Schedule 6.10 (Certain Affiliate Transactions) to the Credit Agreement is hereby amended by deleting the stricken text (indicated textually in the same manner as the following example: stricken text) and adding the double-underlined text (indicated textually in the same manner as the following example: double-underlined text):

Terminal Marine Services Agreement, April 2, 2009, as amended by Extension of Terminal Marine Services Agreement, January 31, 2017 and Terminal Marine Services Agreement - Increase in Per Vessel Fee, January 31, 2018 and as further amended by that certain Amendment No. 2, dated as of July ___, 2022.

2.4    Item 25 in Schedule 6.10 (Certain Affiliate Transactions) to the Credit Agreement shall automatically be further amended to include reference to the amendment or termination agreement to the TMSA contemplated by Section 1.2 upon execution of such amendment or termination agreement.

Section 3.    Representations and Warranties. The Borrower hereby represents and warrants to the Lenders that:

3.1.    no Default or Event of Default has occurred and is continuing as of the date hereof or, after giving effect to this Consent and Amendment, will result from the consummation of the transactions contemplated by this Consent and Amendment; and

3.2    each of the representations and warranties of the Borrower in the Credit Agreement and the other Financing Documents is true and correct in all material respects except for those representations and warranties that are qualified by materiality, which shall be true and correct in all respects, on and as of the date hereof (or, if stated to have been made solely as of an earlier date, as of such earlier date).

Section 4.    Effectiveness. This Consent and Amendment shall become effective as of the date hereof upon the Administrative Agent receiving executed counterparts of this Consent and Amendment by each of the Borrower, the Administrative Agent and the Requisite Lenders.

Section 5.    Financing Document. This Consent and Amendment constitutes a Financing Document as such term is defined in, and for purposes of, the Credit Agreement.

Section 6.    Governing Law. THIS CONSENT AND AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, UNITED STATES OF AMERICA, WITHOUT ANY REFERENCE TO THE CONFLICT OF LAW PRINCIPLES THEREOF (OTHER THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW).

Section7.    Headings. All headings in this Consent and Amendment are included only for convenience and ease of reference and shall not be considered in the construction and interpretation of any provision hereof.

3

Section 8.    Binding Nature and Benefit. This Consent and Amendment shall be binding upon and inure to the benefit of each party hereto and their respective successors and permitted assigns.

Section 9.    Counterparts; E-Signature. This Consent and Amendment may be executed in multiple counterparts, each of which shall be deemed an original for all purposes, but all of which together shall constitute one and the same instrument. Delivery of an executed counterpart of a signature page of this Consent and Amendment by facsimile or portable document format (“pdf’) shall be effective as delivery of a manually executed counterpart of this Consent and Amendment. The words “execution,” “execute”, “signed,” “signature,” and words of like import in or related to any document to be signed in connection with this Consent and Amendment and the transactions contemplated hereby (including without limitation amendments, waivers or consents) shall be deemed to include electronic signatures, the electronic matching of assignment terms and contract formations on electronic platforms approved by the parties hereto, or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act.

Section 10.    No Modifications; No Other Matters. Except as expressly provided for herein, the terms and conditions of the Credit Agreement and the other Financing Documents shall continue unchanged and shall remain in full force and effect. Each consent and amendment granted herein shall apply solely to the matters set forth herein and such consent and amendment shall not be deemed or construed as a consent or amendment of any other matters, nor shall such consent or amendment apply to any other matters.

Section 11.    Direction to Administrative Agent. By their signature below, each of the Term Loan Lenders and Revolving Lenders party hereto, constituting the Requisite Lenders, hereby directs the Administrative Agent to execute this Consent and Amendment.

[Remainder of the page left intentionally blank.]

4

IN WITNESS WHEREOF,the parties hereto have caused this Consent and Amendment to be duly executed by their officers thereunto duly authorized as of the day and year first above written.

CHENIERE ENERGY PARTNERS,

L.P.,

as Borrower

By: Cheniere Energy Partners GP, LLC, its
general partner

By:	/s/ Matthew Healey
Name:	Matthew Healey
Title:	Vice President, Finance and Treasury

SIGNATURE PAGE TO CQP CREDIT AGREEMENT CONSENT AND AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

BANCO BILBAO VIZCAYA ARGENTARIA, S.A. NEW YORK BRANCH,

as Lender

By:	/s/ Stephen Johnson
Name:	Stephen Johnson
Title:	Managing Director

By:	/s/ Luis Ruigomez
Name:	Luis Ruigomez
Title:	Executive Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

THE BANK OF NOVA SCOTIA, HOUSTON BRANCH,

as Lender

By:	/s/ Joe Lattanzi
Name:	Joe Lattanzi
Title:	Managing Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK BRANCH, as Lender

By:	/s/ Kwaku Ntoso
Title:	Executive Director
Name:	Kwaku Ntoso

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

Citibank, N.A.,

as Lender

By:	/s/ Cathy Shepherd
Name:	Cathy Shepherd
Title:	Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

COMMONWEALTH BANK OF AUSTRALIA,

as Lender

By:	/s/ Scott Easey
Name:	Scott Easey
Title:	Associate Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

Credit Agricole Corporate and Investment Bank,

as Lender

By:	/s/ Evan Levy
Name:	Evan Levy
Title:	Managing Director

By:	/s/ Ken Ricciardi
Name:	Ken Ricciardi
Title:	Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH

as Lender

By:	/s/ William O”Daly
Name:	William O’Daly
Title:	Authorized Signatory

By:	/s/ Ilan Dolgin
Name:	Ilan Dolgin
Title:	Authorized Signatory

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

DBS Bank Ltd.,

as Lender

By:	/s/ Ronald Wong
Name:	Ronald Wong
Title:	Senior Vice Pesident

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

Goldman Sachs Bank USA,

as Lender

By:	/s/ Dan Martis
Name:	Dan Martis
Title:	Authorized Signatory

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

[HSBC Bank USA, N.A.],

as Lender

By:	/s/ Karun Chopra
Name:	Karun Chopra
Title:	No. 23341 Director, Real Assets Finance

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

ING Capital LLC,

as Lender

By:	/s/ Subha Pasumarti
Name:	Subha Pasumarti
Title:	Managing Director

By:	/s/ Tanja van der Woude
Name:	Tanja van der Woude
Title:	Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

INTESA SANPAOLO S.P.A.,

NEW YORK BRANCH

as Lender

By:	/s/ Nicholas A. Matacchieri
Name:	Nicholas A. Matacchieri
Title:	Managing Director

By:	/s/ Lisa Cintron
Name:	Lisa Cintron
Title:	Business Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

JPMORGAN CHASE BANK, N.A.,

as Lender

By:	/s/ Arina Mavilian
Name:	Arina Mavilian
Title:	Executive Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

Mizuho Bank, Ltd.,

as Lender

By:	/s/ Hiroe Nikaido
Name:	Hiroe Nikaido
Title:	Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

Morgan Stanley Bank, N.A.,

as Lender

By:	/s/ Rikin Pandya
Name:	Rikin Pandya
Title:	Authorized Signatory

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

MUFG BANK, LTD.,

as Lender

By:	/s/ Saad Iqbal
Name:	Saad Iqbal
Title:	Managing Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

National Australia Bank Limited,

as Lender

By:	/s/ Eli Davis
Name:	Eli Davis
Title:	Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

Natixis,

as Lender

By:	/s/ Anthony Perna
Name:	Anthony Perna
Title:	Director

By:	/s/ John Sickler III
Name:	John Sickler III
Title:	Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

ROYAL BANK OF CANADA,

as Lender

By:	/s/ Jay T. Sartain
Name:	Jay T. Sartain
Title:	Authorized Signatory

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

SANTANDER BANK, N.A.

as Lender

By:	/s/ Erika Wershoven
Name:	Erika Wershoven
Title:	Executive Director

By:	/s/ Sandra Zelaya
Name:	Sandra Zelaya
Title:	Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

Sumitomo Mitsui Banking Corporation,

as Lender

By:	/s/ Juan Kreutz
Name:	Juan Kreutz
Title:	Managing Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

Société Générale,

as Lender

By:	/s/ Valerie Colville
Name:	Valerie Colville
Title:	Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

IN WITNESS WHEREOF, the parties hereto have caused this Consent and Amendment to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

WELLS FARGO BANK, NATIONAL

ASSOCIATION

as Lender

By:	/s/ Borden Tennant
Name:	Borden Tennant
Title:	Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT

EX-10.2

Exhibit 10.2

CHANGE ORDER

FERC CONDITION 78

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-00063 DATE OF CHANGE ORDER: May 6, 2022

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 costs to increase the design spill rate on the Third Berth system from 12,000 m3/hr to 13,000 m3/hr to accommodate both loading and cooldown flow rates to satisfy FERC Condition 78. This change requires Swale Modification in two (2) locations and a new SIL 2 Interlock Impoundment as further described below.

1.1. Swale Modification:

At Location 1, the system does not provide sufficient cross section to pass the flow resulting in a backup of the water surface upstream of the channel. The channel is identified as 5’-8” wide but only has a usable width of 5’-0” due to the provided 4” lightweight concrete liner (DB-03R03-00011). Removal of the lightweight concrete liner from the sides of the trench will provide sufficient cross-sectional area to reduce the water surface sufficiently to pass the peak flow rate. Removal of the lining from the bottom of the trench will lower the flowline level and provide additional available flow capacity in this section of the system. Owner has confirmed that removal of lightweight concrete line is acceptable.

At Location 2, there is insufficient cross section in the existing LNG system to convey the peak flow resulting in minor overtopping. The section depth at this location is approximately 3’ with a calculated normal flow depth of 3.03’ (1/3” above top of drain). To achieve sufficient flow depth in the existing LNG system, the tie-in point needs to move approximately 200’ downstream to Location 3 to provide approximately 3” of freeboard, which is in line with minimum freeboard provided in new Third Berth LNG trench. Re-alignment of the Third Berth spill conveyance channel will require removal of approximately 195' of clean stormwater drain.

Refer to Exhibit C of this Change Order for plot plan reflecting these modifications.

1.2. New SIL 2 Interlock Impoundment:

To avoid a pool fire scenario in the LNG trenches and associated impact to adjacent structures, a new SIL 2 interlock will be added to limit the spill volume to the capacity of the Jetty Impoundment Basin only, and eliminate back-up into the LNG trenches. This interlock will detect cold temperatures in the LNG trench and at the entrance to the Jetty Impoundment basin associated with the Third Berth, and will isolate the Third Berth as primary action, and trip the in-tank LNG pumps as secondary action.

Refer to Exhibit D of this Change Order for conceptual LNG spill collection system.

Reference DECN 26012-100-M6N-DK-24015 for further information.

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, 41-42, 45-49, 51, 53-58, 61)	$	21,155,105
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,038,047,678
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	$	2,038,047,678

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, 39-40, 43-44, 50, 52, 59-60, 62)	$	(1,857,667)
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	455,838,333
10. The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	627,450
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	$	456,465,783

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)	$	2,493,886,011
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	627,450
16. The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,494,513,461

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):Yes

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	Bechtel Energy, Inc.
Owner	Contractor
David Craft	Kane McIntosh
Name	Name
SVP E&C	Senior Project Manager
Title	Title
May 9, 2022	May 6, 2022
Date of Signing	Date of Signing

CHANGE ORDER

FERC IMPACT TO PIPE INSTALLATION

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-00064 DATE OF CHANGE ORDER: June 14, 2022

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 costs associated with the mitigated delayed FERC permit approval for aboveground pipe, originally planned for 3 January 2022 and received on 8 April 2022. The delayed approval from FERC resulted in Contractor re-sequencing the Work to maintain key craft professionals and work additional overtime hours to progress the limited activities on a phased release from Owner in order to meet pipe testing skyline and maintain the Ready for Reduced Ship Loading (“RFRSL”) date.

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, 41-42, 45-49, 51, 53-58, 61)	$	21,155,105
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,038,047,678
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	$	2,038,047,678

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, 39-40, 43-44, 50, 52, 59-60, 62-63)	$	(1,230,217)
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	456,465,783
10. The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	455,268
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	$	456,921,051

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)	$	2,494,513,461
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	455,268
16. The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,494,968,729

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	Sr. Project Manager, PVP
Title	Title
June 24, 2022	June 15, 2022
Date of Signing	Date of Signing

CHANGE ORDER

SPILL CONTAINMENT SIL 2 INTERLOCK

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-00065 DATE OF CHANGE ORDER: June 15, 2022

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), and in addition to the previously executed Change Order No. CO-00059, dated 11 January 2022 and the services provided therein, the Parties agree this Change Order includes Contractor’s costs to implement additional changes to the Spill Containment SIL 2 Interlock for the Third Berth Project as shown in Parts A and B below.

•    Part A: The material take-off (MTO) approved in the previous Change Order No. CO-00059 requires modification based on field walkdown. Existing spares were utilized for Tanks 1, 2 and 3; however, a new junction box and home run cable were added near the substation for Tanks 4 and 5. The purpose of this revision is to capture this additional hardware and associated labor and is inclusive of an additional junction box with stand, instrumentation cable, fittings and terminations. Part A has no impact to Contractor’s engineering hours previously executed in Change Order No. CO-00059.

•    Part B: Owner has requested the addition of new junction boxes and associated home run cable for Tanks 1, 2, 3, 4 and 5 to increase spare capacity in the system. As a result, these MTOs are new and are inclusive of five (5) junction boxes with stands, instrumentation cable, fittings and terminations. Part B has no impact to Contractor’s engineering hours previously executed in Change Order No. CO-00059.

•    For the avoidance of doubt, Parts A and B are considered independent. This Change Oder assumes that the new flow interlock under Part A will not be re-wired to the new junction boxes under Part B.

2.Mitigation of any exceedance(s) (including re-running of transient at different conditions, and stress analysis to confirm exceedance(s) are acceptable to mitigate any potential exceedances) are specifically excluded from this Change Order and shall be part of a separate Change Order in accordance with Section 6.1 of the Agreement, if requested by 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, 38, 41-42, 45-49, 51, 53-58, 61)	$	21,155,105
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,038,047,678
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	$	2,038,047,678

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, 39-40, 43-44, 50, 52, 59-60, 62-64)	$	(774,949)
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	456,921,051
10. The Contract Price Applicable to Subproject 6(b) will be increased by this Change Order	$	619,069
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	$	457,540,120

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)	$	2,494,968,729
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	619,069
16. The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,495,587,798

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/ KMContractor /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, PVP
Title	Title
June 24, 2022	June 15, 2022
Date of Signing	Date of Signing

CHANGE ORDER

MARINE DREDGING AND MANAGEMENT OVERSIGHT PROVISIONAL SUMS CLOSURE

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-00066 DATE OF CHANGE ORDER: June 16, 2022

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

1.Pursuant to the instructions in Section 2.4 and Section 2.5 Marine Dredging Provisional Sum and Dredging Management and Oversight Support Provisional Sum respectively of Attachment EE, Schedule EE-4 of the Agreement, this Change Order amends the Marine Dredging Provisional Sum and Dredging Management and Oversight Support Provisional Sum amounts based on the actual and final costs incurred by Contractor.

2.Section 2.4 - Marine Dredging Provisional Sum

a.The original Marine Dredging Provisional Sum in Section 2.4 of Attachment EE, Schedule EE-4 of the Agreement was Fifty-One Million, Seven Thousand U.S. Dollars (U.S. $51,007,000).

b.The amended Marine Dredging Provisional Sum, pursuant to Change Order CO-00020, dated 4 May 2020, was Fifty-Nine Million, Seven Thousand U.S. Dollars (U.S. $59,007,000).

c.The Marine Dredging Provisional Sum in Section 2.4 of Attachment EE, Schedule EE-4 of the Agreement is hereby increased by Seven Million, Five Hundred Thirty-Seven Thousand, Five Hundred Ninety-One U.S. Dollars (U.S. $7,537,591); and therefore, the final Marine Dredging Provisional Sum as amended by this Change Order shall be Sixty-Six Million, Five Hundred Forty-Four Thousand, Five Hundred Ninety-One U.S. Dollars (U.S. $66,544,591).

3.Section 2.5 - Dredging Management and Oversight Support Provisional Sum

a.The original Dredging Management and Oversight Support Provisional Sum in Section 2.5 of Attachment EE, Schedule EE-4 of the Agreement was Seven Hundred Thousand U.S. Dollars (U.S. $700,000).

b.The Dredging Management and Oversight Support Provisional Sum in Section 2.5 of Attachment EE, Schedule EE-4 of the Agreement is hereby decreased by Three Hundred Forty-Nine Thousand, Eight Hundred Fifty-Nine U.S. Dollars (U.S. $349,859); and therefore, the final Dredging Management and Oversight Support Provisional Sum as amended by this Change Order shall be Three Hundred Fifty Thousand, One Hundred Forty-One U.S. Dollars (U.S. $350,141).

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, 41-42, 45-49, 51, 53-58, 61)	$	21,155,105
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was	$	2,038,047,678
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	$	2,038,047,678

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, 39-40, 43-44, 50, 52, 59-60, 62-65)	$	(155,880)
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was	$	457,540,120
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 increased by this Change Order	$	7,187,450
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be	$	464,727,570

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)	$	2,495,587,798
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11)	$	7,187,450
16. The new Contract Price including this Change Order will be (add lines 14 and 15)	$	2,502,775,248

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 Mitchell
Name	Name
SVP E&C	Sr. Project Manager, PVP
Title	Title
June 24, 2022	June 16, 2022
Date of Signing	Date of Signing

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: August 3, 2022

/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: August 3, 2022

/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 June 30, 2022, 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: August 3, 2022

/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 June 30, 2022, 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: August 3, 2022

/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	6 Months Ended
	Jun. 30, 2022	Jul. 29, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2022
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		484,030,123
Entity Central Index Key	0001383650
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q2

XML

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Revenues
Revenues	$ 4,181	$ 1,889	$ 7,509	$ 3,852
Revenues from contracts with customers	4,177	1,889	7,505	3,852
Operating costs and expenses
Cost of sales (excluding items shown separately below)	3,144	888	5,706	1,836
Cost of sales—affiliate	57	12	62	54
Cost of sales—related party	1	1	1	1
Operating and maintenance expense	191	168	361	317
Operating and maintenance expense—affiliate	41	35	79	69
Operating and maintenance expense—related party	15	12	27	22
Development expense	0	1	0	1
General and administrative expense (recovery)	(3)	3	0	5
General and administrative expense—affiliate	24	21	47	42
Depreciation and amortization expense	156	138	309	277
Other	0	6	0	6
Total operating costs and expenses	3,626	1,285	6,592	2,630
Income from operations	555	604	917	1,222
Other income (expense)
Interest expense, net of capitalized interest	(216)	(209)	(419)	(426)
Loss on modification or extinguishment of debt	0	0	0	(54)
Other income, net	3	0	3	0
Total other expense	(213)	(209)	(416)	(480)
Net income	$ 342	$ 395	$ 501	$ 742
Basic and diluted net income per common unit	$ 0.25	$ 0.73	$ 0.13	$ 1.38
Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation	484.0	484.0	484.0	484.0
LNG [Member]
Revenues
Revenues	$ 2,959	$ 1,597	$ 5,447	$ 3,266
Revenues from contracts with customers	2,955	1,597	5,443	3,266
LNG—affiliate [Member]
Revenues
Revenues from contracts with customers	1,135	211	1,892	425
LNG—related party[Member]
Revenues
Revenues from contracts with customers	4	0	4	0
Regasification [Member]
Revenues
Revenues from contracts with customers	68	67	136	134
Other [Member]
Revenues
Revenues from contracts with customers	$ 15	$ 14	$ 30	$ 27

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Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 1,111	$ 876
Restricted cash and cash equivalents	78	98
Trade and other receivables, net of current expected credit losses	723	580
Accounts receivable—affiliate	485	232
Accounts receivable—related party	0	1
Advances to affiliate	136	141
Inventory	170	176
Current derivative assets	153	21
Other current assets	104	87
Total current assets	2,960	2,212
Property, plant and equipment, net of accumulated depreciation	16,861	16,830
Operating lease assets	94	98
Debt issuance costs, net of accumulated amortization	10	12
Derivative assets	36	33
Other non-current assets, net	169	173
Total assets	20,130	19,358
Current liabilities
Accounts payable	31	21
Accrued liabilities	1,576	1,073
Accrued liabilities—related party	6	4
Current debt, net of discount and debt issuance costs	1,497	0
Due to affiliates	58	67
Deferred revenue	124	155
Deferred revenue—affiliate	0	1
Current operating lease liabilities	9	8
Current derivative liabilities	478	16
Total current liabilities	3,779	1,345
Long-term debt, net of premium, discount and debt issuance costs	15,693	17,177
Operating lease liabilities	85	89
Derivative liabilities	3,178	11
Other non-current liabilities—affiliate	20	18
Partners' equity (deficit)
Common unitholders’ interest (484.0 million units issued and outstanding at both June 30, 2022 and December 31, 2021)		1,024
General partner’s interest (2% interest with 9.9 million units issued and outstanding at June 30, 2022 and December 31, 2021)		(306)
Total partners' equity (deficit)	(2,625)	718
Total liabilities and partners' equity (deficit)	$ 20,130	$ 19,358

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Consolidated Balance Sheets Parentheticals - shares shares in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2022	Dec. 31, 2021	Mar. 31, 2022	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020
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	484.0	484.0	484.0	484.0
General Partner [Member]
General Partners' Capital Account, Units Outstanding	9.9	9.9	9.9	9.9	9.9	9.9

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Consolidated Statements of Partners' Equity - USD ($) shares in Millions, $ in Millions	Total	Common Units [Member]	General Partner [Member]
Units, Outstanding, beginning of period at Dec. 31, 2020		484.0
Partners' equity, beginning of period at Dec. 31, 2020	$ 539	$ 714	$ (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	$ 7
Distributions		$ (316)	(35)
Units, Outstanding, end of period at Mar. 31, 2021		484.0
Partners' equity, end of period at Mar. 31, 2021	535	$ 738	$ (203)
General partner units, Outstanding, end of period at Mar. 31, 2021			9.9
Units, Outstanding, beginning of period at Dec. 31, 2020		484.0
Partners' equity, beginning of period at Dec. 31, 2020	539	$ 714	$ (175)
General partner units, Outstanding, beginning of period at Dec. 31, 2020			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income	742
Units, Outstanding, end of period at Jun. 30, 2021		484.0
Partners' equity, end of period at Jun. 30, 2021	571	$ 805	$ (234)
General partner units, Outstanding, end of period at Jun. 30, 2021			9.9
Units, Outstanding, beginning of period at Mar. 31, 2021		484.0
Partners' equity, beginning of period at Mar. 31, 2021	535	$ 738	$ (203)
General partner units, Outstanding, beginning of period at Mar. 31, 2021			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income	395	387	$ 8
Distributions		$ (320)	(39)
Units, Outstanding, end of period at Jun. 30, 2021		484.0
Partners' equity, end of period at Jun. 30, 2021	571	$ 805	$ (234)
General partner units, Outstanding, end of period at Jun. 30, 2021			9.9
Units, Outstanding, beginning of period at Dec. 31, 2021		484.0
Partners' equity, beginning of period at Dec. 31, 2021	718	$ 1,024	$ (306)
General partner units, Outstanding, beginning of period at Dec. 31, 2021			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income	159	157	$ 2
Novated IPM Agreement	2,712	2,712
Distributions		$ (339)	(56)
Units, Outstanding, end of period at Mar. 31, 2022		484.0
Partners' equity, end of period at Mar. 31, 2022	(2,230)	$ (1,870)	$ (360)
General partner units, Outstanding, end of period at Mar. 31, 2022			9.9
Units, Outstanding, beginning of period at Dec. 31, 2021		484.0
Partners' equity, beginning of period at Dec. 31, 2021	718	$ 1,024	$ (306)
General partner units, Outstanding, beginning of period at Dec. 31, 2021			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income	501
Units, Outstanding, end of period at Jun. 30, 2022		484.0
Partners' equity, end of period at Jun. 30, 2022	(2,625)	$ (2,043)	$ (582)
General partner units, Outstanding, end of period at Jun. 30, 2022			9.9
Units, Outstanding, beginning of period at Mar. 31, 2022		484.0
Partners' equity, beginning of period at Mar. 31, 2022	(2,230)	$ (1,870)	$ (360)
General partner units, Outstanding, beginning of period at Mar. 31, 2022			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income	342	335	$ 7
Distributions		$ (508)	(229)
Units, Outstanding, end of period at Jun. 30, 2022		484.0
Partners' equity, end of period at Jun. 30, 2022	$ (2,625)	$ (2,043)	$ (582)
General partner units, Outstanding, end of period at Jun. 30, 2022			9.9

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Consolidated Statements of Partners' Equity Parentheticals - $ / shares	3 Months Ended
	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Mar. 31, 2021
Common Units [Member]
Distributions Paid, Per Unit	$ 1.05	$ 0.700	$ 0.660	$ 0.655

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Cash flows from operating activities
Net income	$ 501	$ 742
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	309	277
Amortization of debt issuance costs, premium and discount	15	15
Loss on modification or extinguishment of debt	0	54
Losses (gains) on derivative instruments, net	819	(54)
Net cash provided by (used for) settlement of derivative instruments	(37)	18
Other	16	13
Changes in operating assets and liabilities:
Trade and other receivables, net of current expected credit losses	(208)	32
Accounts receivable—affiliate	(269)	119
Advances to affiliate	7	3
Inventory	4	(9)
Accounts payable and accrued liabilities	491	(48)
Accrued liabilities—related party	2	0
Due to affiliates	5	(13)
Deferred revenue	(31)	(32)
Other, net	(39)	(49)
Other, net—affiliate	1	7
Net cash provided by operating activities	1,586	1,075
Cash flows from investing activities
Property, plant and equipment	(239)	(316)
Net cash used in investing activities	(239)	(316)
Cash flows from financing activities
Proceeds from issuances of debt	0	1,500
Redemptions and repayments of debt	0	(1,500)
Debt issuance and other financing costs	0	(20)
Debt extinguishment costs	0	(40)
Distributions to owners	(1,132)	(710)
Other	0	8
Net cash used in financing activities	(1,132)	(762)
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	215	(3)
Cash, Cash Equivalents—beginning of period	974	1,307
Cash, Cash Equivalents—end of period	$ 1,189	$ 1,304

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Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021	Jun. 30, 2021	Dec. 31, 2020
Balances per Consolidated Balance Sheets:
Cash and cash equivalents	$ 1,111	$ 876
Restricted cash and cash equivalents	78	98
Total cash, cash equivalents and restricted cash and cash equivalents	$ 1,189	$ 974	$ 1,304	$ 1,307

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Nature of Operations and Basis of Presentation

6 Months Ended

Jun. 30, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We own the natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”) which has six operational Trains, with Train 6 achieving substantial completion on February 4, 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include five LNG storage tanks, vaporizers and two marine berths, with 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”).

We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive final investment decision.

As of June 30, 2022, Cheniere owned 48.6% of our limited partner interest in the form of 239.9 million of our common units. Cheniere also owns 100% of our general partner interest and our incentive distribution rights (“IDRs”).

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of CQP have been prepared in accordance with GAAP for interim financial information and in accordance 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, 2021.

Results of operations for the three and six months ended June 30, 2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2022.

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

ASU 2020-04

In March 2020, the FASB issued 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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Unitholders' Equity

6 Months Ended

Jun. 30, 2022

Partners' Capital Notes [Abstract]

Unitholders' Equity

UNITHOLDERS’ EQUITY

The common units represent limited partner interests in us, which entitle the unitholders to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. Although common unitholders are not obligated to fund losses of the Partnership, their 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 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.

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 we have paid to date have been made from accumulated operating surplus as defined in the partnership agreement.

As of June 30, 2022, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.4% by CQP Target Holdco L.L.C. (“CQP Target Holdco”) and other affiliates of Blackstone 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. CQP Target Holdco’s equity interests are 50.00% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone and 50.00% owned by BIF IV Cypress Aggregator (Delaware) LLC, an affiliate of Brookfield. The ownership of CQP Target Holdco, Blackstone and Brookfield are based on their most recent filings with the SEC.

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Restricted Cash and Cash Equivalents

6 Months Ended

Jun. 30, 2022

Restricted Cash and Cash Equivalents [Abstract]

Restricted Cash and Cash Equivalents

RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents consist 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 June 30, 2022 and December 31, 2021, we had $78 million and $98 million of restricted cash and cash equivalents, 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.

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Trade and Other Receivables, Net of Current Expected Credit Losses

6 Months Ended

Jun. 30, 2022

Receivables [Abstract]

Trade and Other Receivables, Net of Current Expected Credit Losses

TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

Trade and other receivables, net of current expected credit losses consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
Trade receivables	$	648	$	546
Other receivables	75		34
Total trade and other receivables, net of current expected credit losses	$	723	$	580

XML

Inventory

6 Months Ended

Jun. 30, 2022

Inventory Disclosure [Abstract]

Inventory

INVENTORY

Inventory consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
Materials	$	95	$	86
LNG	34		45
Natural gas	41		43
Other	—		2
Total inventory	$	170	$	176

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Property, Plant and Equipment, Net of Accumulated Depreciation

6 Months Ended

Jun. 30, 2022

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
LNG terminal
Terminal and interconnecting pipeline facilities	$	19,447	$	16,973
Construction-in-process	609		2,746
Accumulated depreciation	(3,199)		(2,893)
Total LNG terminal, net of accumulated depreciation	16,857		16,826
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(26)		(25)
Total fixed assets, net of accumulated depreciation	4		4
Property, plant and equipment, net of accumulated depreciation	$	16,861	$	16,830

The following table shows depreciation expense and offsets to LNG terminal costs (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Depreciation expense	$	155	$	137	$	307	$	275
Offsets to LNG terminal costs (1)	—		—		148		—

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

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Derivative Instruments

6 Months Ended

Jun. 30, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts, including those under SPL’s IPM agreement, for the 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, in which case such changes are capitalized.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis (in millions):

	Fair Value Measurements as of
	June 30, 2022								December 31, 2021
	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	$	(15)	$	(3,456)	$	(3,467)	$	2	$	(13)	$	38	$	27

We value our Liquefaction Supply Derivatives using a market or option-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, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed.

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 and volatility.

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 and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of June 30, 2022 and December 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	$(3,456)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.845) - $0.765 / $0.032
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	97% - 604% / 217%

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

(2)Spread contemplates U.S. dollar-denominated pricing.

Increases or decreases in basis or pricing spreads, 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 (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021			2022		2021
Balance, beginning of period	$	(3,162)	$	(36)		$	38	$	(21)
Realized and mark-to-market gains (losses):
Included in cost of sales	(309)		67			63		58
Purchases and settlements:
Purchases (1)	8		1			(3,549)		—
Settlements	7		1			(8)		(4)
Balance, end of period	$	(3,456)	$	33		$	(3,456)	$	33
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(309)	$	67		$	63	$	58

(1)Includes any assignments during the period.

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 and the unconditional contractual right of set-off 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 depending on the position of the derivative. 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 holds Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The remaining minimum terms of the Physical Liquefaction Supply Derivatives range up to 15 years, some of which commence upon the satisfaction of certain conditions precedent. The terms of the Financial Liquefaction Supply Derivatives range up to approximately two years.

The forward notional amount for our Liquefaction Supply Derivatives was approximately 5,484 TBtu and 5,194 TBtu as of June 30, 2022 and December 31, 2021, respectively, excluding notional amounts associated with extension options that were uncertain to be taken as of June 30, 2022.

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Income (in millions):

	Gain (Loss) Recognized in Consolidated Statements of Income
Consolidated Statements of Income Location (1)	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
LNG revenues	$	4	$	—	$	4	$	—
Cost of sales	(298)		56		(823)		54

(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.

Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets

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	June 30, 2022		December 31, 2021
Current derivative assets	$	153	$	21
Derivative assets	36		33
Total derivative assets	189		54
Current derivative liabilities	(478)		(16)
Derivative liabilities	(3,178)		(11)
Total derivative liabilities	(3,656)		(27)
Derivative asset (liability), net	$	(3,467)	$	27

(1)Does not include collateral posted with counterparties by us of $9 million and $7 million, as of June 30, 2022 and December 31, 2021, respectively, which are included in other current assets in our Consolidated Balance Sheets.

Consolidated Balance Sheets Presentation

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

	Liquefaction Supply Derivatives
As of June 30, 2022
Gross assets	$	232
Offsetting amounts	(43)
Net assets	$	189
Gross liabilities	$	(3,681)
Offsetting amounts	25
Net liabilities	$	(3,656)
As of December 31, 2021
Gross assets	$	79
Offsetting amounts	(25)
Net assets	$	54
Gross liabilities	$	(33)
Offsetting amounts	6
Net liabilities	$	(27)

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Accrued Liabilities

6 Months Ended

Jun. 30, 2022

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
Natural gas purchases	$	1,160	$	786
Interest costs and related debt fees	203		180
LNG terminal and related pipeline costs	195		101
Other accrued liabilities	18		6
Total accrued liabilities	$	1,576	$	1,073

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Debt

6 Months Ended

Jun. 30, 2022

Debt Disclosure [Abstract]

Debt

DEBT

Debt consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
SPL:
Senior Secured Notes:
5.625% due 2023	$	1,500	$	1,500
5.75% due 2024	2,000		2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.27% weighted average rate due 2037	1,282		1,282
Total SPL Senior Secured Notes	13,132		13,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Total debt - SPL	13,132		13,132
CQP:
Senior Notes:
4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
Total CQP Senior Notes	4,200		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Total debt - CQP	4,200		4,200
Total debt	17,332		17,332
Short-term debt	(1,497)		—
Unamortized premium, discount and debt issuance costs, net	(142)		(155)
Total long-term debt, net of premium, discount and debt issuance costs	$	15,693	$	17,177

Credit Facilities

Below is a summary of our credit facilities outstanding as of June 30, 2022 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities
Total facility size	$	1,200	$	750
Less:
Outstanding balance	—		—
Letters of credit issued	363		—
Available commitment	$	837	$	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%
Commitment fees on undrawn balance	0.15%		0.49%
Maturity date	March 19, 2025		May 29, 2024

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. We and SPL are restricted from making distributions under agreements governing our and SPL’s indebtedness generally until, among other requirements, deposits are made into any required debt

service reserve accounts and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.

As of June 30, 2022, 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 June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Total interest cost	$	223	$	241	$	447	$	488
Capitalized interest	(7)		(32)		(28)		(62)
Total interest expense, net of capitalized interest	$	216	$	209	$	419	$	426

Fair Value Disclosures

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

	June 30, 2022				December 31, 2021
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	16,050	$	15,429	$	16,050	$	17,496
Senior notes — Level 3 (2)	1,282		1,204		1,282		1,466

(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.

The estimated fair value of our credit facilities approximates the principal amount outstanding 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

6 Months Ended

Jun. 30, 2022

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 (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021			2022		2021
LNG revenues	$	2,955	$	1,597		$	5,443	$	3,266
LNG revenues—affiliate	1,135		211			1,892		425
LNG revenues—related party	4		—			4		—
Regasification revenues	68		67			136		134
Other revenues	15		14			30		27
Total revenues from customers	4,177		1,889			7,505		3,852
Net derivative gain (1)	4		—			4		—
Total revenues	$	4,181	$	1,889		$	7,509	$	3,852

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

Contract Assets and Liabilities

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

	June 30,		December 31,
	2022		2021
Contract assets, net of current expected credit losses	$	1	$	1

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

	Six Months Ended June 30, 2022
Deferred revenue, beginning of period	$	155
Cash received but not yet recognized in revenue	124
Revenue recognized from prior period deferral	(155)
Deferred revenue, end of period	$	124

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

	Six Months Ended June 30, 2022
Deferred revenue—affiliate, beginning of period	$	3
Cash received but not yet recognized in revenue	5
Revenue recognized from prior period deferral	(3)
Deferred revenue—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:

	June 30, 2022			December 31, 2021
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	52.3	9	$	49.3	9
LNG revenues—affiliate	2.1		3	2.1		3
Regasification revenues	1.7		2	1.9		4
Total revenues	$	56.1		$	53.3

(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 75% and 55% of our LNG revenues from contracts included in the table above during the three months ended June 30, 2022 and 2021, respectively, and approximately 72% and 53% of our LNG revenues from contracts included in the table above during the six months ended June 30, 2022 and 2021, respectively, were related to variable consideration received from customers. Approximately 100% and 91% of our LNG revenues—affiliate from contracts included in the table above during the three and six months ended June 30, 2022 and 2021, respectively, were related to variable consideration received from customers. During each of the three and six months ended June 30, 2022, approximately 6% of our regasification revenues were related to variable consideration received from customers and during each of the three and six months ended June 30, 2021, approximately 5% 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.

Termination Agreement with Chevron

In June 2022, Chevron U.S.A. Inc. (“Chevron”) entered into an agreement with SPLNG providing for the early termination of the TUA between the parties for a lump sum fee of $765 million (the “Termination Fee”). Upon SPLNG’s receipt of the Termination Fee, obligations pursuant to the TUA will terminate, including Chevron’s obligation to pay SPLNG capacity payments totaling $125 million annually (adjusted for inflation) through 2029. The termination agreement became effective on July 6, 2022, and we will recognize revenue, inclusive of the Termination Fee, over the remaining 2022 period.

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Related Party Transactions

6 Months Ended

Jun. 30, 2022

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 (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
LNG revenues—affiliate
Cheniere Marketing Agreements	$	1,100	$	209	$	1,845	$	419
Contracts for Sale and Purchase of Natural Gas and LNG	35		2		47		6
Total LNG revenues—affiliate	1,135		211		1,892		425
LNG revenues—related party
Natural Gas Transportation and Storage Agreements	4		—		4		—
Cost of sales—affiliate
Cheniere Marketing Agreements	—		—		—		34
Contracts for Sale and Purchase of Natural Gas and LNG	57		12		62		20
Total cost of sales—affiliate	57		12		62		54
Cost of sales—related party
Natural Gas Transportation and Storage Agreements	1		1		1		1
Operating and maintenance expense—affiliate
Services Agreements	41		35		79		69
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	15		12		27		22
General and administrative expense—affiliate
Services Agreements	24		21		47		42

As of June 30, 2022 and December 31, 2021, we had $485 million and $232 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. The Base SPA was subsequently amended 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.

Cheniere Marketing Letter Agreements

In May 2022, SPL and Cheniere Marketing entered into a letter agreement for the sale of up to 32 TBtu of LNG to be delivered between 2023 and 2025 at a price of 115% of Henry Hub plus $3.00 per MMBtu.

Cheniere Marketing has letter agreements with SPL to purchase up to 306 cargoes of LNG to be delivered between 2022 and 2027 at a weighted average price of $1.95 plus 115% of Henry Hub.

SPL and Cheniere Marketing had a letter agreement for the sale of up to 30 cargoes of LNG that were delivered in 2021 at a price of 115% of Henry Hub plus $0.728 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 indirectly acquired a portion of our limited partner interests in September 2020 through its purchase of a portion of CQP Target Holdco’s equity interests. We recorded accrued liabilities—related party of $6 million and $4 million as of June 30, 2022 and December 31, 2021, respectively, with this related party.

Services Agreements

As of June 30, 2022 and December 31, 2021, we had $136 million and $141 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.

CQP 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 through 2042. 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 through 2029. 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) through 2029 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 necessary services required to operate and maintain the Liquefaction Project. After each Train of the Liquefaction Project 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 is required to 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 through 2042. 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 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 is required to pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, SPL is required to pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such Train through 2042.

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.

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 as of June 30, 2022 and December 31, 2021, respectively, and $15 million of other non-current liabilities—affiliate as of both June 30, 2022 and December 31, 2021, from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

SPLNG is able to sell and purchase natural gas and LNG under agreements with Cheniere Marketing. Under these agreements, SPLNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase price paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third party costs incurred by Cheniere Marketing with respect to the receipt, purchase and delivery of natural gas or LNG to the Sabine Pass LNG Terminal.

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. Tug Services distributed $4 million and $3 million during the three months ended June 30, 2022 and 2021, respectively, and $5 million and $4 million during the six months ended June 30, 2022 and 2021, respectively, to Cheniere Terminals, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ Equity (Deficit).

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG terminal export agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG Terminal.  SPLNG did not record any revenues associated with this agreement during the three and six months ended June 30, 2022 and 2021.

State Tax Sharing Agreements

SPLNG, SPL and CTPL each have a state tax sharing agreement with Cheniere.  Under these agreements, Cheniere has agreed to prepare and file all state and local tax returns which each of the entities 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, each of the respective entities will pay to Cheniere an amount equal to the state and local tax that each of the entities would be required to pay if its state and local tax liability were calculated on a separate company basis. To date, there have been no state and local tax payments demanded by Cheniere under the tax sharing agreements. The agreements for SPLNG, SPL and CTPL are effective for tax returns due on or after January 2008, August 2012 and May 2013, respectively.

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Net Income per Common Unit

6 Months Ended

Jun. 30, 2022

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 (Deficit). On July 25, 2022, we declared a cash distribution of $1.060 per common unit to unitholders of record as of August 4, 2022 and the related general partner distribution to be paid on August 12, 2022. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.285 per unit.

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).

	Total		Limited Partner Common Units		General Partner Units		IDR
Three Months Ended June 30, 2022
Net income	$	342
Declared distributions	743		513		15		215
Assumed allocation of undistributed net loss (1)	$	(401)	(393)		(8)		—
Assumed allocation of net income			$	120	$	7	$	215
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	0.25
Three Months Ended June 30, 2021
Net income	$	395
Declared distributions	361		322		7		32
Assumed allocation of undistributed net income (1)	$	34	33		1		—
Assumed allocation of net income			$	355	$	8	$	32
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	0.73
Six Months Ended June 30, 2022
Net income	$	501
Declared distributions	1,476		1,021		30		425
Assumed allocation of undistributed net loss (1)	$	(975)	(955)		(20)		—
Assumed allocation of net income			$	66	$	10	$	425
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	0.13
Six Months Ended June 30, 2021
Net income	$	742
Declared distributions	716		641		14		61
Assumed allocation of undistributed net income (1)	$	26	25		1		—
Assumed allocation of net income			$	666	$	15	$	61
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	1.38

(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 (loss).

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Customer Concentration

6 Months Ended

Jun. 30, 2022

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 trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended June 30,		Six Months Ended June 30,		June 30,	December 31,
	2022	2021	2022	2021	2022	2021
Customer A	23%	26%	26%	27%	20%	28%
Customer B	18%	18%	16%	16%	19%	17%
Customer C	18%	17%	18%	18%	13%	*
Customer D	16%	16%	15%	16%	16%	14%
Customer E	14%	12%	13%	12%	*	12%
Customer F	*	*	*	*	*	12%

* Less than 10%

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Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2022

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):

	Six Months Ended June 30,
	2022		2021
Cash paid during the period for interest on debt, net of amounts capitalized	$	377	$	410

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $332 million and $252 million as of June 30, 2022 and 2021, respectively.

Novation of IPM Agreement from Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”)

In March 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project, SPL and CCL Stage III, formerly a wholly owned direct subsidiary of Cheniere that merged with and into Corpus Christi Liquefaction, LLC, entered into an agreement to assign to SPL an IPM agreement to purchase 140,000 MMBtu per day of natural gas at a price based on the Platts Japan Korea Marker (“JKM”), for a term of approximately 15 years beginning in early 2023. The transaction has been accounted for as a transfer between entities under common control, which required us to recognize the obligations assumed at the historical basis of Cheniere. Upon the transfer, which occurred on March 15, 2022, we recognized $2.7 billion in distributions to Cheniere’s common unitholder interest within our Consolidated Statements of Partners’ Equity (Deficit) based on our assumption of current derivative liabilities and derivative liabilities of $142 million and $2.6 billion, respectively, which represented a non-cash financing activity

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Nature of Operations and Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation, Policy

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of CQP have been prepared in accordance with GAAP for interim financial information and in accordance 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, 2021.

Results of operations for the three and six months ended June 30, 2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2022.

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

ASU 2020-04

In March 2020, the FASB issued 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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Trade and Other Receivables, Net of Current Expected Credit Losses (Tables)

6 Months Ended

Jun. 30, 2022

Receivables [Abstract]

Schedule of Accounts and Other Receivables, Net of Current Expected Credit Losses

Trade and other receivables, net of current expected credit losses consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
Trade receivables	$	648	$	546
Other receivables	75		34
Total trade and other receivables, net of current expected credit losses	$	723	$	580

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Inventory (Tables)

6 Months Ended

Jun. 30, 2022

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
Materials	$	95	$	86
LNG	34		45
Natural gas	41		43
Other	—		2
Total inventory	$	170	$	176

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Property, Plant and Equipment, Net of Accumulated Depreciation (Tables)

6 Months Ended

Jun. 30, 2022

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
LNG terminal
Terminal and interconnecting pipeline facilities	$	19,447	$	16,973
Construction-in-process	609		2,746
Accumulated depreciation	(3,199)		(2,893)
Total LNG terminal, net of accumulated depreciation	16,857		16,826
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(26)		(25)
Total fixed assets, net of accumulated depreciation	4		4
Property, plant and equipment, net of accumulated depreciation	$	16,861	$	16,830

Schedule of Depreciation and Offsets to LNG Terminal Costs

The following table shows depreciation expense and offsets to LNG terminal costs (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Depreciation expense	$	155	$	137	$	307	$	275
Offsets to LNG terminal costs (1)	—		—		148		—

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2022

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 (in millions):

	Fair Value Measurements as of
	June 30, 2022								December 31, 2021
	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	$	(15)	$	(3,456)	$	(3,467)	$	2	$	(13)	$	38	$	27

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 June 30, 2022 and December 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	$(3,456)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.845) - $0.765 / $0.032
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	97% - 604% / 217%

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

(2)Spread contemplates U.S. dollar-denominated pricing.

Fair Value, Liabilities 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 (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021			2022		2021
Balance, beginning of period	$	(3,162)	$	(36)		$	38	$	(21)
Realized and mark-to-market gains (losses):
Included in cost of sales	(309)		67			63		58
Purchases and settlements:
Purchases (1)	8		1			(3,549)		—
Settlements	7		1			(8)		(4)
Balance, end of period	$	(3,456)	$	33		$	(3,456)	$	33
Change in unrealized gains (losses) relating to instruments still held at end of period	$	(309)	$	67		$	63	$	58

(1)Includes any assignments during the period.

Derivative Instruments, Gain (Loss)

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Income (in millions):

	Gain (Loss) Recognized in Consolidated Statements of Income
Consolidated Statements of Income Location (1)	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
LNG revenues	$	4	$	—	$	4	$	—
Cost of sales	(298)		56		(823)		54

(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.

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	June 30, 2022		December 31, 2021
Current derivative assets	$	153	$	21
Derivative assets	36		33
Total derivative assets	189		54
Current derivative liabilities	(478)		(16)
Derivative liabilities	(3,178)		(11)
Total derivative liabilities	(3,656)		(27)
Derivative asset (liability), net	$	(3,467)	$	27

(1)Does not include collateral posted with counterparties by us of $9 million and $7 million, as of June 30, 2022 and December 31, 2021, respectively, which are included in other current assets in our Consolidated Balance Sheets.

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) for our derivative instruments that are presented on a net basis on our Consolidated Balance Sheets:

	Liquefaction Supply Derivatives
As of June 30, 2022
Gross assets	$	232
Offsetting amounts	(43)
Net assets	$	189
Gross liabilities	$	(3,681)
Offsetting amounts	25
Net liabilities	$	(3,656)
As of December 31, 2021
Gross assets	$	79
Offsetting amounts	(25)
Net assets	$	54
Gross liabilities	$	(33)
Offsetting amounts	6
Net liabilities	$	(27)

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Accrued Liabilities (Tables)

6 Months Ended

Jun. 30, 2022

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

Accrued liabilities consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
Natural gas purchases	$	1,160	$	786
Interest costs and related debt fees	203		180
LNG terminal and related pipeline costs	195		101
Other accrued liabilities	18		6
Total accrued liabilities	$	1,576	$	1,073

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Debt (Tables)

6 Months Ended

Jun. 30, 2022

Debt Disclosure [Abstract]

Schedule of Debt Instruments

Debt consisted of the following (in millions):

	June 30,		December 31,
	2022		2021
SPL:
Senior Secured Notes:
5.625% due 2023	$	1,500	$	1,500
5.75% due 2024	2,000		2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.27% weighted average rate due 2037	1,282		1,282
Total SPL Senior Secured Notes	13,132		13,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Total debt - SPL	13,132		13,132
CQP:
Senior Notes:
4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
Total CQP Senior Notes	4,200		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Total debt - CQP	4,200		4,200
Total debt	17,332		17,332
Short-term debt	(1,497)		—
Unamortized premium, discount and debt issuance costs, net	(142)		(155)
Total long-term debt, net of premium, discount and debt issuance costs	$	15,693	$	17,177

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of June 30, 2022 (in millions):

	SPL Working Capital Facility		CQP Credit Facilities
Total facility size	$	1,200	$	750
Less:
Outstanding balance	—		—
Letters of credit issued	363		—
Available commitment	$	837	$	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%
Commitment fees on undrawn balance	0.15%		0.49%
Maturity date	March 19, 2025		May 29, 2024

Schedule of Interest Expense

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Total interest cost	$	223	$	241	$	447	$	488
Capitalized interest	(7)		(32)		(28)		(62)
Total interest expense, net of capitalized interest	$	216	$	209	$	419	$	426

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):

	June 30, 2022				December 31, 2021
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	$	16,050	$	15,429	$	16,050	$	17,496
Senior notes — Level 3 (2)	1,282		1,204		1,282		1,466

(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.

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Revenues from Contracts with Customers (Tables)

6 Months Ended

Jun. 30, 2022

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table represents a disaggregation of revenue earned from contracts with customers (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021			2022		2021
LNG revenues	$	2,955	$	1,597		$	5,443	$	3,266
LNG revenues—affiliate	1,135		211			1,892		425
LNG revenues—related party	4		—			4		—
Regasification revenues	68		67			136		134
Other revenues	15		14			30		27
Total revenues from customers	4,177		1,889			7,505		3,852
Net derivative gain (1)	4		—			4		—
Total revenues	$	4,181	$	1,889		$	7,509	$	3,852

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

Contract with Customer, Asset

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

	June 30,		December 31,
	2022		2021
Contract assets, net of current expected credit losses	$	1	$	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):

	Six Months Ended June 30, 2022
Deferred revenue, beginning of period	$	155
Cash received but not yet recognized in revenue	124
Revenue recognized from prior period deferral	(155)
Deferred revenue, end of period	$	124

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

	Six Months Ended June 30, 2022
Deferred revenue—affiliate, beginning of period	$	3
Cash received but not yet recognized in revenue	5
Revenue recognized from prior period deferral	(3)
Deferred revenue—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:

	June 30, 2022			December 31, 2021
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	52.3	9	$	49.3	9
LNG revenues—affiliate	2.1		3	2.1		3
Regasification revenues	1.7		2	1.9		4
Total revenues	$	56.1		$	53.3

(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)

6 Months Ended

Jun. 30, 2022

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 (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
LNG revenues—affiliate
Cheniere Marketing Agreements	$	1,100	$	209	$	1,845	$	419
Contracts for Sale and Purchase of Natural Gas and LNG	35		2		47		6
Total LNG revenues—affiliate	1,135		211		1,892		425
LNG revenues—related party
Natural Gas Transportation and Storage Agreements	4		—		4		—
Cost of sales—affiliate
Cheniere Marketing Agreements	—		—		—		34
Contracts for Sale and Purchase of Natural Gas and LNG	57		12		62		20
Total cost of sales—affiliate	57		12		62		54
Cost of sales—related party
Natural Gas Transportation and Storage Agreements	1		1		1		1
Operating and maintenance expense—affiliate
Services Agreements	41		35		79		69
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	15		12		27		22
General and administrative expense—affiliate
Services Agreements	24		21		47		42

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Net Income per Common Unit (Tables)

6 Months Ended

Jun. 30, 2022

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).

	Total		Limited Partner Common Units		General Partner Units		IDR
Three Months Ended June 30, 2022
Net income	$	342
Declared distributions	743		513		15		215
Assumed allocation of undistributed net loss (1)	$	(401)	(393)		(8)		—
Assumed allocation of net income			$	120	$	7	$	215
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	0.25
Three Months Ended June 30, 2021
Net income	$	395
Declared distributions	361		322		7		32
Assumed allocation of undistributed net income (1)	$	34	33		1		—
Assumed allocation of net income			$	355	$	8	$	32
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	0.73
Six Months Ended June 30, 2022
Net income	$	501
Declared distributions	1,476		1,021		30		425
Assumed allocation of undistributed net loss (1)	$	(975)	(955)		(20)		—
Assumed allocation of net income			$	66	$	10	$	425
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	0.13
Six Months Ended June 30, 2021
Net income	$	742
Declared distributions	716		641		14		61
Assumed allocation of undistributed net income (1)	$	26	25		1		—
Assumed allocation of net income			$	666	$	15	$	61
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	1.38

(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 (loss).

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Customer Concentration (Tables)

6 Months Ended

Jun. 30, 2022

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 trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively:

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended June 30,		Six Months Ended June 30,		June 30,	December 31,
	2022	2021	2022	2021	2022	2021
Customer A	23%	26%	26%	27%	20%	28%
Customer B	18%	18%	16%	16%	19%	17%
Customer C	18%	17%	18%	18%	13%	*
Customer D	16%	16%	15%	16%	16%	14%
Customer E	14%	12%	13%	12%	*	12%
Customer F	*	*	*	*	*	12%

* Less than 10%

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2022

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Six Months Ended June 30,
	2022		2021
Cash paid during the period for interest on debt, net of amounts capitalized	$	377	$	410

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Nature of Operations and Basis of Presentation (Details) shares in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2022 milliontonnes / yr item unit mi trains shares	Dec. 31, 2021
Cheniere Partners [Member]
Nature of Operations and Basis of Presentation [Line Items]
General Partner Ownership Interest Percentage	2.00%	2.00%
Cheniere Partners [Member] | Cheniere [Member]
Nature of Operations and Basis of Presentation [Line Items]
Limited Partner Ownership Percentage	48.60%
General Partner Ownership Interest Percentage	100.00%
Cheniere Partners [Member] | Cheniere [Member] | Common Units [Member]
Nature of Operations and Basis of Presentation [Line Items]
Partners' Capital Account, Units, Units Held | shares	239.9
Sabine Pass LNG Terminal [Member]
Nature of Operations and Basis of Presentation [Line Items]
Number of Liquefaction LNG Trains Operating | trains	6
Total Production Capability | milliontonnes / yr	30
Number Of LNG Storage Tanks | unit	5
Number of Marine Berths Operating	2
Number of Marine Berths Constructing	1
Creole Trail Pipeline [Member]
Nature of Operations and Basis of Presentation [Line Items]
Length of Natural Gas Pipeline | mi	94

XML

Unitholders' Equity (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
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%
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] | CQP Target Holdco LLC [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	50.00%
BIF IV Cypress Aggregator (Delaware) LLC [Member] | CQP Target Holdco LLC [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	50.00%

XML

Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 78	$ 98
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 78	$ 98

XML

Trade and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Receivables [Abstract]
SPL trade receivable	$ 648	$ 546
Other receivables	75	34
Total trade and other receivables, net of current expected credit losses	$ 723	$ 580

XML

Inventory (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Inventory [Line Items]
Inventory	$ 170	$ 176
Materials [Member]
Inventory [Line Items]
Inventory	95	86
LNG [Member]
Inventory [Line Items]
Inventory	34	45
Natural gas [Member]
Inventory [Line Items]
Inventory	41	43
Other [Member]
Inventory [Line Items]
Inventory	$ 0	$ 2

XML

Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment, Net of Accumulated Depreciation (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 16,861	$ 16,830
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(3,199)	(2,893)
Property, plant and equipment, net of accumulated depreciation	16,857	16,826
LNG terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	19,447	16,973
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	609	2,746
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	30	29
Accumulated depreciation	(26)	(25)
Property, plant and equipment, net of accumulated depreciation	$ 4	$ 4

XML

Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Depreciation and Offsets to LNG Terminal Costs (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Property, Plant and Equipment [Abstract]
Depreciation expense		$ 155	$ 137	$ 307	$ 275
Offsets to LNG terminal costs	[1]	$ 0	$ 0	$ 148	$ 0

[1] We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction.

XML

Derivative Instruments - Narrative (Details) - SPL [Member] - tbtu	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	5,484	5,194
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	15 years
Financial Liquefaction Supply Derivatives | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	2 years

XML

Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (3,467)	$ 27
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	2
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	(15)	(13)
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	$ (3,456)	$ 38

XML

Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - USD ($)		6 Months Ended
		Jun. 30, 2022	Dec. 31, 2021
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability		$ (3,467,000,000)	$ 27,000,000
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability		(3,456,000,000)	$ 38,000,000
Physical Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability		(3,456,000,000)
Physical Liquefaction Supply Derivatives [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Market Approach
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	$ (1.845)
Physical Liquefaction Supply Derivatives [Member] | Minimum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation Technique, Option Pricing Model
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	97.00%
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Market Approach
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	$ 0.765
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation Technique, Option Pricing Model
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	604.00%
Physical Liquefaction Supply Derivatives [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation, Market Approach
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	$ 0.032
Physical Liquefaction Supply Derivatives [Member] | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member] | Valuation Technique, Option Pricing Model
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	217.00%

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

[2] Spread contemplates U.S. dollar-denominated pricing.

XML

Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (3,162)	$ (36)	$ 38	$ (21)
Realized and mark-to-market gains (losses):
Included in cost of sales		(309)	67	63	58
Purchases and settlements:
Purchases	[1]	8	1	(3,549)	0
Settlements		7	1	(8)	(4)
Balance, end of period		(3,456)	33	(3,456)	33
Change in unrealized gains (losses) relating to instruments still held at end of period		$ (309)	$ 67	$ 63	$ 58

[1] Includes any assignments during the period.

XML

Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
LNG revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ 4	$ 0	$ 4	$ 0
Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ (298)	$ 56	$ (823)	$ 54

[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.

XML

Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Jun. 30, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Current derivative assets		$ 153	$ 21
Derivative assets		36	33
Total derivative assets	[1]	189	54
Current derivative liabilities		(478)	(16)
Derivative liabilities		(3,178)	(11)
Total derivative liabilities	[1]	(3,656)	(27)
Derivative asset (liability), net	[1]	(3,467)	27
Derivative, collateral posted by us		9	7
Current Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[1]	153	21
Derivative Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	[1]	36	33
Current Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Current derivative liabilities	[1]	(478)	(16)
Derivative Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	[1]	$ (3,178)	$ (11)

[1] Does not include collateral posted with counterparties by us of $9 million and $7 million, as of June 30, 2022 and December 31, 2021, respectively, which are included in other current assets in our Consolidated Balance Sheets.

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Derivative Instruments - Balance Sheet Presentation Table (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (3,467)	$ 27
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	232	79
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	(43)	(25)
Derivative Assets (Liabilities), at Fair Value, Net	189	54
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(3,681)	(33)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	25	6
Derivative Assets (Liabilities), at Fair Value, Net	$ (3,656)	$ (27)

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Accrued Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Accrued Liabilities, Current [Abstract]
Natural gas purchases	$ 1,160	$ 786
Interest costs and related debt fees	203	180
LNG terminal and related pipeline costs	195	101
Other accrued liabilities	18	6
Total accrued liabilities	$ 1,576	$ 1,073

XML

Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 17,332	$ 17,332
Current debt, net of discount and debt issuance costs	(1,497)	0
Unamortized premium, discount and debt issuance costs, net	(142)	(155)
Long-term Debt, Net of Premium, Discount and Debt Issuance Costs	15,693	17,177
SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	13,132	13,132
2023 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2024 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage	5.75%
2025 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage	5.625%
2026 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage	5.875%
2027 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage	5.00%
2028 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,350	1,350
Debt Instrument, Interest Rate, Stated Percentage	4.20%
2030 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage	4.50%
2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,282	1,282
2037 SPL Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.27%
SPL Working Capital Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0	0
CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	4,200	4,200
2029 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage	4.50%
2031 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage	4.00%
2032 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,200	1,200
Debt Instrument, Interest Rate, Stated Percentage	3.25%
CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0	0
SPL [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	13,132	13,132
Cheniere Partners [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 4,200	$ 4,200

XML

Debt - Credit Facilities Table (Details) $ in Millions	6 Months Ended
	Jun. 30, 2022 USD ($) unit Rate	Dec. 31, 2021 USD ($)
Line of Credit Facility [Line Items]
Outstanding balance	$ 17,332	$ 17,332
Debt, Minimum Historical Debt Service Coverage Ratio And Projected Debt Service Coverage Ratio | unit	1.25
SPL Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 1,200
Outstanding balance	0	0
Letters of credit issued	363
Available commitment	$ 837
Debt Instrument, Description of Variable Rate Basis	LIBOR or base rate
Line of Credit Facility, Commitment Fee Percentage	0.15%
Debt Instrument, Maturity Date	Mar. 19, 2025
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%
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%
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%
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%
CQP Credit Facilities [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 750
Outstanding balance	0	$ 0
Letters of credit issued	0
Available commitment	$ 750
Debt Instrument, Description of Variable Rate Basis	LIBOR or base rate
Line of Credit Facility, Commitment Fee Percentage	0.49%
Debt Instrument, Maturity Date	May 29, 2024
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%
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%
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%
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%

XML

Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Debt Disclosure [Abstract]
Total interest cost	$ 223	$ 241	$ 447	$ 488
Capitalized interest	(7)	(32)	(28)	(62)
Total interest expense, net of capitalized interest	$ 216	$ 209	$ 419	$ 426

XML

Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - Senior Notes [Member] - USD ($) $ in Millions		Jun. 30, 2022	Dec. 31, 2021
Carrying Amount [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	$ 16,050	$ 16,050
Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[2]	1,282	1,282
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]	15,429	17,496
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]	$ 1,204	$ 1,466

[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.

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Revenues from Contracts with Customers - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 4,177	$ 1,889	$ 7,505	$ 3,852
Net derivative gain	[1]	4	0	4	0
Total revenues		4,181	1,889	7,509	3,852
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		2,955	1,597	5,443	3,266
Total revenues		2,959	1,597	5,447	3,266
LNG—affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		1,135	211	1,892	425
LNG—related party[Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		4	0	4	0
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		68	67	136	134
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 15	$ 14	$ 30	$ 27

[1] See Note 7—Derivative Instruments for additional information about our derivatives.

XML

Revenues from Contracts with Customers - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Contract assets, net of current expected credit losses	$ 1	$ 1
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	155
Cash received but not yet recognized in revenue	124
Revenue recognized from prior period deferral	(155)
Deferred revenues, end of period	124
Deferred revenue—affiliate, beginning of period	3
Cash received but not yet recognized in revenue	5
Revenue recognized from prior period deferral	(3)
Deferred revenue—affiliate, end of period	$ 5

XML

Revenues from Contracts with Customers - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price						$ 53,300
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 56,100		$ 56,100
LNG [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage		75.00%	55.00%	72.00%	53.00%
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price						$ 49,300
Weighted Average Recognition Timing	[1]					9 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 52,300		$ 52,300
Weighted Average Recognition Timing	[1]	9 years		9 years
LNG—affiliate [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage		100.00%	91.00%	100.00%	91.00%
LNG—affiliate [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price						$ 2,100
Weighted Average Recognition Timing	[1]					3 years
LNG—affiliate [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 2,100		$ 2,100
Weighted Average Recognition Timing	[1]	3 years		3 years
Regasification [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage		6.00%	5.00%	6.00%	5.00%
Regasification [Member] | Chevron U.S.A. Inc.
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract Termination Fee				$ 765
Revenue, Performance Obligation, Fixed Consideration				125
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price						$ 1,900
Weighted Average Recognition Timing	[1]					4 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 1,700		$ 1,700
Weighted Average Recognition Timing	[1]	2 years		2 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		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Related Party Transaction [Line Items]
LNG revenues—affiliate	$ 1,135	$ 211	$ 1,892	$ 425
Cost of sales—affiliate	57	12	62	54
Cost of sales—related party	1	1	1	1
Operating and maintenance expense—affiliate	41	35	79	69
Operating and maintenance expense—related party	15	12	27	22
General and administrative expense—affiliate	24	21	47	42
Cheniere Marketing Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	1,100	209	1,845	419
Cost of sales—affiliate	0	0	0	34
Contracts for Sale and Purchase of Natural Gas And LNG [Member]
Related Party Transaction [Line Items]
LNG revenues—affiliate	35	2	47	6
Cost of sales—affiliate	57	12	62	20
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—related party	4	0	4	0
Cost of sales—related party	1	1	1	1
Operating and maintenance expense—related party	15	12	27	22
Service Agreements [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense—affiliate	41	35	79	69
General and administrative expense—affiliate	$ 24	$ 21	$ 47	$ 42

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Related Party Transactions - LNG Terminal Capacity Agreements (Details)	6 Months Ended
	Jun. 30, 2022 USD ($) tbtu Cargo	Dec. 31, 2021 USD ($)
Related Party Transaction [Line Items]
Accounts receivable—affiliate	$ 485,000,000	$ 232,000,000
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] | 2022 Letter Agreement
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] | 2022 Letter Agreement | Maximum [Member]
Related Party Transaction [Line Items]
Contract Volume | tbtu	32
SPL [Member] | Cheniere Marketing [Member] | 2022 - 2027 Letter Agreements
Related Party Transaction [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
LNG Volume, Weighted Average Purchase Price Per MMBtu	$ 1.95
SPL [Member] | Cheniere Marketing [Member] | 2022 - 2027 Letter Agreements | Maximum [Member]
Related Party Transaction [Line Items]
Contract Cargoes | Cargo	306
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

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Related Party Transactions - Service Agreements (Details) - USD ($)	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Advances to Affiliate Current	$ 136,000,000	$ 141,000,000
Service Agreements [Member]
Related Party Transaction [Line Items]
Advances to Affiliate Current	136,000,000	$ 141,000,000
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		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Related Party Transaction [Line Items]
Accounts receivable—affiliate	$ 485,000,000		$ 485,000,000		$ 232,000,000
Accrued liabilities—related party	6,000,000		6,000,000		4,000,000
Due to affiliates	58,000,000		58,000,000		67,000,000
Other non-current liabilities—affiliate	20,000,000		20,000,000		18,000,000
Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
LNG revenues—related party	4,000,000	$ 0	4,000,000	$ 0
SPLNG [Member] | Cooperative Endeavor Agreements [Member]
Related Party Transaction [Line Items]
Aggregate commitment under the Agreement	25,000,000		$ 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		3,000,000		2,000,000
Other non-current liabilities—affiliate	15,000,000		15,000,000		15,000,000
SPLNG [Member] | Cheniere Marketing [Member] | LNG Terminal Export Agreement [Member]
Related Party Transaction [Line Items]
LNG revenues—related party	0	0	0	0
Tug Services [Member] | Cheniere Terminals [Member] | Terminal Marine Services Agreement [Member]
Related Party Transaction [Line Items]
General Partner Distributions	4,000,000	$ 3,000,000	$ 5,000,000	$ 4,000,000
SPL and CTPL [Member] | Natural Gas Transportation and Storage Agreements [Member]
Related Party Transaction [Line Items]
Related Party Agreement Term			10 years
Accrued liabilities—related party	$ 6,000,000		$ 6,000,000		$ 4,000,000
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				6 Months Ended
		Jul. 25, 2022	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2022	Jun. 30, 2021
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income			$ 342	$ 159	$ 395	$ 347	$ 501	$ 742
Declared distributions			743		361		1,476	716
Assumed allocation of undistributed net income (loss)	[1]		$ (401)		$ 34		$ (975)	$ 26
Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation			484.0		484.0		484.0	484.0
Basic and diluted net income per common unit			$ 0.25		$ 0.73		$ 0.13	$ 1.38
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income			$ 335	157	$ 387	340
Declared distributions			513		322		$ 1,021	$ 641
Assumed allocation of undistributed net income (loss)	[1]		(393)		33		(955)	25
Assumed allocation of net income			$ 120		$ 355		$ 66	$ 666
Weighted average number of common units outstanding used for basic and diluted net income per common unit calculation			484.0		484.0		484.0	484.0
Basic and diluted net income per common unit			$ 0.25		$ 0.73		$ 0.13	$ 1.38
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		$ 1.060
Common Units [Member] | Subsequent Event [Member] | Base Amount
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit		0.775
Common Units [Member] | Subsequent Event [Member] | Variable Amount
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.285
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income			$ 7	$ 2	$ 8	$ 7
Declared distributions			15		7		$ 30	$ 14
Assumed allocation of undistributed net income (loss)	[1]		(8)		1		(20)	1
Assumed allocation of net income			7		8		10	15
IDR [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Declared distributions			215		32		425	61
Assumed allocation of undistributed net income (loss)	[1]		0		0		0	0
Assumed allocation of net income			$ 215		$ 32		$ 425	$ 61

[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 (loss).

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Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member]	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	23.00%	26.00%	26.00%	27.00%
Customer A [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			20.00%		28.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	18.00%	16.00%	16.00%
Customer B [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			19.00%		17.00%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	17.00%	18.00%	18.00%
Customer C [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			13.00%
Customer D [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.00%	16.00%	15.00%	16.00%
Customer D [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			16.00%		14.00%
Customer E [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	14.00%	12.00%	13.00%	12.00%
Customer E [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage					12.00%
Customer F [Member] | Accounts Receivable, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage					12.00%

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Supplemental Cash Flow Information (Details) $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2022 USD ($) MMBTU	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)	Mar. 15, 2022 USD ($)	Dec. 31, 2021 USD ($)
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest on debt, net of amounts capitalized		$ 377	$ 410
Novation of IPM agreement from Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”)	$ (2,700)
Balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate)		332	$ 252
Nonmonetary Transaction [Line Items]
Current derivative liabilities		478			$ 16
Derivative liabilities		$ 3,178			$ 11
Novation of IPM Agreement [Member] | Cheniere Corpus Christi Liquefaction Stage III
Nonmonetary Transaction [Line Items]
Contract Volume | MMBTU	140,000
IPM Agreement, Term of Agreement	15 years
Current derivative liabilities				$ 142
Derivative liabilities				$ 2,600