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 September 30, 2023

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 October 26, 2023, the registrant had 484,039,123 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 Operations	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	8
	Note 3—Restricted Cash and Cash Equivalents	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	13
	Note 9—Debt	13
	Note 10—Revenues	15
	Note 11—Related Party Transactions	17
	Note 12—Net Income (Loss) per Common Unit	18
	Note 13—Customer Concentration	20
	Note 14—Supplemental Cash Flow Information	20
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	30
Item 4.	Controls and Procedures	30
Part II. Other Information
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 5.	Other Information	32
Item 6.	Exhibits	32
	Signatures	33

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
ESG	environmental, social and governance
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
SOFR	Secured Overnight Financing Rate
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 September 30, 2023, 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. 

2

PART I.     FINANCIAL INFORMATION

ITEM I.     CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

(unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues
LNG revenues	$	1,564	$	3,130	$	5,085	$	8,577
LNG revenues—affiliate	515		1,376		1,745		3,268
LNG revenues—related party	—		—		—		4
Regasification revenues	34		455		101		591
Other revenues	15		15		47		45
Total revenues	2,128		4,976		6,978		12,485
Operating costs and expenses
Cost of sales (excluding items shown separately below)	682		4,739		1,598		10,445
Cost of sales—affiliate	2		104		20		166
Cost of sales—related party	—		—		—		1
Operating and maintenance expense	211		189		680		550
Operating and maintenance expense—affiliate	38		39		120		118
Operating and maintenance expense—related party	14		18		44		45
General and administrative expense	2		3		8		3
General and administrative expense—affiliate	20		23		66		70
Depreciation and amortization expense	166		160		500		469
Other	4		—		6		—
Other—affiliate	1		—		1		—
Total operating costs and expenses	1,140		5,275		3,043		11,867
Income (loss) from operations	988		(299)		3,935		618
Other income (expense)
Interest expense, net of capitalized interest	(205)		(222)		(620)		(641)
Loss on modification or extinguishment of debt	(4)		—		(6)		—
Interest and dividend income	12		7		39		10
Total other expense	(197)		(215)		(587)		(631)
Net income (loss)	$	791	$	(514)	$	3,348	$	(13)
Basic and diluted net income (loss) per common unit (1)	$	1.19	$	(1.49)	$	5.53	$	(1.36)
Weighted average basic and diluted number of common units outstanding	484.0		484.0		484.0		484.0

(1)In computing basic and diluted net income (loss) per common unit, net income (loss) is reduced by the amount of undistributed net income (loss) allocated to participating securities other than common units, as required under the two-class method. See Note 12—Net Income (Loss) per Common Unit.

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)

	September 30,		December 31,
	2023		2022
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	499	$	904
Restricted cash and cash equivalents	35		92
Trade and other receivables, net of current expected credit losses	287		627
Trade receivables—affiliate	167		551
Advances to affiliate	141		177
Inventory	131		160
Current derivative assets	34		24
Margin deposits	—		35
Other current assets, net	60		50
Total current assets	1,354		2,620
Property, plant and equipment, net of accumulated depreciation	16,341		16,725
Operating lease assets	83		89
Debt issuance costs, net of accumulated amortization	17		8
Derivative assets	111		28
Other non-current assets, net	166		163
Total assets	$	18,072	$	19,633
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities
Accounts payable	$	50	$	32
Accrued liabilities	641		1,378
Accrued liabilities—related party	5		6
Current debt, net of discount and debt issuance costs	349		—
Due to affiliates	42		74
Deferred revenue	151		144
Deferred revenue—affiliate	1		3
Current operating lease liabilities	11		10
Current derivative liabilities	294		769
Other current liabilities	5		5
Total current liabilities	1,549		2,421
Long-term debt, net of discount and debt issuance costs	15,600		16,198
Operating lease liabilities	74		80
Finance lease liabilities	15		18
Derivative liabilities	1,731		3,024
Other non-current liabilities	52		—
Other non-current liabilities—affiliate	24		23
Partners’ deficit
Common unitholders’ interest (484.0 million units issued and outstanding at both September 30, 2023 and December 31, 2022)	647		(1,118)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at both September 30, 2023 and December 31, 2022)	(1,620)		(1,013)
Total partners’ deficit	(973)		(2,131)
Total liabilities and partners’ deficit	$	18,072	$	19,633

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 Nine Months Ended September 30, 2023
	Common Unitholders’ Interest			General Partner’s Interest			Total Partners’ Deficit
	Units	Amount		Units	Amount
Balance at December 31, 2022	484.0	$	(1,118)	9.9	$	(1,013)	$	(2,131)
Net income	—	1,897		—	38		1,935
Distributions
Common units, $1.070/unit	—	(518)		—	—		(518)
General partner units	—	—		—	(236)		(236)
Balance at March 31, 2023	484.0	261		9.9	(1,211)		(950)
Net income	—	610		—	12		622
Distributions
Common units, $1.03/unit	—	(499)		—	—		(499)
General partner units	—	—		—	(219)		(219)
Balance at June 30, 2023	484.0	372		9.9	(1,418)		(1,046)
Net income	—	774		—	17		791
Distributions
Common units, $1.03/unit	—	(499)		—	—		(499)
General partner units	—	—		—	(219)		(219)
Balance at September 30, 2023	484.0	$	647	9.9	$	(1,620)	$	(973)

Three and Nine Months Ended September 30, 2022
	Common Unitholders’ Interest			General Partner’s Interest			Total Partners’ Equity (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)
Net loss	—	(503)		—	(11)		(514)
Distributions
Common units, $1.06/unit	—	(513)		—	—		(513)
General partner units	—	—		—	(232)		(232)
Balance at September 30, 2022	484.0	$	(3,059)	9.9	$	(825)	$	(3,884)

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)

	Nine Months Ended September 30,
	2023		2022
Cash flows from operating activities
Net income (loss)	$	3,348	$	(13)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	500		469
Amortization of debt issuance costs, premium and discount	22		22
Loss on modification or extinguishment of debt	6		—
Total losses (gains) on derivative instruments, net	(1,867)		2,447
Net cash provided by (used for) settlement of derivative instruments	6		(54)
Other	16		28
Changes in operating assets and liabilities:
Trade and other receivables, net of current expected credit losses	340		(290)
Trade receivables—affiliate	384		(231)
Advances to affiliate	31		(10)
Inventory	30		(67)
Margin deposits	35		(52)
Contract assets	—		(387)
Accounts payable and accrued liabilities	(662)		592
Accrued liabilities—related party	(2)		5
Due to affiliates	(30)		2
Total deferred revenue	59		6
Other, net	(21)		(30)
Other, net—affiliate	(2)		5
Net cash provided by operating activities	2,193		2,442
Cash flows from investing activities
Property, plant and equipment, net	(170)		(356)
Other	(6)		—
Net cash used in investing activities	(176)		(356)
Cash flows from financing activities
Proceeds from issuances of debt	1,397		—
Redemptions and repayments of debt	(1,650)		—
Debt issuance and other financing costs	(32)		—
Debt extinguishment costs	(1)		—
Distributions	(2,190)		(1,877)
Other	(3)		—
Net cash used in financing activities	(2,479)		(1,877)
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	(462)		209
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	996		974
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$	534	$	1,183

Balances per Consolidated Balance Sheet:

	September 30,
	2023
Cash and cash equivalents	$	499
Restricted cash and cash equivalents	35
Total cash, cash equivalents and restricted cash and cash equivalents	$	534

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, 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 three marine berths. Additionally, the Sabine Pass LNG Terminal includes a 94-mile pipeline owned by our subsidiary, CTPL, that interconnects the Sabine Pass LNG Terminal with a number of large interstate and intrastate 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. In May 2023, certain of our subsidiaries entered the pre-filing review process with the FERC under the National Environmental Policy Act for an expansion adjacent to the Liquefaction Project with a potential production capacity of up to 20 mtpa of LNG. 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.

We do not have employees and thus we and our subsidiaries have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. See Note 11—Related Party Transactions for additional details of the activity under these services agreements during the three and nine months ended September 30, 2023 and 2022.

As of September 30, 2023, 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 and reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of the financial results for the interim periods presented. 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, 2022.

Results of operations for the three and nine months ended September 30, 2023 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2023.

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 as a result of the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.

As further detailed in Note 9—Debt, all of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through replacements of previous credit facilities subsequent to the effective date of ASU 2020-04. We elected to apply the optional expedients as applicable to certain replaced facilities; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.

7

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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 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 September 30, 2023, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.5% by CQP Target Holdco L.L.C. (“CQP Target Holdco”) and other affiliates of Blackstone Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) and 7.9% by the public. All of our 2% general partner interest was held by Cheniere. CQP Target Holdco’s equity interests are 50.0% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone, and 50.0% 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

As of September 30, 2023 and December 31, 2022, we had $35 million and $92 million of restricted cash and cash equivalents, respectively, for which the usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project as required under certain debt arrangements.

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):

	September 30,		December 31,
	2023		2022
Trade receivables	$	275	$	603
Other receivables	12		24
Total trade and other receivables, net of current expected credit losses	$	287	$	627

NOTE 5—INVENTORY

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
Materials	$	104	$	103
LNG	8		27
Natural gas	16		28
Other	3		2
Total inventory	$	131	$	160

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):

	September 30,		December 31,
	2023		2022
LNG terminal
Terminal and interconnecting pipeline facilities	$	20,122	$	20,072
Construction-in-process	201		140
Accumulated depreciation	(4,004)		(3,512)
Total LNG terminal, net of accumulated depreciation	16,319		16,700
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(26)		(25)
Total fixed assets, net of accumulated depreciation	4		4
Assets under finance leases
Tug vessels	23		23
Accumulated depreciation	(5)		(2)
Total assets under finance leases, net of accumulated depreciation	18		21
Property, plant and equipment, net of accumulated depreciation	$	16,341	$	16,725

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Depreciation expense	$	166	$	158	$	497	$	465
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

SPL has commodity derivatives consisting of natural gas supply contracts, including those under the IPM agreement, for the operation of the Liquefaction Project and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).

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

The following table shows the fair value of the derivative instruments that are required to be measured at fair value on a recurring basis, by the fair value hierarchy levels prescribed by GAAP (in millions):

	Fair Value Measurements as of
	September 30, 2023								December 31, 2022
	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)	$	13	$	(1)	$	(1,892)	$	(1,880)	$	(12)	$	(10)	$	(3,719)	$	(3,741)

We value the Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, which incorporates 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 the 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 significant portion of our 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 may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.

The Level 3 fair value measurements of the natural gas positions within the 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 the Level 3 Liquefaction Supply Derivatives as of September 30, 2023:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(1,892)	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.543) - $0.510 / $0.040
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	103% - 422% / 213%

(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 the Liquefaction Supply Derivatives.

10

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table shows the changes in the fair value of the Level 3 Liquefaction Supply Derivatives (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Balance, beginning of period	$	(2,255)	$	(3,456)	$	(3,719)	$	38
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)	294		(1,545)		1,275		(155)
Included in cost of sales, new deals (3)	8		—		23		—
Purchases and settlements:
Purchases (4)	—		3		—		(4,896)
Settlements (5)	59		(24)		522		(11)
Transfers out of level 3 (6)	2		(2)		7		—
Balance, end of period	$	(1,892)	$	(5,024)	$	(1,892)	$	(5,024)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period	$	302	$	(1,545)	$	1,298	$	(155)

(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume.  See settlements line item in this table.

(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.

(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.

(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period.

(5)Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.

(6)Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from those derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes SPL to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when the derivative instruments are in an asset position. Additionally, counterparties are at risk that SPL will be unable to meet its commitments in instances where the derivative instruments are in a liability position. We incorporate both SPL’s 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 the 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 firm terms of the Liquefaction Supply Derivatives range up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs.

The forward notional amount for the Liquefaction Supply Derivatives was approximately 5,642 TBtu and 5,972 TBtu as of September 30, 2023 and December 31, 2022, respectively, excluding notional amounts associated with extension options that were uncertain to be taken as of September 30, 2023.

11

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues	$	—	$	(3)	$	—	$	1
Cost of sales	365		(1,625)		1,867		(2,448)

(1)Does not include the realized value associated with Liquefaction Supply Derivatives 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 the Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):

	Fair Value Measurements as of (1)
Consolidated Balance Sheets Location	September 30, 2023		December 31, 2022
Current derivative assets	$	34	$	24
Derivative assets	111		28
Total derivative assets	145		52
Current derivative liabilities	(294)		(769)
Derivative liabilities	(1,731)		(3,024)
Total derivative liabilities	(2,025)		(3,793)
Derivative liability, net	$	(1,880)	$	(3,741)

(1)Does not include collateral posted by counterparties to us of $1 million as of September 30, 2023, which is included in other current liabilities on our Consolidated Balance Sheets, and collateral posted with counterparties by us of $35 million as of December 31, 2022, which is included in margin deposits on our Consolidated Balance Sheets.

Consolidated Balance Sheets Presentation

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

	Liquefaction Supply Derivatives
	September 30, 2023		December 31, 2022
Gross assets	$	172	$	57
Offsetting amounts	(27)		(5)
Net assets	$	145	$	52
Gross liabilities	$	(2,029)	$	(3,814)
Offsetting amounts	4		21
Net liabilities	$	(2,025)	$	(3,793)

12

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 8—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
Natural gas purchases	$	372	$	1,017
Interest costs and related debt fees	151		218
LNG terminal and related pipeline costs	86		137
Other accrued liabilities	32		6
Total accrued liabilities	$	641	$	1,378

NOTE 9—DEBT

Debt consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
SPL:
Senior Secured Notes:
5.75% due 2024 (the “2024 SPL Senior Notes”)	$	350	$	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
4.746% weighted average rate due 2037	1,782		1,782
Total SPL Senior Secured Notes	10,482		12,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	10,482		12,132
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
5.95% due 2033 (the “2033 CQP Senior Notes”)	1,400		—
Total CQP Senior Notes	5,600		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	5,600		4,200
Total debt	16,082		16,332
Current debt, net of discount and debt issuance costs	(349)		—
Long-term portion of unamortized discount and debt issuance costs, net	(133)		(134)
Total long-term debt, net of discount and debt issuance costs	$	15,600	$	16,198

13

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2023 (in millions):

	SPL Revolving Credit Facility (1)		CQP Revolving Credit Facility (1)
Total facility size	$	1,000	$	1,000
Less:
Outstanding balance	—		—
Letters of credit issued	284		—
Available commitment	$	716	$	1,000
Priority ranking	Senior secured		Senior unsecured
Interest rate on available balance (2)	SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.125% - 2.0% or base rate plus 0.125% - 1.0%
Commitment fees on undrawn balance (2)	0.075% - 0.30%		0.10% - 0.30%
Maturity date	June 23, 2028		June 23, 2028

(1)In June 2023, we and SPL refinanced and replaced the CQP Credit Facilities and the SPL Working Capital Facility with the CQP Revolving Credit Facility and the SPL Revolving Credit Facility, respectively, resulting in extended maturity dates, revised borrowing capacities, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

(2)The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.

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. SPL is restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.

As of September 30, 2023, 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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Total interest cost	$	207	$	231	$	626	$	678
Capitalized interest	(2)		(9)		(6)		(37)
Total interest expense, net of capitalized interest	$	205	$	222	$	620	$	641

14

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Fair Value Disclosures

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

	September 30, 2023				December 31, 2022
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	16,082	$	14,943	$	16,332	$	15,386

(1)As of both September 30, 2023 and December 31, 2022, $1.2 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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

The following table represents a disaggregation of revenue earned (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues from contracts with customers
LNG revenues	$	1,564	$	3,133	$	5,085	$	8,576
LNG revenues—affiliate	515		1,376		1,745		3,268
LNG revenues—related party	—		—		—		4
Regasification revenues	34		455		101		591
Other revenues	15		15		47		45
Total revenues from contracts with customers	2,128		4,979		6,978		12,484
Net derivative gain (loss) (1)	—		(3)		—		1
Total revenues	$	2,128	$	4,976	$	6,978	$	12,485

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

Termination Agreement with Chevron

In June 2022, Chevron U.S.A. (“Chevron”) entered into an agreement with SPLNG providing for the early termination of the TUA and an associated terminal marine services agreement between the parties and their affiliates (the “Termination Agreement”), effective July 2022, for a lump sum fee of $765 million (the “Termination Fee”). Obligations pursuant to the TUA and associated agreement, including Chevron’s obligation to pay SPLNG capacity payments totaling $125 million annually (adjusted for inflation) from 2023 through 2029, terminated on December 31, 2022, upon SPLNG’s receipt of the Termination Fee in December 2022. We allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which was recognized ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations.

Contract Assets and Liabilities

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

	September 30,		December 31,
	2023		2022
Contract assets, net of current expected credit losses	$	1	$	1

15

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 and other non-current liabilities on our Consolidated Balance Sheets (in millions):

	Nine Months Ended September 30, 2023
Deferred revenue, beginning of period	$	144
Cash received but not yet recognized in revenue	203
Revenue recognized from prior period deferral	(144)
Deferred revenue, end of period	$	203

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):

	Nine Months Ended September 30, 2023
Deferred revenue—affiliate, beginning of period	$	8
Cash received but not yet recognized in revenue	6
Revenue recognized from prior period deferral	(8)
Deferred revenue—affiliate, end of period	$	6

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:

	September 30, 2023			December 31, 2022
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	48.4	8	$	50.8	8
LNG revenues—affiliate	1.5		2	2.0		2
Regasification revenues	0.7		3	0.8		4
Total revenues	$	50.6		$	53.6

(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. Additionally, we have excluded variable consideration related to volumes that contractually are subject to additional liquefaction capacity beyond what is currently in construction or operation. The following table summarizes the amount of variable consideration earned under contracts with customers included in the table above:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues	53	%	78	%	55	%	74	%
LNG revenues—affiliate	64	%	77	%	68	%	76	%
Regasification revenues	7	%	1	%	7	%	2	%

16

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 11—RELATED PARTY TRANSACTIONS

Below is a summary of our transactions with our affiliates and other related parties, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues—affiliate
SPAs and Letter Agreements with Cheniere Marketing	$	513	$	1,328	$	1,742	$	3,173
Contracts for Sale and Purchase of Natural Gas and LNG with other affiliates	2		48		3		95
Total LNG revenues—affiliate	515		1,376		1,745		3,268
LNG revenues—related party
Natural Gas Transportation and Storage Agreements (1)	—		—		—		4
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	2		104		20		166
Cost of sales—related party
Natural Gas Transportation and Storage Agreements (1)	—		—		—		1
Operating and maintenance expense—affiliate
Services Agreements (see Note 1)	38		39		120		118
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements (1)	14		18		44		45
General and administrative expense—affiliate
Services Agreements (see Note 1)	20		23		66		70
Other—affiliate
Services Agreements (see Note 1)	1		—		1		—

(1)This related party is partially owned by Brookfield, who indirectly owns a portion of our limited partner interests.

Other Agreements

Terminal Marine Services Agreement

In connection with its tug boat leases, 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. Under this agreement, Tug Services distributed $4 million and $2 million during the three months ended September 30, 2023 and 2022, respectively, and $8 million and $7 million during the nine months ended September 30, 2023 and 2022, 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).

Cooperative Endeavor Agreements (“CEAs”)

SPLNG has executed 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. In 2018, SPLNG entered into a Memorandum of Understanding, which forgave $7 million of the dollar-for-dollar credits, and in 2022, an

17

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

agreement was reached to defer the commencement of the dollar-for-dollar credits until 2027. As of both September 30, 2023 and December 31, 2022, we had $17 million of amounts associated with dollar-for-dollar credits due on advance tax payments to the taxing authorities recorded to other non-current assets on our Consolidated Balance Sheets. 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. We had $17 million of other non-current liabilities—affiliate as of both September 30, 2023 and December 31, 2022 from these payments received from Cheniere Marketing.

NOTE 12—NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit for a given period is based on the distributions to the common unitholders with respect to earnings or losses of the reporting 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 declared by us during the period are presented on the Consolidated Statements of Partners’ Equity (Deficit). On October 27, 2023, we declared a cash distribution of $1.03 per common unit to unitholders of record as of November 6, 2023 and the related general partner distribution to be paid on November 14, 2023 with respect to the three months ended September 30, 2023. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.255 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 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.

18

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

	Total		Limited Partner Common Units		General Partner Units		IDR
Three Months Ended September 30, 2023
Net income	$	791
Declared distributions	714		499		14		201
Assumed allocation of undistributed net income (1)	$	77	75		1		—
Assumed allocation of net income			$	574	$	15	$	201
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	1.19
Three Months Ended September 30, 2022
Net loss	$	(514)
Declared distributions	753		518		15		220
Assumed allocation of undistributed net loss (1)	$	(1,267)	(1,242)		(25)		—
Assumed allocation of net loss			$	(724)	$	(10)	$	220
Weighted average units outstanding			484.0
Basic and diluted net loss per unit (2)			$	(1.49)
Nine Months Ended September 30, 2023
Net income	$	3,348
Declared distributions	2,142		1,496		43		603
Assumed allocation of undistributed net income (1)	$	1,206	1,181		24		—
Assumed allocation of net income			$	2,677	$	67	$	603
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	5.53
Nine Months Ended September 30, 2022
Net loss	$	(13)
Declared distributions	2,229		1,539		45		645
Assumed allocation of undistributed net loss (1)	$	(2,242)	(2,197)		(45)		—
Assumed allocation of net loss (1)			$	(658)	$	—	$	645
Weighted average units outstanding			484.0
Basic and diluted net loss per unit			$	(1.36)

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

(2)Basic and diluted net income (loss) per unit in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

19

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 13—CUSTOMER CONCENTRATION

The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2023	2022	2023	2022	2023	2022
Customer A	17%	18%	23%	23%	19%	27%
Customer B	18%	16%	16%	16%	14%	18%
Customer C	17%	14%	16%	16%	22%	*
Customer D	15%	16%	15%	16%	11%	18%
Customer E	*	10%	*	*	*	13%
Customer F	—%	12%	—%	*	*	*
Customer G	10%	*	11%	*	15%	*

* Less than 10%

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Nine Months Ended September 30,
	2023		2022
Cash paid during the period for interest on debt, net of amounts capitalized	$	658	$	585
Non-cash investing activity:
Unpaid purchases of property, plant and equipment, net	31		147

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 CCL, 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 was 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.

20

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

Information Regarding Forward-Looking Statements

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

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

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

•statements that we expect to commence or complete construction of our proposed LNG 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; and

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

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

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in our annual report on Form 10-K for the fiscal year ended December 31, 2022. 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, other industrial uses and back up for intermittent energy sources. 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 a 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, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has three marine berths, two of which can accommodate vessels with nominal capacity of up to 266,000 cubic meters and the third berth which can accommodate vessels with nominal capacity of up to 200,000 cubic meters, operational regasification facilities that include five LNG storage tanks with aggregate capacity of approximately 17 Bcfe and vaporizers with regasification capacity of approximately 4 Bcf/d. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects our facilities to several interstate and intrastate pipelines (the “Creole Trail Pipeline”).

Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted most of 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 an IPM agreement, in which the gas producer sells natural gas to us on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Through our SPAs and IPM agreement, we have contracted approximately 85% of the total production capacity from the Liquefaction Project with approximately 14 years of weighted average remaining life as of September 30, 2023.

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We remain focused on safety, 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. In May 2023, certain of our subsidiaries entered the pre-filing review process with the FERC under the National Environmental Policy Act (“NEPA”) for an expansion adjacent to the Liquefaction Project with a potential production capacity of up to 20 mtpa of LNG (the “SPL Expansion Project”). 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 management of our most important ESG impacts, risks and opportunities. In August 2023, Cheniere published The Power of Connection, its fourth Corporate Responsibility (“CR”) report, which details its approach and progress on ESG issues, including its collaboration with natural gas midstream companies, technology providers and leading academic institutions on life-cycle assessment (“LCA”) models, quantification, monitoring, reporting and verification (“QMRV”) of greenhouse gas emissions and other research and development projects. Cheniere also co-founded and sponsored the Energy Emissions Modeling and Data Lab (“EEMDL”), a multidisciplinary research and education initiative led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines. In addition, Cheniere commenced providing Cargo Emissions Tags (“CE Tags”) to our long-term customers in June 2022, and in October 2022 joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s (“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative. Cheniere’s CR report is available at cheniere.com/our-responsibility/reporting-center. Information on Cheniere’s 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, 2023 and through the filing date of this Form 10-Q include the following:  

Strategic

•In May 2023, certain of our subsidiaries entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project, and in April 2023, one of our subsidiaries executed a contract with Bechtel Energy Inc. to provide the front end engineering and design work on the project.

•On January 2, 2023, Corey Grindal, formerly Executive Vice President, Worldwide Trading, was promoted to Executive Vice President and Chief Operating Officer of Cheniere Partners GP.

Operational

•As of October 26, 2023, approximately 2,270 cumulative LNG cargoes totaling approximately 155 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

Financial

•On October 27, 2023, with respect to the third quarter of 2023, we declared a cash distribution of $1.03 per common unit to unitholders of record as of November 6, 2023 and the related general partner distribution to be paid on November 14, 2023. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.255 per unit.

•We completed the following debt transactions:

◦In September 2023, SPL redeemed $50 million of its 5.75% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”).

◦In June 2023, we issued $1.4 billion aggregate principal amount of 5.95% Senior Notes due 2033 (the “2033 CQP Senior Notes”). Using contributed proceeds from the 2033 CQP Senior Notes together with cash on hand, SPL redeemed $1.4 billion of its 2024 SPL Senior Notes in July 2023.

◦In June 2023, we entered into a $1.0 billion Senior Unsecured Revolving Credit and Guaranty Agreement (the “CQP Revolving Credit Facility”), and SPL entered into a $1.0 billion Senior Secured Revolving

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Credit and Guaranty Agreement (the “SPL Revolving Credit Facility”). The CQP Revolving Credit Facility and SPL Revolving Credit Facility each refinanced and replaced the respective existing credit facilities to, among other things, (1) extend the maturity date thereunder, (2) reduce the rate of interest and commitment fees applicable thereunder and (3) make certain other changes to the terms and conditions of the prior credit facilities.

•In August 2023, Fitch Ratings upgraded SPL’s senior secured debt and issuer credit ratings from BBB to BBB+ with a stable outlook.

•In February 2023, S&P Global Ratings upgraded its issuer credit rating of SPL from BBB to BBB+ with a stable outlook.

Results of Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions, except per unit data)	2023		2022		Variance		2023		2022		Variance
Revenues
LNG revenues	$	1,564	$	3,130	$	(1,566)	$	5,085	$	8,577	$	(3,492)
LNG revenues—affiliate	515		1,376		(861)		1,745		3,268		(1,523)
LNG revenues—related party	—		—		—		—		4		(4)
Regasification revenues	34		455		(421)		101		591		(490)
Other revenues	15		15		—		47		45		2
Total revenues	2,128		4,976		(2,848)		6,978		12,485		(5,507)
Operating costs and expenses
Cost of sales (excluding items shown separately below)	682		4,739		(4,057)		1,598		10,445		(8,847)
Cost of sales—affiliate	2		104		(102)		20		166		(146)
Cost of sales—related party	—		—		—		—		1		(1)
Operating and maintenance expense	211		189		22		680		550		130
Operating and maintenance expense—affiliate	38		39		(1)		120		118		2
Operating and maintenance expense—related party	14		18		(4)		44		45		(1)
General and administrative expense	2		3		(1)		8		3		5
General and administrative expense—affiliate	20		23		(3)		66		70		(4)
Depreciation and amortization expense	166		160		6		500		469		31
Other	4		—		4		6		—		6
Other—affiliate	1		—		1		1		—		1
Total operating costs and expenses	1,140		5,275		(4,135)		3,043		11,867		(8,824)
Income (loss) from operations	988		(299)		1,287		3,935		618		3,317
Other income (expense)
Interest expense, net of capitalized interest	(205)		(222)		17		(620)		(641)		21
Loss on modification or extinguishment of debt	(4)		—		(4)		(6)		—		(6)
Interest and dividend income	12		7		5		39		10		29
Total other expense	(197)		(215)		18		(587)		(631)		44
Net income (loss)	$	791	$	(514)	$	1,305	$	3,348	$	(13)	$	3,361
Basic and diluted net income (loss) per common unit	$	1.19	$	(1.49)	$	2.68	$	5.53	$	(1.36)	$	6.89

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Operational volumes loaded and recognized from the Liquefaction Project

	Three Months Ended September 30,			Nine Months Ended September 30,
	2023	2022	Variance	2023	2022	Variance
LNG volumes loaded and recognized as revenues (in TBtu)	362	363	(1)	1,118	1,110	8

Net income (loss)

The increases of $1.3 billion and $3.4 billion for the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to the favorable variances of $2.0 billion and $4.3 billion, respectively, from changes in fair value and settlements of derivatives. During the three and nine months ended September 30, 2023, we recognized gains of $217 million and $1.5 billion, respectively, due to non-cash favorable changes in fair value of the IPM agreement with Tourmaline Oil Marketing Corp. (the “Tourmaline IPM Agreement”) as a result of lower volatility in international gas prices compared to the same periods of 2022 and declines in international forward commodity curves, as compared to losses of $1.3 billion and $2.2 billion in the three and nine months ended September 30, 2022, respectively, following the assignment of the Tourmaline IPM Agreement to SPL from Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”) in March 2022. The 2022 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 shifts in the international forward commodity curve. The increases were partially offset by a reduction in LNG revenues, net of cost of sales and excluding the effect of derivatives (as further described above), of $261 million and $339 million for the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, which was attributable to lower margins on LNG delivered. The remaining offsetting variance is primarily attributable to a decrease in our regasification revenues primarily as a result of the early termination of one of our TUA agreements in December 2022.

The following is additional discussion of the significant drivers of the variance in net income (loss) by line item:

Revenues

The $2.8 billion and $5.5 billion decreases between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to:

•$2.4 billion and $5.0 billion decreases between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022 due to lower pricing per MMBtu, from decreased Henry Hub pricing; and

•$421 million and $490 million decreases in regasification revenues between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022 due to the early termination of one of our TUA agreements in December 2022. See Note 10—Revenues of our Notes to Consolidated Financial Statements for additional information on the termination agreement.

Operating costs and expenses

The $4.1 billion and $8.8 billion decreases between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, were primarily attributable to:

•$2.0 billion and $4.3 billion favorable variances between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, from changes in fair value and settlements of derivatives included in cost of sales, from losses of $1.6 billion and $2.4 billion in the three and nine months ended September 30, 2022, respectively, to gains of $365 million and $1.9 billion in the three and nine months ended September 30, 2023, respectively, primarily due to decreased international gas prices resulting in non-cash favorable changes in fair value of our commodity derivatives indexed to such prices, specifically associated with the Tourmaline IPM Agreement as discussed above under Net income (loss); and

•$2.2 billion and $4.7 billion decreases between the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022, in cost of sales excluding the effect of derivative changes described above, primarily as a result of $2.2 billion and $4.6 billion decreases, respectively, in cost of natural gas feedstock largely due to lower U.S. natural gas prices.

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The favorable variances were partially offset by increases in third party operating and maintenance expense of $22 million and $130 million for the three and nine months ended September 30, 2023, respectively, as compared to the same periods of 2022. For the nine months ended September 30, 2023, increases in third party operating and maintenance expense were primarily due to the completion of planned large-scale maintenance activities on two trains at the Liquefaction Project during June 2023. Further contributing to the increase in third party operating and maintenance expense during the three and nine months ended September 30, 2023 was other third party service and maintenance contract costs and natural gas transportation and storage capacity demand charges.

Significant factors affecting our results of operations

Below are significant factors that affect our results of operations.

Gains and losses on derivative instruments

Derivative instruments are utilized to manage our exposure to commodity-related marketing and price risks 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 that may be outside of our control, notwithstanding the operational intent to mitigate risk exposure over time.

Commissioning cargoes

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 nine months ended September 30, 2022, we realized offsets to LNG terminal costs of $148 million corresponding to 13 TBtu attributable to the sale of commissioning cargoes from Train 6 of the Liquefaction Project. We did not have any commissioning cargoes during the three months ended September 30, 2022 or the three and nine months ended September 30, 2023.

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. Additionally, we expect to meet our long term cash requirements by 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). Future material sources of liquidity are discussed below.

	September 30, 2023
Cash and cash equivalents	$	499
Restricted cash and cash equivalents designated for the Liquefaction Project	35
Available commitments under our credit facilities (1):
SPL Revolving Credit Facility	716
CQP Revolving Credit Facility	1,000
Total available commitments under our credit facilities	1,716
Total available liquidity	$	2,250

(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of September 30, 2023. See Note 9—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

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Our liquidity position subsequent to September 30, 2023 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. For further discussion of our future sources and uses of liquidity, see the liquidity and capital resources disclosures in our annual report on Form 10-K for the fiscal year ended December 31, 2022.

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 SPL 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. In addition, SPL’s operating costs are managed by subsidiaries of Cheniere under affiliate agreements, which may require SPL to advance cash to the respective affiliates, however the cash remains restricted to CQP 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.

Despite 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 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, $1.5 billion of 4.000% Senior Notes due 2031, $1.2 billion of 3.25% Senior Notes due 2032, and the 2033 CQP Senior Notes (collectively, the “CQP Senior Notes”) are jointly and severally guaranteed by each of our subsidiaries other than SPL and, subject to certain conditions governing its guarantee, 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 any claims by the Non-Guarantors’ creditors, including trade creditors.

Summarized Balance Sheets (in millions)	September 30,		December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	499	$	904
Accounts receivable from Non-Guarantors	41		55
Other current assets	39		40
Current assets—affiliate	139		171
Total current assets	718		1,170
Property, plant and equipment, net of accumulated depreciation	2,919		2,946
Other non-current assets, net	111		109
Total assets	$	3,748	$	4,225
LIABILITIES
Current liabilities
Due to affiliates	$	152	$	193
Deferred revenue from Non-Guarantors	22		24
Other current liabilities	141		95
Other current liabilities from Non-Guarantors	—		2
Total current liabilities	315		314
Long-term debt, net of premium, discount and debt issuance costs	5,541		4,159
Finance lease liabilities	15		18
Other non-current liabilities	70		78
Non-current liabilities—affiliate	18		18
Total liabilities	$	5,959	$	4,587

Summarized Statement of Income (in millions)	Nine Months Ended September 30, 2023
Revenues	$	148
Revenues from Non-Guarantors	409
Total revenues	557
Operating costs and expenses	181
Operating costs and expenses—affiliate	140
Operating costs and expenses—Non-Guarantors	9
Total operating costs and expenses	330
Income from operations	227
Net income	93

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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. 

	Nine Months Ended September 30,
	2023		2022
Net cash provided by operating activities	$	2,193	$	2,442
Net cash used in investing activities	(176)		(356)
Net cash used in financing activities	(2,479)		(1,877)
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	$	(462)	$	209

Operating Cash Flows

The $249 million decrease between the periods was primarily related to lower cash receipts from the sale of LNG cargoes from lower pricing per MMBtu as a result of decreased Henry Hub pricing, and regasification fees. The decrease was partially offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.

Investing Cash Flows

Cash outflows for property, plant and equipment during the nine months ended September 30, 2023 were primarily related to optimization and other site improvement projects. Cash outflows for property, plant and equipment during the nine months ended September 30, 2022 were primarily related to the construction costs for Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022.

Financing Cash Flows

The following table summarizes our financing activities (in millions):

	Nine Months Ended September 30,
	2023		2022
Proceeds from issuances of debt	$	1,397	$	—
Redemptions and repayments of debt	(1,650)		—
Debt issuance and other financing costs	(32)		—
Debt extinguishment costs	(1)		—
Distributions	(2,190)		(1,877)
Other	(3)		—
Net cash used in financing activities	$	(2,479)	$	(1,877)

Debt Activity

During the nine months ended September 30, 2023, we issued an aggregate principal amount of $1.4 billion of 2033 CQP Senior Notes, the proceeds of which were used with cash on hand to redeem $1.4 billion of the 2024 SPL Senior Notes. Additionally, during the nine months ended September 30, 2023, SPL purchased $200 million of the 2024 SPL Senior Notes in the open market and redeemed an additional $50 million of the 2024 SPL Senior Notes, which leaves only $350 million to be repaid for debt maturing in 2024.

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.

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The following provides a summary of distributions paid by us during the nine months ended September 30, 2023 and 2022:

				Total Distribution (in millions)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Common Units		General Partner Units		Incentive Distribution Rights
August 14, 2023	April 1 - June 30, 2023	$	1.030	$	499	$	14	$	201
May 15, 2023	January 1 - March 31, 2023	1.030		499		14		201
February 14, 2023	October 1 - December 31, 2022	1.070		518		15		220
August 12, 2022	April 1 - June 30, 2022	1.060		513		15		215
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

In addition, Tug Services distributed $8 million and $7 million during the nine months ended September 30, 2023 and 2022, respectively, to Cheniere Terminals in accordance with their terminal marine service agreement, which is recognized as part of the distributions to the holder of our general partner interest.

On October 27, 2023, with respect to the third quarter of 2023, we declared a cash distribution of $1.03 per common unit to unitholders of record as of November 6, 2023 and the related general partner distribution to be paid on November 14, 2023. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.255 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 ended December 31, 2022.

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

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

	September 30, 2023				December 31, 2022
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(1,880)	$	392	$	(3,741)	$	565

See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about the 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 Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our general partner’s management, including our general partner’s Chief Executive Officer and Chief Financial Officer, the

30

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. 

31

PART II.     OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. There have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2022, except for the update presented in our quarterly report on Form 10-Q for the quarterly period ended March 31, 2023.

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, 2022.

ITEM 5.    OTHER INFORMATION

Rule 10b5-1 under the Exchange Act provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits our directors and executive officers to enter into trading plans designed to comply with Rule 10b5-1. During the three-month period ending September 30, 2023, none of our executive officers or directors adopted or terminated a Rule 10b5-1 trading plan or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

ITEM 6.    EXHIBITS

Exhibit No.	Description
10.1*	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 8, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00076 Supplemental FERC Condition 80 Requirements, dated May 5, 2023, (ii) the Change Order CO-00077 Louisiana Sales and Use Tax Provisional Sum Closure, dated June 16, 2023, (iii) the Change Order CO-00078 Natural Gas Pipeline (NGPL) Security Coordination Provisional Sum Closure, dated June 22, 2023, (iv) the Change Order CO-00079 Insurance Provisional Sum Closure, dated July 27, 2023 and (v) the Change Order Co-00080 Borrowed Items, dated September 6, 2023
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 23, 2023)
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.

32

SIGNATURES

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

		CHENIERE ENERGY PARTNERS, L.P.
		By:	Cheniere Energy Partners GP, LLC, its general partner
Date:	November 1, 2023	By:	/s/ Zach Davis
			Zach Davis
			Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)
Date:	November 1, 2023	By:	/s/ David Slack
			David Slack
			Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

33

EX-10.1

Exhibit 10.1

CHANGE ORDER

SUPPLEMENTAL FERC CONDITION 80 REQUIREMENTS

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. CHANGE ORDER NUMBER: CO-00076 DATE OF CHANGE ORDER: 05-May-2023 DATE OF AGREEMENT: November 7, 2018

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 per Owner correspondence SPL4-BE-C23-036 dated 20-Feb-2023, the Parties agree Contractor shall augment the scope as stated under Clause 1(d) of previous Change Order CO-00072 dated 31-Oct-2022, as follows:

a.    Add a sixth (6th) elevated-oscillating firewater monitor with remote manual operation capability, the implementation of which requires the relocation of three (3) of five (5) firewater monitors added in accordance with Clause 1(d) of previous Change Order CO-00072; and

b.    For context: Per Clause 1(d) of previous CO-00072, the Agreement was amended for Contractor to install five (5) firewater hydrants or monitors for the entire length of the marine transfer piping (under FERC Condition 80 and associated conditions).

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, 68, 75)….................................................................................................................................................	$	8,116,678
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was.........................….	$	2,025,009,251
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ...............................................................................................................................................	$	0
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ...............................................................................................................................................	$	0
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be ......................	$	2,025,009,251

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, 62-74) ................	$	11,039,604
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was ............................	$	468,735,604
10. The Contract Price Applicable to Subproject 6(b) will be changed by this change order ..................	$	165,221
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order .......	$	0
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be ...................	$	468,900,825
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) …………….........................	$	2,493,744,855
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) ………………………………………….......................................................................................	$	165,221
16. The new Contract Price including this Change Order will be (add lines 14 and 15) ….....................	$	2,493,910,076

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 – This Work is performed post-Substantial Completion

Adjustment to other Changed Criteria for Subproject 6(b): N/A – This Work is performed post-Substantial Completion

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

Adjustment to Design Basis for Subproject 6(b): N/A – This Work is performed post-Substantial Completion

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A – This Work is performed post-Substantial Completion

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/ LL__ 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/ Laura Link
Owner	Contractor
David Craft	Steve Smith
Name	Name
SVP, Engineering & Construction	Senior Project Manager & Principal Vice President
Title	Title
July 18, 2023	June 27, 2023
Date of Signing	Date of Signing

CHANGE ORDER

LOUISIANA SALES AND USE TAX PROVISIONAL SUM CLOSURE

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc CHANGE ORDER NUMBER: CO-00077 DATE OF CHANGE ORDER: 16-Jun-2023 DATE OF AGREEMENT: November 7, 2018

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

1.    In accordance with Section 2.1 Louisiana Sales and Use Tax Provisional Sumof Schedule EE-2 of the Agreement, this Change Order amends Section 2.1 Louisiana Sales and Use Tax Provisional Sum to reflect actual and final costs incurred by Contractor, as follows:

a.The current amount for the Louisiana Sales and Use Tax Provisional Sum is U.S. $42,543,792;

b.The actual and final costs incurred by Contractor for the Louisiana Sales and Use Tax Provisional Sum is U.S. 29,361,818; and

c.The Louisiana Sales and Use Tax Provisional Sum amount is hereby reduced by Thirteen Million, One Hundred and Eighty-One Thousand, Nine Hundred and Seventy-Four U.S. Dollars (U.S. $13,181,974).

d.Therefore the final Louisiana Sales and Use TaxProvisional Sum amount as amended by this Change Order shall be Twenty-Nine Million, Three Hundred and Sixty-One Thousand, Eight Hundred and Eighteen U.S. Dollars (U.S. $29,361,818).

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

3.    The detailed reconciliation for this provisional sum is provided in Exhibit B of this Change Order.

4.    Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit C 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, 68, 75) ....................................................................................................................................................	$	8,116,678
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was .............................	$	2,025,009,251
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of …………………………………………..……...................................................................	$	0
5. The Provisional Sum Applicable to Subproject 6(a) will be reduced by this Change Order in the amount of ….........................................................................................................................................	$	13,181,974
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be ………….....	$	2,011,827,277
Adjustment to Contract Price Applicable to Subproject 6(b)
7. The original Contract Price Applicable to Subproject 6(b) (in CO-00009) was …..….......….............	$	457,969,000
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, 62-67, 69-74, 76).	$	11,204,825
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was ..….......................	$	468,900,825

10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order .............	$	0
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order ...........	$	0
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be .....................	$	468,900,825
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) ……………...........................	$	2,493,910,076
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, 10 and 11) .........................................................................................................................................................	$	13,181,974
16. The new Contract Price including this Change Order will be (add lines 14 and 15) ….......................	$	2,480,728,102

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

The following dates are modified: N/A

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

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

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

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

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

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

___________________________________________________________________________________________________

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

The following dates are modified: N/A

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

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

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

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

___________________________________________________________________________________________________

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change.Initials: /s/ SMS 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/ Steve Smith
Owner	Contractor
David Craft	Steve Smith
Name	Name
SVP, Engineering & Construction	Senior Project Manager & Principal Vice President
Title	Title
July 25, 2023	July 18, 2023
Date of Signing	Date of Signing

CHANGE ORDER

NATURAL GAS PIPELINE (NGPL) SECURITY COORDINATION PROVISIONAL SUM CLOSURE

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. CHANGE ORDER NUMBER: CO-00078 DATE OF CHANGE ORDER: 22-Jun-2023 DATE OF AGREEMENT: November 7, 2018

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

1.    In accordance with Section 2.4 NGPL Gate Access Security Coordination Provisional Sum of Schedule EE-2 of the Agreement, this Change Order amends Section 2.4 NGPL Gate Access Security Coordination Provisional Sum to reflect actual and final costs incurred by Contractor, as follows:

a.The current amount for the NGPL Gate Access Security Coordination Provisional Sum, as amended by previous Change Order CO-00046,is U.S. $253,207 (inclusive of 6% fee component);

b.The actual and final costs incurred by Contractor for the NGPL Gate Access Security Coordination Provisional Sum (inclusive of fee)is U.S. $264,576;

c.The NGPL Gate Access Security Coordination Provisional Sum amount is hereby increased by Eleven Thousand, Three Hundred and Sixty-Nine U.S. Dollars (U.S. $11,369);

d.Therefore the final NGPL Gate Access Security Coordination Provisional Sum amount as amended by this Change Order shall be Two Hundred and Sixty-Four Thousand, Five Hundred and Seventy-Six U.S. Dollars (U.S. $264,576); and

e.For context the NGPL Gate Access Security Coordination Provisional Sum services were provided in the period November 2019 through January 2022.

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

3.    The detailed reconciliation for this provisional sum is provided in Exhibit B of this Change Order.

4.    Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit C 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, 68, 75, 77)…................................................................................................................................	$	(5,065,296)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was …….................	$	2,011,827,277
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ..........................................................................................................................................	$	0
5. The Provisional Sum Applicable to Subproject 6(a) will be increased by this Change Order in the amount of...	$	11,369
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be ...................	$	2,011,838,646
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 authorize Change Orders (#14, 16, 19-20, 23, 25-27, 30-31, 33, 36-37, 39-40, 43-44, 50, 52, 59-60, 62-67, 69-74, 76) .....................................................................................................................................................	$	11,204,825
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was ..…..................	$	468,900,825
10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order .........	$	0
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order .....	$	0
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be ..............	$	468,900,825
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) ……………......................	$	2,480,728,102
15. The Contract Price will be increased by this Change Order in the amount of (add lines 4, 5, 10 and 11) .............................................................................................................................................	$	11,369
16. The new Contract Price including this Change Order will be (add lines 14 and 15) ........................	$	2,480,739,471

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

The following dates are modified: N/A

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

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

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

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

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

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

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

The following dates are modified: N/A

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

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

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

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

________________________________________________________________________________

Select either A or B:

[A]This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SMS 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 changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. 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/ Steve Smith
Owner	Contractor
David Craft	Steve Smith
Name	Name
SVP, Engineering & Construction	Senior Project Manager & Principal Vice President
Title	Title
July 25, 2023	July 18, 2023
Date of Signing	Date of Signing

CHANGE ORDER

INSURANCE PROVISIONAL SUM CLOSURE

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. CHANGE ORDER NUMBER: CO-00079 DATE OF CHANGE ORDER: 27-Jul-2023 DATE OF AGREEMENT: November 7, 2018

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

1.    In accordance with Section 2.3 Insurance Provisional Sum of Schedule EE-3 of the Agreement, this Change Order amends Section 2.3 Insurance Provisional Sum to reflect actual and final costs incurred by Contractor, as follows:

a.    The current amount for the Insurance Provisional Sum, as amended by previous Change Order(s) CO-00001, CO-00009, CO-00011 and CO-00031, is U.S. $39,840,850;

b.    The actual and final costs incurred by Contractor for the Insurance Provisional Sum is U.S. $39,840,110;

c.    Therefore the Insurance Provisional Sum amount is decreased by Seven Hundred and Forty U.S. Dollars (U.S. $740);

d.    Therefore the final Insurance Provisional Sum amount as amended by this Change Order shall be Thirty Nine Million, Eight Hundred and Forty Thousand, One Hundred and Ten U.S. Dollars (U.S. $39,840,110); and

2.    The detailed cost summary and reconciliation for this Change Order is provided in Exhibit A of this Change Order.

3.    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, 68, 75, 77, 78)......................................................................................................................................	$	(5,053,927)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was ...........................	$	2,011,838,646
4. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of …………………………………………..……..................................................................	$	0
5. The Provisional Sum Applicable to Subproject 6(a) will be decreased by this Change Order in the amount of …........................................................................................................................................	$	740
6. The Contract Price Applicable to Subproject 6(a) including this change Order will be....................	$	2,011,837,906
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, 62-67, 69-74, 76) .......................................................................................................................................................	$	11,204,825
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was ..….....................	$	468,900,825

10. The Contract Price Applicable to Subproject 6(b) will be unchanged by this Change Order ……....	$	0
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order ........	$	0
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be ....................	$	468,900,825
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) ……………..........................	$	2,480,739,471
15. The Contract Price will be decreased by this Change Order in the amount of (add lines 4, 5, and 11) .......................................................................................................................................................	$	740
16. The new Contract Price including this Change Order will be (add lines 14 and 15) …......................	$	2,480,738,731

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

The following dates are modified: N/A

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

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

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

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

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

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

__________________________________________________________________________________________________

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

The following dates are modified: N/A

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

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

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

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

________________________________________________________________________________

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SMS 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	Steve Smith
Owner	Contractor
David Craft	Steve Smith
Name	Name
SVP E&C	Senior Project Manager & Principal Vice President
Title	Title
August 3, 2023	July 31, 2023
Date of Signing	Date of Signing

CHANGE ORDER

BORROWED ITEMS

PROJECT NAME: Sabine Pass LNG Stage 4 Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. CHANGE ORDER NUMBER: CO-00080 DATE OF CHANGE ORDER: 06-Sep-2023 DATE OF AGREEMENT: 07-Nov-2018

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

1.Owner and Contractor agree that the Contract Price Applicable to Subproject 6(a) is reduced by Two Hundred Fifty-Five Thousand, Five Hundred and Sixty-Two U.S. Dollars (U.S. $255,562) as full and final settlement for Owner to purchase the items identified in Attachment 1 of this Change Order.

2.     For context the items in Attachment 1 of this Change Order were borrowed by Contractor from Owner but will not be returned. Therefore Parties agree that by this Change Order, Contractor shall have no responsibility to purchase such replacement items.

3.     The detailed cost summary and reconciliation for this Change Order is provided in Exhibit A of this Change Order. 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, 68, 75, 77-79).......................................................................................................................................	$	(5,054,667)
3. The Contract Price Applicable to Subproject 6(a) prior to this Change Order was ……....................	$	2,011,837,906
4. The Contract Price Applicable to Subproject 6(a) will be reduced by this Change Order in the amount of …………………………………………..……..................................................................	$	255,562
5. The Provisional Sum Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ............................................................................................................................................	$	0
6. The Contract Price Applicable to Subproject 6(a) will be unchanged by this Change Order in the amount of ………………………………………………………………………………………........	$	2,011,582,344
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, 62-67, 69-74, 76).......................................................................................................................................................	$	11,204,825
9. The Contract Price Applicable to Subproject 6(b) prior to this Change Order was ..…....................	$	468,900,825
10. The Contract Price Applicable to Subproject 6(b) will be reduced by this Change Order ...............	$	0
11. The Provisional Sum Applicable to Subproject 6(b) will be unchanged by this Change Order .......	$	0
12. The Contract Price Applicable to Subproject 6(b) including this Change Order will be ..................	$	468,900,825
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) …………….......................	$	2,480,738,731
15. The Contract Price will be reduced by this Change Order in the amount of (add lines 4, 5, 10 and 11) .......................................................................................................................................................	$	255,562
16. The new Contract Price including this Change Order will be (add lines 14 and 15) …....................	$	2,480,483,169

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

The following dates are modified: N/A

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

Adjustment to Payment Schedule for Subproject 6(a): Yes

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

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

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

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

__________________________________________________________________________________________________

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

The following dates are modified: N/A

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

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

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

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

__________________________________________________________________________________________________

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS 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/ Steve Smith
Owner	Contractor
David Craft	Steve Smith
Name	Name
SVP, Engineering and Construction	Senior Project Manager & Principal Vice President
Title	Title
September 27, 2023	September 15, 2023
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: November 1, 2023

/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: November 1, 2023

/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 September 30, 2023, 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: November 1, 2023

/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 September 30, 2023, 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: November 1, 2023

/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	9 Months Ended
	Sep. 30, 2023	Oct. 26, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2023
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		484,039,123
Entity Central Index Key	0001383650
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q3

XML

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Revenues
Revenues		$ 2,128	$ 4,976	$ 6,978	$ 12,485
Operating costs and expenses
Cost of sales		684	4,843	1,618	10,612
Operating and maintenance expense		263	246	844	713
General and administrative expense		22	26	74	73
Depreciation and amortization expense		166	160	500	469
Other		5	0	7	0
Total operating costs and expenses		1,140	5,275	3,043	11,867
Income (loss) from operations		988	(299)	3,935	618
Other income (expense)
Interest expense, net of capitalized interest		(205)	(222)	(620)	(641)
Loss on modification or extinguishment of debt		(4)	0	(6)	0
Interest and dividend income		12	7	39	10
Total other expense		(197)	(215)	(587)	(631)
Net income (loss)		$ 791	$ (514)	$ 3,348	$ (13)
Basic and diluted net income (loss) per common unit	[1]	$ 1.19	$ (1.49)	$ 5.53	$ (1.36)
Weighted average basic and diluted number of common units outstanding		484.0	484.0	484.0	484.0
Nonrelated Party [Member]
Operating costs and expenses
Cost of sales		$ 682	$ 4,739	$ 1,598	$ 10,445
Operating and maintenance expense		211	189	680	550
General and administrative expense		2	3	8	3
Other		4	0	6	0
Affiliate [Member]
Operating costs and expenses
Cost of sales		2	104	20	166
Operating and maintenance expense		38	39	120	118
General and administrative expense		20	23	66	70
Other		1	0	1	0
Related Party [Member]
Operating costs and expenses
Cost of sales		0	0	0	1
Operating and maintenance expense		14	18	44	45
LNG [Member]
Revenues
Revenues		2,079	4,506	6,830	11,849
LNG [Member] | Nonrelated Party [Member]
Revenues
Revenues		1,564	3,130	5,085	8,577
LNG [Member] | Affiliate [Member]
Revenues
Revenues		515	1,376	1,745	3,268
LNG [Member] | Related Party [Member]
Revenues
Revenues		0	0	0	4
Regasification [Member]
Revenues
Revenues		34	455	101	591
Other [Member]
Revenues
Revenues		$ 15	$ 15	$ 47	$ 45

[1] In computing basic and diluted net income (loss) per common unit, net income (loss) is reduced by the amount of undistributed net income (loss) allocated to participating securities other than common units, as required under the two-class method. See Note 12—Net Income (Loss) per Common Unit.

XML

Consolidated Balance Sheets - USD ($) $ in Millions		Sep. 30, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents		$ 499	$ 904
Restricted cash and cash equivalents		35	92
Trade and other receivables, net of current expected credit losses		287	627
Trade receivables—affiliate		167	551
Advances to affiliate		141	177
Inventory		131	160
Current derivative assets	[1]	34	24
Margin deposits		0	35
Other current assets, net		60	50
Total current assets		1,354	2,620
Property, plant and equipment, net of accumulated depreciation		16,341	16,725
Operating lease assets		83	89
Debt issuance costs, net of accumulated amortization		17	8
Derivative assets	[1]	111	28
Other non-current assets, net		$ 166	$ 163
Accounts Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration]		Affiliated Entity [Member]	Affiliated Entity [Member]
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration]		Affiliated Entity [Member]	Affiliated Entity [Member]
Total assets		$ 18,072	$ 19,633
Current liabilities
Accounts payable		50	32
Accrued liabilities		688	1,458
Current debt, net of discount and debt issuance costs		349	0
Deferred revenue		152	147
Current operating lease liabilities		11	10
Current derivative liabilities	[1]	294	769
Other current liabilities		5	5
Total current liabilities		1,549	2,421
Long-term debt, net of discount and debt issuance costs		15,600	16,198
Operating lease liabilities		74	80
Finance lease liabilities		15	18
Derivative liabilities	[1]	1,731	3,024
Other non-current liabilities		76	23
Partners’ deficit
Common unitholders’ interest (484.0 million units issued and outstanding at both September 30, 2023 and December 31, 2022)		647	(1,118)
General partner’s interest (2% interest with 9.9 million units issued and outstanding at both September 30, 2023 and December 31, 2022)		(1,620)	(1,013)
Total partners’ deficit		(973)	(2,131)
Total liabilities and partners’ deficit		18,072	19,633
Nonrelated Party [Member]
Current liabilities
Accrued liabilities		641	1,378
Deferred revenue		151	144
Other non-current liabilities		52	0
Affiliate [Member]
Current liabilities
Accrued liabilities		42	74
Deferred revenue		1	3
Other non-current liabilities		24	23
Related Party [Member]
Current liabilities
Accrued liabilities		$ 5	$ 6

[1] Does not include collateral posted by counterparties to us of $1 million as of September 30, 2023, which is included in other current liabilities on our Consolidated Balance Sheets, and collateral posted with counterparties by us of $35 million as of December 31, 2022, which is included in margin deposits on our Consolidated Balance Sheets.

XML

Consolidated Balance Sheets Parentheticals - shares shares in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021
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	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	9.9	9.9

XML

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, 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 (Loss)	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 (Loss)	(13)
Units, Outstanding, end of period at Sep. 30, 2022		484.0
Partners' equity, end of period at Sep. 30, 2022	(3,884)	$ (3,059)	$ (825)
General partner units, Outstanding, end of period at Sep. 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 (Loss)	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
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	(514)	(503)	$ (11)
Distributions		$ (513)	(232)
Units, Outstanding, end of period at Sep. 30, 2022		484.0
Partners' equity, end of period at Sep. 30, 2022	(3,884)	$ (3,059)	$ (825)
General partner units, Outstanding, end of period at Sep. 30, 2022			9.9
Units, Outstanding, beginning of period at Dec. 31, 2022		484.0
Partners' equity, beginning of period at Dec. 31, 2022	(2,131)	$ (1,118)	$ (1,013)
General partner units, Outstanding, beginning of period at Dec. 31, 2022			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	1,935	1,897	$ 38
Distributions		$ (518)	(236)
Units, Outstanding, end of period at Mar. 31, 2023		484.0
Partners' equity, end of period at Mar. 31, 2023	(950)	$ 261	$ (1,211)
General partner units, Outstanding, end of period at Mar. 31, 2023			9.9
Units, Outstanding, beginning of period at Dec. 31, 2022		484.0
Partners' equity, beginning of period at Dec. 31, 2022	(2,131)	$ (1,118)	$ (1,013)
General partner units, Outstanding, beginning of period at Dec. 31, 2022			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	3,348
Units, Outstanding, end of period at Sep. 30, 2023		484.0
Partners' equity, end of period at Sep. 30, 2023	(973)	$ 647	$ (1,620)
General partner units, Outstanding, end of period at Sep. 30, 2023			9.9
Units, Outstanding, beginning of period at Mar. 31, 2023		484.0
Partners' equity, beginning of period at Mar. 31, 2023	(950)	$ 261	$ (1,211)
General partner units, Outstanding, beginning of period at Mar. 31, 2023			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	622	610	$ 12
Distributions		$ (499)	(219)
Units, Outstanding, end of period at Jun. 30, 2023		484.0
Partners' equity, end of period at Jun. 30, 2023	(1,046)	$ 372	$ (1,418)
General partner units, Outstanding, end of period at Jun. 30, 2023			9.9
Increase (Decrease) in Partners' Capital [Roll Forward]
Net Income (Loss)	791	774	$ 17
Distributions		$ (499)	(219)
Units, Outstanding, end of period at Sep. 30, 2023		484.0
Partners' equity, end of period at Sep. 30, 2023	$ (973)	$ 647	$ (1,620)
General partner units, Outstanding, end of period at Sep. 30, 2023			9.9

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Consolidated Statements of Partners' Equity Parentheticals - $ / shares	3 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022
Common Units [Member]
Distributions Paid, Per Unit	$ 1.03	$ 1.03	$ 1.070	$ 1.06	$ 1.05	$ 0.700

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Cash flows from operating activities
Net income (loss)	$ 3,348	$ (13)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	500	469
Amortization of debt issuance costs, premium and discount	22	22
Loss on modification or extinguishment of debt	6	0
Total losses (gains) on derivative instruments, net	(1,867)	2,447
Net cash provided by (used for) settlement of derivative instruments	6	(54)
Other	16	28
Changes in operating assets and liabilities:
Trade and other receivables, net of current expected credit losses	340	(290)
Trade receivables—affiliate	384	(231)
Advances to affiliate	31	(10)
Inventory	30	(67)
Margin deposits	35	(52)
Contract assets	0	(387)
Accounts payable and accrued liabilities	(662)	592
Accrued liabilities—related party	(2)	5
Due to affiliates	(30)	2
Total deferred revenue	59	6
Other, net	(21)	(30)
Other, net—affiliate	(2)	5
Net cash provided by operating activities	2,193	2,442
Cash flows from investing activities
Property, plant and equipment, net	(170)	(356)
Other	(6)	0
Net cash used in investing activities	(176)	(356)
Cash flows from financing activities
Proceeds from issuances of debt	1,397	0
Redemptions and repayments of debt	(1,650)	0
Debt issuance and other financing costs	(32)	0
Debt extinguishment costs	(1)	0
Distributions	(2,190)	(1,877)
Other	(3)	0
Net cash used in financing activities	(2,479)	(1,877)
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	(462)	209
Cash, Cash Equivalents—beginning of period	996	974
Cash, Cash Equivalents—end of period	$ 534	$ 1,183

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Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022	Sep. 30, 2022	Dec. 31, 2021
Balances per Consolidated Balance Sheets:
Cash and cash equivalents	$ 499	$ 904
Restricted cash and cash equivalents	35	92
Total cash, cash equivalents and restricted cash and cash equivalents	$ 534	$ 996	$ 1,183	$ 974

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Nature of Operations and Basis of Presentation

9 Months Ended

Sep. 30, 2023

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, 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 three marine berths. Additionally, the Sabine Pass LNG Terminal includes a 94-mile pipeline owned by our subsidiary, CTPL, that interconnects the Sabine Pass LNG Terminal with a number of large interstate and intrastate 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. In May 2023, certain of our subsidiaries entered the pre-filing review process with the FERC under the National Environmental Policy Act for an expansion adjacent to the Liquefaction Project with a potential production capacity of up to 20 mtpa of LNG. 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.

We do not have employees and thus we and our subsidiaries have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. See Note 11—Related Party Transactions for additional details of the activity under these services agreements during the three and nine months ended September 30, 2023 and 2022.

As of September 30, 2023, 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 and reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of the financial results for the interim periods presented. 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, 2022.

Results of operations for the three and nine months ended September 30, 2023 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2023.

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 as a result of the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.

As further detailed in Note 9—Debt, all of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through replacements of previous credit facilities subsequent to the effective date of ASU 2020-04. We elected to apply the optional expedients as applicable to certain replaced facilities; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.

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Unitholders' Equity

9 Months Ended

Sep. 30, 2023

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 September 30, 2023, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.5% by CQP Target Holdco L.L.C. (“CQP Target Holdco”) and other affiliates of Blackstone Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) and 7.9% by the public. All of our 2% general partner interest was held by Cheniere. CQP Target Holdco’s equity interests are 50.0% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone, and 50.0% 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

9 Months Ended

Sep. 30, 2023

Restricted Cash and Cash Equivalents [Abstract]

Restricted Cash and Cash Equivalents

RESTRICTED CASH AND CASH EQUIVALENTS

As of September 30, 2023 and December 31, 2022, we had $35 million and $92 million of restricted cash and cash equivalents, respectively, for which the usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project as required under certain debt arrangements.

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Trade and Other Receivables, Net of Current Expected Credit Losses

9 Months Ended

Sep. 30, 2023

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):

	September 30,		December 31,
	2023		2022
Trade receivables	$	275	$	603
Other receivables	12		24
Total trade and other receivables, net of current expected credit losses	$	287	$	627

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Inventory

9 Months Ended

Sep. 30, 2023

Inventory Disclosure [Abstract]

Inventory

INVENTORY

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
Materials	$	104	$	103
LNG	8		27
Natural gas	16		28
Other	3		2
Total inventory	$	131	$	160

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Property, Plant and Equipment, Net of Accumulated Depreciation

9 Months Ended

Sep. 30, 2023

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):

	September 30,		December 31,
	2023		2022
LNG terminal
Terminal and interconnecting pipeline facilities	$	20,122	$	20,072
Construction-in-process	201		140
Accumulated depreciation	(4,004)		(3,512)
Total LNG terminal, net of accumulated depreciation	16,319		16,700
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(26)		(25)
Total fixed assets, net of accumulated depreciation	4		4
Assets under finance leases
Tug vessels	23		23
Accumulated depreciation	(5)		(2)
Total assets under finance leases, net of accumulated depreciation	18		21
Property, plant and equipment, net of accumulated depreciation	$	16,341	$	16,725

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Depreciation expense	$	166	$	158	$	497	$	465
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

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

SPL has commodity derivatives consisting of natural gas supply contracts, including those under the IPM agreement, for the operation of the Liquefaction Project and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).

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

The following table shows the fair value of the derivative instruments that are required to be measured at fair value on a recurring basis, by the fair value hierarchy levels prescribed by GAAP (in millions):

	Fair Value Measurements as of
	September 30, 2023								December 31, 2022
	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)	$	13	$	(1)	$	(1,892)	$	(1,880)	$	(12)	$	(10)	$	(3,719)	$	(3,741)

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

The fair value of the 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 significant portion of our 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 may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.

The Level 3 fair value measurements of the natural gas positions within the 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 the Level 3 Liquefaction Supply Derivatives as of September 30, 2023:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(1,892)	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.543) - $0.510 / $0.040
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	103% - 422% / 213%

(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 the Liquefaction Supply Derivatives.

The following table shows the changes in the fair value of the Level 3 Liquefaction Supply Derivatives (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Balance, beginning of period	$	(2,255)	$	(3,456)	$	(3,719)	$	38
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)	294		(1,545)		1,275		(155)
Included in cost of sales, new deals (3)	8		—		23		—
Purchases and settlements:
Purchases (4)	—		3		—		(4,896)
Settlements (5)	59		(24)		522		(11)
Transfers out of level 3 (6)	2		(2)		7		—
Balance, end of period	$	(1,892)	$	(5,024)	$	(1,892)	$	(5,024)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period	$	302	$	(1,545)	$	1,298	$	(155)

(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume.  See settlements line item in this table.

(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.

(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.

(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period.

(5)Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.

(6)Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from those derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes SPL to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when the derivative instruments are in an asset position. Additionally, counterparties are at risk that SPL will be unable to meet its commitments in instances where the derivative instruments are in a liability position. We incorporate both SPL’s 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 the 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 firm terms of the Liquefaction Supply Derivatives range up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs.

The forward notional amount for the Liquefaction Supply Derivatives was approximately 5,642 TBtu and 5,972 TBtu as of September 30, 2023 and December 31, 2022, respectively, excluding notional amounts associated with extension options that were uncertain to be taken as of September 30, 2023.

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

	Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues	$	—	$	(3)	$	—	$	1
Cost of sales	365		(1,625)		1,867		(2,448)

(1)Does not include the realized value associated with Liquefaction Supply Derivatives 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 the Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):

	Fair Value Measurements as of (1)
Consolidated Balance Sheets Location	September 30, 2023		December 31, 2022
Current derivative assets	$	34	$	24
Derivative assets	111		28
Total derivative assets	145		52
Current derivative liabilities	(294)		(769)
Derivative liabilities	(1,731)		(3,024)
Total derivative liabilities	(2,025)		(3,793)
Derivative liability, net	$	(1,880)	$	(3,741)

(1)Does not include collateral posted by counterparties to us of $1 million as of September 30, 2023, which is included in other current liabilities on our Consolidated Balance Sheets, and collateral posted with counterparties by us of $35 million as of December 31, 2022, which is included in margin deposits on our Consolidated Balance Sheets.

Consolidated Balance Sheets Presentation

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

	Liquefaction Supply Derivatives
	September 30, 2023		December 31, 2022
Gross assets	$	172	$	57
Offsetting amounts	(27)		(5)
Net assets	$	145	$	52
Gross liabilities	$	(2,029)	$	(3,814)
Offsetting amounts	4		21
Net liabilities	$	(2,025)	$	(3,793)

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Accrued Liabilities

9 Months Ended

Sep. 30, 2023

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
Natural gas purchases	$	372	$	1,017
Interest costs and related debt fees	151		218
LNG terminal and related pipeline costs	86		137
Other accrued liabilities	32		6
Total accrued liabilities	$	641	$	1,378

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Debt

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

Debt

DEBT

Debt consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
SPL:
Senior Secured Notes:
5.75% due 2024 (the “2024 SPL Senior Notes”)	$	350	$	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
4.746% weighted average rate due 2037	1,782		1,782
Total SPL Senior Secured Notes	10,482		12,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	10,482		12,132
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
5.95% due 2033 (the “2033 CQP Senior Notes”)	1,400		—
Total CQP Senior Notes	5,600		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	5,600		4,200
Total debt	16,082		16,332
Current debt, net of discount and debt issuance costs	(349)		—
Long-term portion of unamortized discount and debt issuance costs, net	(133)		(134)
Total long-term debt, net of discount and debt issuance costs	$	15,600	$	16,198

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2023 (in millions):

	SPL Revolving Credit Facility (1)		CQP Revolving Credit Facility (1)
Total facility size	$	1,000	$	1,000
Less:
Outstanding balance	—		—
Letters of credit issued	284		—
Available commitment	$	716	$	1,000
Priority ranking	Senior secured		Senior unsecured
Interest rate on available balance (2)	SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.125% - 2.0% or base rate plus 0.125% - 1.0%
Commitment fees on undrawn balance (2)	0.075% - 0.30%		0.10% - 0.30%
Maturity date	June 23, 2028		June 23, 2028

(1)In June 2023, we and SPL refinanced and replaced the CQP Credit Facilities and the SPL Working Capital Facility with the CQP Revolving Credit Facility and the SPL Revolving Credit Facility, respectively, resulting in extended maturity dates, revised borrowing capacities, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

(2)The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.

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. SPL is restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.

As of September 30, 2023, 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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Total interest cost	$	207	$	231	$	626	$	678
Capitalized interest	(2)		(9)		(6)		(37)
Total interest expense, net of capitalized interest	$	205	$	222	$	620	$	641

Fair Value Disclosures

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

	September 30, 2023				December 31, 2022
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	16,082	$	14,943	$	16,332	$	15,386

(1)As of both September 30, 2023 and December 31, 2022, $1.2 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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

9 Months Ended

Sep. 30, 2023

Revenue from Contract with Customer [Abstract]

Revenues

REVENUES

The following table represents a disaggregation of revenue earned (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues from contracts with customers
LNG revenues	$	1,564	$	3,133	$	5,085	$	8,576
LNG revenues—affiliate	515		1,376		1,745		3,268
LNG revenues—related party	—		—		—		4
Regasification revenues	34		455		101		591
Other revenues	15		15		47		45
Total revenues from contracts with customers	2,128		4,979		6,978		12,484
Net derivative gain (loss) (1)	—		(3)		—		1
Total revenues	$	2,128	$	4,976	$	6,978	$	12,485

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

Termination Agreement with Chevron

In June 2022, Chevron U.S.A. (“Chevron”) entered into an agreement with SPLNG providing for the early termination of the TUA and an associated terminal marine services agreement between the parties and their affiliates (the “Termination Agreement”), effective July 2022, for a lump sum fee of $765 million (the “Termination Fee”). Obligations pursuant to the TUA and associated agreement, including Chevron’s obligation to pay SPLNG capacity payments totaling $125 million annually (adjusted for inflation) from 2023 through 2029, terminated on December 31, 2022, upon SPLNG’s receipt of the Termination Fee in December 2022. We allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which was recognized ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations.

Contract Assets and Liabilities

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

	September 30,		December 31,
	2023		2022
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 and other non-current liabilities on our Consolidated Balance Sheets (in millions):

	Nine Months Ended September 30, 2023
Deferred revenue, beginning of period	$	144
Cash received but not yet recognized in revenue	203
Revenue recognized from prior period deferral	(144)
Deferred revenue, end of period	$	203

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):

	Nine Months Ended September 30, 2023
Deferred revenue—affiliate, beginning of period	$	8
Cash received but not yet recognized in revenue	6
Revenue recognized from prior period deferral	(8)
Deferred revenue—affiliate, end of period	$	6

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:

	September 30, 2023			December 31, 2022
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	48.4	8	$	50.8	8
LNG revenues—affiliate	1.5		2	2.0		2
Regasification revenues	0.7		3	0.8		4
Total revenues	$	50.6		$	53.6

(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. Additionally, we have excluded variable consideration related to volumes that contractually are subject to additional liquefaction capacity beyond what is currently in construction or operation. The following table summarizes the amount of variable consideration earned under contracts with customers included in the table above:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues	53	%	78	%	55	%	74	%
LNG revenues—affiliate	64	%	77	%	68	%	76	%
Regasification revenues	7	%	1	%	7	%	2	%

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Related Party Transactions

9 Months Ended

Sep. 30, 2023

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Below is a summary of our transactions with our affiliates and other related parties, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues—affiliate
SPAs and Letter Agreements with Cheniere Marketing	$	513	$	1,328	$	1,742	$	3,173
Contracts for Sale and Purchase of Natural Gas and LNG with other affiliates	2		48		3		95
Total LNG revenues—affiliate	515		1,376		1,745		3,268
LNG revenues—related party
Natural Gas Transportation and Storage Agreements (1)	—		—		—		4
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	2		104		20		166
Cost of sales—related party
Natural Gas Transportation and Storage Agreements (1)	—		—		—		1
Operating and maintenance expense—affiliate
Services Agreements (see Note 1)	38		39		120		118
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements (1)	14		18		44		45
General and administrative expense—affiliate
Services Agreements (see Note 1)	20		23		66		70
Other—affiliate
Services Agreements (see Note 1)	1		—		1		—

(1)This related party is partially owned by Brookfield, who indirectly owns a portion of our limited partner interests.

Other Agreements

Terminal Marine Services Agreement

In connection with its tug boat leases, 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. Under this agreement, Tug Services distributed $4 million and $2 million during the three months ended September 30, 2023 and 2022, respectively, and $8 million and $7 million during the nine months ended September 30, 2023 and 2022, 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).

Cooperative Endeavor Agreements (“CEAs”)

SPLNG has executed 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. In 2018, SPLNG entered into a Memorandum of Understanding, which forgave $7 million of the dollar-for-dollar credits, and in 2022, an

agreement was reached to defer the commencement of the dollar-for-dollar credits until 2027. As of both September 30, 2023 and December 31, 2022, we had $17 million of amounts associated with dollar-for-dollar credits due on advance tax payments to the taxing authorities recorded to other non-current assets on our Consolidated Balance Sheets. 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. We had $17 million of other non-current liabilities—affiliate as of both September 30, 2023 and December 31, 2022 from these payments received from Cheniere Marketing.

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Net Income (Loss) per Common Unit

9 Months Ended

Sep. 30, 2023

Earnings Per Share [Abstract]

Net Income per Common Unit

NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit for a given period is based on the distributions to the common unitholders with respect to earnings or losses of the reporting 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 declared by us during the period are presented on the Consolidated Statements of Partners’ Equity (Deficit). On October 27, 2023, we declared a cash distribution of $1.03 per common unit to unitholders of record as of November 6, 2023 and the related general partner distribution to be paid on November 14, 2023 with respect to the three months ended September 30, 2023. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.255 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 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 (loss) and the allocation of net income (loss) to the common units, the subordinated units, the general partner units and IDRs for purposes of computing basic and diluted net income (loss) per unit (in millions, except per unit data).

	Total		Limited Partner Common Units		General Partner Units		IDR
Three Months Ended September 30, 2023
Net income	$	791
Declared distributions	714		499		14		201
Assumed allocation of undistributed net income (1)	$	77	75		1		—
Assumed allocation of net income			$	574	$	15	$	201
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	1.19
Three Months Ended September 30, 2022
Net loss	$	(514)
Declared distributions	753		518		15		220
Assumed allocation of undistributed net loss (1)	$	(1,267)	(1,242)		(25)		—
Assumed allocation of net loss			$	(724)	$	(10)	$	220
Weighted average units outstanding			484.0
Basic and diluted net loss per unit (2)			$	(1.49)
Nine Months Ended September 30, 2023
Net income	$	3,348
Declared distributions	2,142		1,496		43		603
Assumed allocation of undistributed net income (1)	$	1,206	1,181		24		—
Assumed allocation of net income			$	2,677	$	67	$	603
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	5.53
Nine Months Ended September 30, 2022
Net loss	$	(13)
Declared distributions	2,229		1,539		45		645
Assumed allocation of undistributed net loss (1)	$	(2,242)	(2,197)		(45)		—
Assumed allocation of net loss (1)			$	(658)	$	—	$	645
Weighted average units outstanding			484.0
Basic and diluted net loss per unit			$	(1.36)

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

(2)Basic and diluted net income (loss) per unit in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

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Customer Concentration

9 Months Ended

Sep. 30, 2023

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2023	2022	2023	2022	2023	2022
Customer A	17%	18%	23%	23%	19%	27%
Customer B	18%	16%	16%	16%	14%	18%
Customer C	17%	14%	16%	16%	22%	*
Customer D	15%	16%	15%	16%	11%	18%
Customer E	*	10%	*	*	*	13%
Customer F	—%	12%	—%	*	*	*
Customer G	10%	*	11%	*	15%	*

* Less than 10%

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2023

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):

	Nine Months Ended September 30,
	2023		2022
Cash paid during the period for interest on debt, net of amounts capitalized	$	658	$	585
Non-cash investing activity:
Unpaid purchases of property, plant and equipment, net	31		147

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 CCL, 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 was 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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Pay vs Performance Disclosure - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2023	Sep. 30, 2022
Pay vs Performance Disclosure
Net income (loss)	$ 791	$ 622	$ 1,935	$ (514)	$ 342	$ 159	$ 3,348	$ (13)

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Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

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Nature of Operations and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2023

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 and reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of the financial results for the interim periods presented. 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, 2022.

Results of operations for the three and nine months ended September 30, 2023 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2023.

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 as a result of the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.

As further detailed in Note 9—Debt, all of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through replacements of previous credit facilities subsequent to the effective date of ASU 2020-04. We elected to apply the optional expedients as applicable to certain replaced facilities; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.

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Trade and Other Receivables, Net of Current Expected Credit Losses (Tables)

9 Months Ended

Sep. 30, 2023

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):

	September 30,		December 31,
	2023		2022
Trade receivables	$	275	$	603
Other receivables	12		24
Total trade and other receivables, net of current expected credit losses	$	287	$	627

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Inventory (Tables)

9 Months Ended

Sep. 30, 2023

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
Materials	$	104	$	103
LNG	8		27
Natural gas	16		28
Other	3		2
Total inventory	$	131	$	160

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

9 Months Ended

Sep. 30, 2023

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):

	September 30,		December 31,
	2023		2022
LNG terminal
Terminal and interconnecting pipeline facilities	$	20,122	$	20,072
Construction-in-process	201		140
Accumulated depreciation	(4,004)		(3,512)
Total LNG terminal, net of accumulated depreciation	16,319		16,700
Fixed assets
Fixed assets	30		29
Accumulated depreciation	(26)		(25)
Total fixed assets, net of accumulated depreciation	4		4
Assets under finance leases
Tug vessels	23		23
Accumulated depreciation	(5)		(2)
Total assets under finance leases, net of accumulated depreciation	18		21
Property, plant and equipment, net of accumulated depreciation	$	16,341	$	16,725

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 September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Depreciation expense	$	166	$	158	$	497	$	465
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)

9 Months Ended

Sep. 30, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value of Derivative Assets and Liabilities

The following table shows the fair value of the derivative instruments that are required to be measured at fair value on a recurring basis, by the fair value hierarchy levels prescribed by GAAP (in millions):

	Fair Value Measurements as of
	September 30, 2023								December 31, 2022
	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)	$	13	$	(1)	$	(1,892)	$	(1,880)	$	(12)	$	(10)	$	(3,719)	$	(3,741)

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of September 30, 2023:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(1,892)	Market approach incorporating present value techniques	Henry Hub basis spread	$(0.543) - $0.510 / $0.040
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	103% - 422% / 213%

(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 the Level 3 Liquefaction Supply Derivatives (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Balance, beginning of period	$	(2,255)	$	(3,456)	$	(3,719)	$	38
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)	294		(1,545)		1,275		(155)
Included in cost of sales, new deals (3)	8		—		23		—
Purchases and settlements:
Purchases (4)	—		3		—		(4,896)
Settlements (5)	59		(24)		522		(11)
Transfers out of level 3 (6)	2		(2)		7		—
Balance, end of period	$	(1,892)	$	(5,024)	$	(1,892)	$	(5,024)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period	$	302	$	(1,545)	$	1,298	$	(155)

(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume.  See settlements line item in this table.

(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.

(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.

(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period.

(5)Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.

(6)Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

Derivative Instruments, Gain (Loss)

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

	Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues	$	—	$	(3)	$	—	$	1
Cost of sales	365		(1,625)		1,867		(2,448)

(1)Does not include the realized value associated with Liquefaction Supply Derivatives 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 the Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):

	Fair Value Measurements as of (1)
Consolidated Balance Sheets Location	September 30, 2023		December 31, 2022
Current derivative assets	$	34	$	24
Derivative assets	111		28
Total derivative assets	145		52
Current derivative liabilities	(294)		(769)
Derivative liabilities	(1,731)		(3,024)
Total derivative liabilities	(2,025)		(3,793)
Derivative liability, net	$	(1,880)	$	(3,741)

(1)Does not include collateral posted by counterparties to us of $1 million as of September 30, 2023, which is included in other current liabilities on our Consolidated Balance Sheets, and collateral posted with counterparties by us of $35 million as of December 31, 2022, which is included in margin deposits on our Consolidated Balance Sheets.

Derivative Net Presentation on Consolidated Balance Sheets

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

	Liquefaction Supply Derivatives
	September 30, 2023		December 31, 2022
Gross assets	$	172	$	57
Offsetting amounts	(27)		(5)
Net assets	$	145	$	52
Gross liabilities	$	(2,029)	$	(3,814)
Offsetting amounts	4		21
Net liabilities	$	(2,025)	$	(3,793)

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Accrued Liabilities (Tables)

9 Months Ended

Sep. 30, 2023

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

Accrued liabilities consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
Natural gas purchases	$	372	$	1,017
Interest costs and related debt fees	151		218
LNG terminal and related pipeline costs	86		137
Other accrued liabilities	32		6
Total accrued liabilities	$	641	$	1,378

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Debt (Tables)

9 Months Ended

Sep. 30, 2023

Debt Disclosure [Abstract]

Schedule of Debt Instruments

Debt consisted of the following (in millions):

	September 30,		December 31,
	2023		2022
SPL:
Senior Secured Notes:
5.75% due 2024 (the “2024 SPL Senior Notes”)	$	350	$	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
4.746% weighted average rate due 2037	1,782		1,782
Total SPL Senior Secured Notes	10,482		12,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	10,482		12,132
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
5.95% due 2033 (the “2033 CQP Senior Notes”)	1,400		—
Total CQP Senior Notes	5,600		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	5,600		4,200
Total debt	16,082		16,332
Current debt, net of discount and debt issuance costs	(349)		—
Long-term portion of unamortized discount and debt issuance costs, net	(133)		(134)
Total long-term debt, net of discount and debt issuance costs	$	15,600	$	16,198

Schedule of Line of Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, 2023 (in millions):

	SPL Revolving Credit Facility (1)		CQP Revolving Credit Facility (1)
Total facility size	$	1,000	$	1,000
Less:
Outstanding balance	—		—
Letters of credit issued	284		—
Available commitment	$	716	$	1,000
Priority ranking	Senior secured		Senior unsecured
Interest rate on available balance (2)	SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.125% - 2.0% or base rate plus 0.125% - 1.0%
Commitment fees on undrawn balance (2)	0.075% - 0.30%		0.10% - 0.30%
Maturity date	June 23, 2028		June 23, 2028

(1)In June 2023, we and SPL refinanced and replaced the CQP Credit Facilities and the SPL Working Capital Facility with the CQP Revolving Credit Facility and the SPL Revolving Credit Facility, respectively, resulting in extended maturity dates, revised borrowing capacities, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

(2)The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.

Schedule of Interest Expense

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Total interest cost	$	207	$	231	$	626	$	678
Capitalized interest	(2)		(9)		(6)		(37)
Total interest expense, net of capitalized interest	$	205	$	222	$	620	$	641

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	September 30, 2023				December 31, 2022
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	16,082	$	14,943	$	16,332	$	15,386

(1)As of both September 30, 2023 and December 31, 2022, $1.2 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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Revenues (Tables)

9 Months Ended

Sep. 30, 2023

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table represents a disaggregation of revenue earned (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Revenues from contracts with customers
LNG revenues	$	1,564	$	3,133	$	5,085	$	8,576
LNG revenues—affiliate	515		1,376		1,745		3,268
LNG revenues—related party	—		—		—		4
Regasification revenues	34		455		101		591
Other revenues	15		15		47		45
Total revenues from contracts with customers	2,128		4,979		6,978		12,484
Net derivative gain (loss) (1)	—		(3)		—		1
Total revenues	$	2,128	$	4,976	$	6,978	$	12,485

(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, net and other non-current assets, net on our Consolidated Balance Sheets (in millions):

	September 30,		December 31,
	2023		2022
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 and other non-current liabilities on our Consolidated Balance Sheets (in millions):

	Nine Months Ended September 30, 2023
Deferred revenue, beginning of period	$	144
Cash received but not yet recognized in revenue	203
Revenue recognized from prior period deferral	(144)
Deferred revenue, end of period	$	203

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):

	Nine Months Ended September 30, 2023
Deferred revenue—affiliate, beginning of period	$	8
Cash received but not yet recognized in revenue	6
Revenue recognized from prior period deferral	(8)
Deferred revenue—affiliate, end of period	$	6

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:

	September 30, 2023			December 31, 2022
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	$	48.4	8	$	50.8	8
LNG revenues—affiliate	1.5		2	2.0		2
Regasification revenues	0.7		3	0.8		4
Total revenues	$	50.6		$	53.6

(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.

Revenue, Remaining Performance Obligation, Variable Consideration

The following table summarizes the amount of variable consideration earned under contracts with customers included in the table above:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues	53	%	78	%	55	%	74	%
LNG revenues—affiliate	64	%	77	%	68	%	76	%
Regasification revenues	7	%	1	%	7	%	2	%

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2023

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Below is a summary of our transactions with our affiliates and other related parties, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
LNG revenues—affiliate
SPAs and Letter Agreements with Cheniere Marketing	$	513	$	1,328	$	1,742	$	3,173
Contracts for Sale and Purchase of Natural Gas and LNG with other affiliates	2		48		3		95
Total LNG revenues—affiliate	515		1,376		1,745		3,268
LNG revenues—related party
Natural Gas Transportation and Storage Agreements (1)	—		—		—		4
Cost of sales—affiliate
Contracts for Sale and Purchase of Natural Gas and LNG	2		104		20		166
Cost of sales—related party
Natural Gas Transportation and Storage Agreements (1)	—		—		—		1
Operating and maintenance expense—affiliate
Services Agreements (see Note 1)	38		39		120		118
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements (1)	14		18		44		45
General and administrative expense—affiliate
Services Agreements (see Note 1)	20		23		66		70
Other—affiliate
Services Agreements (see Note 1)	1		—		1		—

(1)This related party is partially owned by Brookfield, who indirectly owns a portion of our limited partner interests.

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Net Income (Loss) per Common Unit (Tables)

9 Months Ended

Sep. 30, 2023

Earnings Per Share [Abstract]

Schedule of Net Income per Common Unit

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

	Total		Limited Partner Common Units		General Partner Units		IDR
Three Months Ended September 30, 2023
Net income	$	791
Declared distributions	714		499		14		201
Assumed allocation of undistributed net income (1)	$	77	75		1		—
Assumed allocation of net income			$	574	$	15	$	201
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	1.19
Three Months Ended September 30, 2022
Net loss	$	(514)
Declared distributions	753		518		15		220
Assumed allocation of undistributed net loss (1)	$	(1,267)	(1,242)		(25)		—
Assumed allocation of net loss			$	(724)	$	(10)	$	220
Weighted average units outstanding			484.0
Basic and diluted net loss per unit (2)			$	(1.49)
Nine Months Ended September 30, 2023
Net income	$	3,348
Declared distributions	2,142		1,496		43		603
Assumed allocation of undistributed net income (1)	$	1,206	1,181		24		—
Assumed allocation of net income			$	2,677	$	67	$	603
Weighted average units outstanding			484.0
Basic and diluted net income per unit			$	5.53
Nine Months Ended September 30, 2022
Net loss	$	(13)
Declared distributions	2,229		1,539		45		645
Assumed allocation of undistributed net loss (1)	$	(2,242)	(2,197)		(45)		—
Assumed allocation of net loss (1)			$	(658)	$	—	$	645
Weighted average units outstanding			484.0
Basic and diluted net loss per unit			$	(1.36)

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

(2)Basic and diluted net income (loss) per unit in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

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Customer Concentration (Tables)

9 Months Ended

Sep. 30, 2023

Risks and Uncertainties [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:

	Percentage of Total Revenues from External Customers				Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Three Months Ended September 30,		Nine Months Ended September 30,		September 30,	December 31,
	2023	2022	2023	2022	2023	2022
Customer A	17%	18%	23%	23%	19%	27%
Customer B	18%	16%	16%	16%	14%	18%
Customer C	17%	14%	16%	16%	22%	*
Customer D	15%	16%	15%	16%	11%	18%
Customer E	*	10%	*	*	*	13%
Customer F	—%	12%	—%	*	*	*
Customer G	10%	*	11%	*	15%	*

* Less than 10%

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2023

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Nine Months Ended September 30,
	2023		2022
Cash paid during the period for interest on debt, net of amounts capitalized	$	658	$	585
Non-cash investing activity:
Unpaid purchases of property, plant and equipment, net	31		147

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Nature of Operations and Basis of Presentation (Details) shares in Millions	9 Months Ended
	Sep. 30, 2023 milliontonnes / yr mi unit item trains shares	Sep. 30, 2022
Sabine Pass LNG Terminal [Member]
Organization and Nature of Operations [Line Items]
Number of Liquefaction LNG Trains Operating | trains	6
Total Production Capability	30
Number Of LNG Storage Tanks | unit	5
Number of Marine Berths Operating | item	3
Creole Trail Pipeline [Member]
Organization and Nature of Operations [Line Items]
Length of Natural Gas Pipeline | mi	94
Sabine Pass LNG Terminal Expansion | Maximum [Member]
Organization and Nature of Operations [Line Items]
Total Production Capability	20
Cheniere Partners [Member]
Organization and Nature of Operations [Line Items]
General Partner Ownership Interest Percentage	2.00%	2.00%
Cheniere [Member] | Cheniere Partners [Member]
Organization and Nature of Operations [Line Items]
Limited Partner Ownership Percentage	48.60%
General Partner Ownership Interest Percentage	100.00%
Cheniere [Member] | Cheniere Partners [Member] | Common Units [Member]
Organization and Nature of Operations [Line Items]
Partners' Capital Account, Units, Units Held | shares	239.9

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Unitholders' Equity (Details)	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
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	41.50%
Public [Member] | Cheniere Partners [Member]
Other Ownership Interests [Line Items]
Limited Partner Ownership Percentage	7.90%
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%

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Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 35	$ 92
SPL Project [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 35	$ 92

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Trade and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable [Line Items]
Trade and other receivables, net of current expected credit losses	$ 287	$ 627
Trade Accounts Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Trade and other receivables, net of current expected credit losses	275	603
Other Receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Trade and other receivables, net of current expected credit losses	$ 12	$ 24

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Inventory (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Inventory [Line Items]
Inventory	$ 131	$ 160
Materials [Member]
Inventory [Line Items]
Inventory	104	103
LNG [Member]
Inventory [Line Items]
Inventory	8	27
Natural gas [Member]
Inventory [Line Items]
Inventory	16	28
Other [Member]
Inventory [Line Items]
Inventory	$ 3	$ 2

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment, Net of Accumulated Depreciation (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation	$ 16,341	$ 16,725
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation	(4,004)	(3,512)
Property, plant and equipment, net of accumulated depreciation	16,319	16,700
Terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	20,122	20,072
Construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	201	140
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
Assets under finance leases
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	23	23
Accumulated depreciation	(5)	(2)
Property, plant and equipment, net of accumulated depreciation	$ 18	$ 21

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Depreciation and Offsets to LNG Terminal Costs (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Property, Plant and Equipment [Abstract]
Depreciation expense		$ 166	$ 158	$ 497	$ 465
Offsets to LNG terminal costs	[1]	$ 0	$ 0	$ 0	$ 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 - Narrative (Details) - SPL [Member] - tbtu	9 Months Ended
	Sep. 30, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Nonmonetary Notional Amount	5,642	5,972
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	15 years

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (1,880)	$ (3,741)
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	13	(12)
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	(1)	(10)
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	$ (1,892)	$ (3,719)

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Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - USD ($)		9 Months Ended
		Sep. 30, 2023	Dec. 31, 2022
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability		$ (1,880,000,000)	$ (3,741,000,000)
Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability		(1,892,000,000)	$ (3,719,000,000)
Physical Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Net Fair Value Liability		(1,892,000,000)
Physical Liquefaction Supply Derivatives [Member] | Valuation, Market Approach | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	(0.543)
Physical Liquefaction Supply Derivatives [Member] | Valuation, Market Approach | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	0.510
Physical Liquefaction Supply Derivatives [Member] | Valuation, Market Approach | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Significant Unobservable Input Range	[1]	$ 0.040
Physical Liquefaction Supply Derivatives [Member] | Valuation Technique, Option Pricing Model | Minimum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	103.00%
Physical Liquefaction Supply Derivatives [Member] | Valuation Technique, Option Pricing Model | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	422.00%
Physical Liquefaction Supply Derivatives [Member] | Valuation Technique, Option Pricing Model | Weighted Average [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair Value Inputs Basis Spread Percentage	[1],[2]	213.00%

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

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

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Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (2,255)	$ (3,456)	$ (3,719)	$ 38
Realized and change in fair value gains (losses) included in net income:
Included in cost of sales, existing deals	[1],[2]	294	(1,545)	1,275	(155)
Included in cost of sales, new deals	[1],[3]	8	0	23	0
Purchases and settlements:
Purchases	[4]	0	3	0	(4,896)
Settlements	[5]	59	(24)	522	(11)
Transfers out of Level 3, net	[6]	2	(2)	7	0
Balance, end of period		(1,892)	(5,024)	(1,892)	(5,024)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period		$ 302	$ (1,545)	$ 1,298	$ (155)

[1] Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume.  See settlements line item in this table.

[2] Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.

[3] Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.

[4] Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period.

[5] Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.

[6] Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

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Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
LNG revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ 0	$ (3)	$ 0	$ 1
Cost of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ 365	$ (1,625)	$ 1,867	$ (2,448)

[1] Does not include the realized value associated with Liquefaction Supply Derivatives that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Sep. 30, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current derivative assets	[1]	$ 34	$ 24
Derivative assets	[1]	111	28
Total derivative assets	[1]	145	52
Current derivative liabilities	[1]	(294)	(769)
Derivative liabilities	[1]	(1,731)	(3,024)
Total derivative liabilities	[1]	(2,025)	(3,793)
Derivative asset (liability), net	[1]	(1,880)	(3,741)
Derivative, collateral posted by counterparties		$ 1
Derivative, collateral posted by us			$ 35
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration]		Current derivative assets	Current derivative assets
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Derivative assets	Derivative assets
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration]		Current derivative liabilities	Current derivative liabilities
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Derivative liabilities	Derivative liabilities

[1] Does not include collateral posted by counterparties to us of $1 million as of September 30, 2023, which is included in other current liabilities on our Consolidated Balance Sheets, and collateral posted with counterparties by us of $35 million as of December 31, 2022, which is included in margin deposits on our Consolidated Balance Sheets.

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Derivative Instruments - Balance Sheet Presentation Table (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (1,880)	$ (3,741)
Liquefaction Supply Derivative Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized	172	57
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheet	(27)	(5)
Derivative Assets (Liabilities), at Fair Value, Net	145	52
Liquefaction Supply Derivative Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized	(2,029)	(3,814)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheet	4	21
Derivative Assets (Liabilities), at Fair Value, Net	$ (2,025)	$ (3,793)

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Accrued Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Accrued Liabilities [Line Items]
Natural gas purchases	$ 372	$ 1,017
Interest costs and related debt fees	151	218
LNG terminal and related pipeline costs	86	137
Other accrued liabilities	32	6
Accrued liabilities	688	1,458
Nonrelated Party [Member]
Accrued Liabilities [Line Items]
Accrued liabilities	$ 641	$ 1,378

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Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2023		Dec. 31, 2022
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 16,082		$ 16,332
Long-Term Debt, Current Maturities	(349)		0
Long-term portion of unamortized discount and debt issuance costs, net	(133)		(134)
Long-term Debt, Net of Premium, Discount and Debt Issuance Costs	15,600		16,198
SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	10,482		12,132
2024 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 350		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	$ 1,782		1,782
2037 SPL Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.746%
SPL Working Capital Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0		0
SPL Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Debt, Gross	0	[1]	0
CQP Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	5,600		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%
2033 Cheniere Energy Partners Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,400		0
Debt Instrument, Interest Rate, Stated Percentage	5.95%
CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0		0
CQP Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Debt, Gross	0	[1]	0
SPL [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	10,482		12,132
Cheniere Partners [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 5,600		$ 4,200

[1] In June 2023, we and SPL refinanced and replaced the CQP Credit Facilities and the SPL Working Capital Facility with the CQP Revolving Credit Facility and the SPL Revolving Credit Facility, respectively, resulting in extended maturity dates, revised borrowing capacities, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

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Debt - Credit Facilities Table (Details) $ in Millions		9 Months Ended
		Sep. 30, 2023 USD ($) unit Rate		Dec. 31, 2022 USD ($)
Line of Credit Facility [Line Items]
Outstanding balance | $		$ 16,082		$ 16,332
Debt, Minimum Historical Debt Service Coverage Ratio And Projected Debt Service Coverage Ratio | unit		1.25
SPL Revolving Credit Facility
Line of Credit Facility [Line Items]
Total facility size | $	[1]	$ 1,000
Outstanding balance | $		0	[1]	0
Letters of credit issued | $	[1]	284
Available commitment | $	[1]	$ 716
Debt Instrument, Description of Variable Rate Basis		SOFR or base rate
Debt Instrument, Maturity Date	[1]	Jun. 23, 2028
SPL Revolving Credit Facility | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	[1],[2]	0.075%
SPL Revolving Credit Facility | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	[1],[2]	0.30%
SPL Revolving Credit Facility | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	[1],[2]	0.10%
SPL Revolving Credit Facility | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1],[2]	1.00%
SPL Revolving Credit Facility | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1],[2]	1.75%
SPL Revolving Credit Facility | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1],[2]	0.00%
SPL Revolving Credit Facility | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1],[2]	0.75%
CQP Revolving Credit Facility
Line of Credit Facility [Line Items]
Total facility size | $	[1]	$ 1,000
Outstanding balance | $		0	[1]	$ 0
Letters of credit issued | $	[1]	0
Available commitment | $	[1]	$ 1,000
Debt Instrument, Description of Variable Rate Basis		SOFR or base rate
Debt Instrument, Maturity Date	[1]	Jun. 23, 2028
CQP Revolving Credit Facility | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	[1],[2]	0.10%
CQP Revolving Credit Facility | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	[1],[2]	0.30%
CQP Revolving Credit Facility | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	[1],[2]	0.10%
CQP Revolving Credit Facility | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1],[2]	1.125%
CQP Revolving Credit Facility | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1],[2]	2.00%
CQP Revolving Credit Facility | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1],[2]	0.125%
CQP Revolving Credit Facility | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	[1],[2]	1.00%

[1] In June 2023, we and SPL refinanced and replaced the CQP Credit Facilities and the SPL Working Capital Facility with the CQP Revolving Credit Facility and the SPL Revolving Credit Facility, respectively, resulting in extended maturity dates, revised borrowing capacities, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

[2] The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.

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Debt - Interest Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Debt Disclosure [Abstract]
Total interest cost	$ 207	$ 231	$ 626	$ 678
Capitalized interest	(2)	(9)	(6)	(37)
Total interest expense, net of capitalized interest	$ 205	$ 222	$ 620	$ 641

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - Senior Notes [Member] - USD ($) $ in Millions		Sep. 30, 2023	Dec. 31, 2022
Carrying Amount [Member] | Fair Value, Inputs, Level 2 and Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt	[1]	$ 16,082	$ 16,332
Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 and Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	14,943	15,386
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		$ 1,200	$ 1,200

[1] As of both September 30, 2023 and December 31, 2022, $1.2 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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Revenues - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 2,128	$ 4,979	$ 6,978	$ 12,484
Net derivative loss	[1]	0	(3)	0	1
Total revenues		2,128	4,976	6,978	12,485
LNG [Member]
Disaggregation of Revenue [Line Items]
Total revenues		2,079	4,506	6,830	11,849
LNG [Member] | Nonrelated Party [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		1,564	3,133	5,085	8,576
Total revenues		1,564	3,130	5,085	8,577
LNG [Member] | Affiliate [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		515	1,376	1,745	3,268
Total revenues		515	1,376	1,745	3,268
LNG [Member] | Related Party [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		0	0	0	4
Total revenues		0	0	0	4
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		34	455	101	591
Total revenues		34	455	101	591
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		15	15	47	45
Total revenues		$ 15	$ 15	$ 47	$ 45

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

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Revenues - Termination Agreement with Chevron (Details) - Chevron U.S.A. Inc. $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Revenue from External Customer [Line Items]
Contract Termination Fee	$ 765
Terminated commitments [Member]
Revenue from External Customer [Line Items]
Contract Termination Fee	796
Regasification [Member]
Revenue from External Customer [Line Items]
Revenue, Performance Obligation, Fixed Consideration	$ 125

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Revenues - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Dec. 31, 2022
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract assets, net of current expected credit losses	$ 1	$ 1
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	144
Cash received but not yet recognized in revenue	203
Revenue recognized from prior period deferral	(144)
Deferred revenues, end of period	203
Affiliate [Member]
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenues, beginning of period	8
Cash received but not yet recognized in revenue	6
Revenue recognized from prior period deferral	(8)
Deferred revenues, end of period	$ 6

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Revenues - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		Sep. 30, 2023	Dec. 31, 2022
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 53.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 50.6
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 50.8
Weighted Average Recognition Timing	[1]		8 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Affiliate [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 2.0
Weighted Average Recognition Timing	[1]		2 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 48.4
Weighted Average Recognition Timing	[1]	8 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01 | Affiliate [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 1.5
Weighted Average Recognition Timing	[1]	2 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 0.8
Weighted Average Recognition Timing	[1]		4 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 0.7
Weighted Average Recognition Timing	[1]	3 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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Revenues - Remaining Performance Obligation, Variable Consideration (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
LNG [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	53.00%	78.00%	55.00%	74.00%
LNG [Member] | Affiliate [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	64.00%	77.00%	68.00%	76.00%
Regasification [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	7.00%	1.00%	7.00%	2.00%

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Related Party Transaction [Line Items]
Revenues		$ 2,128	$ 4,976	$ 6,978	$ 12,485
Cost of sales		684	4,843	1,618	10,612
Operating and maintenance expense		263	246	844	713
General and administrative expense		22	26	74	73
Other		5	0	7	0
Affiliate [Member]
Related Party Transaction [Line Items]
Cost of sales		2	104	20	166
Operating and maintenance expense		38	39	120	118
General and administrative expense		20	23	66	70
Other		1	0	1	0
Related Party [Member]
Related Party Transaction [Line Items]
Cost of sales		0	0	0	1
Operating and maintenance expense		14	18	44	45
LNG [Member]
Related Party Transaction [Line Items]
Revenues		2,079	4,506	6,830	11,849
LNG [Member] | Affiliate [Member]
Related Party Transaction [Line Items]
Revenues		515	1,376	1,745	3,268
LNG [Member] | Related Party [Member]
Related Party Transaction [Line Items]
Revenues		0	0	0	4
Cheniere Marketing Agreements [Member] | LNG [Member] | Affiliate [Member]
Related Party Transaction [Line Items]
Revenues		513	1,328	1,742	3,173
Contracts for Sale and Purchase of Natural Gas And LNG [Member] | Affiliate [Member]
Related Party Transaction [Line Items]
Cost of sales		2	104	20	166
Contracts for Sale and Purchase of Natural Gas And LNG [Member] | LNG [Member] | Affiliate [Member]
Related Party Transaction [Line Items]
Revenues		2	48	3	95
Natural Gas Transportation and Storage Agreements [Member] | Related Party [Member]
Related Party Transaction [Line Items]
Cost of sales	[1]	0	0	0	1
Operating and maintenance expense	[1]	14	18	44	45
Natural Gas Transportation and Storage Agreements [Member] | LNG [Member] | Related Party [Member]
Related Party Transaction [Line Items]
Revenues	[1]	0	0	0	4
Service Agreements [Member] | Affiliate [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense		38	39	120	118
General and administrative expense		20	23	66	70
Other		$ 1	$ 0	$ 1	$ 0

[1] This related party is partially owned by Brookfield, who indirectly owns a portion of our limited partner interests.

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Related Party Transactions - Other Agreements (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022	Dec. 31, 2018
Related Party Transaction [Line Items]
Other non-current liabilities	$ 76		$ 76		$ 23
Affiliate [Member]
Related Party Transaction [Line Items]
Other non-current liabilities	24		24		23
Tug Services [Member] | Cheniere Terminals [Member] | Terminal Marine Services Agreement [Member]
Related Party Transaction [Line Items]
General Partner Distributions	4	$ 2	8	$ 7
SPLNG [Member] | Cooperative Endeavor Agreements [Member]
Related Party Transaction [Line Items]
Aggregate commitment under the Agreement	25		$ 25
Tax Initiative Agreement Term			10 years
Tax Credits Forgiven						$ 7
Tax Credits Deferred					17
SPLNG [Member] | Affiliate [Member] | Cooperative Endeavor Agreements [Member]
Related Party Transaction [Line Items]
Other non-current liabilities	$ 17		$ 17		$ 17

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Net Income (Loss) per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			3 Months Ended							9 Months Ended
		Oct. 27, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022		Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2023	Sep. 30, 2022
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss)			$ 791	$ 622	$ 1,935	$ (514)		$ 342	$ 159	$ 3,348	$ (13)
Declared distributions			714			753				2,142	2,229
Assumed allocation of undistributed net income (loss)	[1]		$ 77			$ (1,267)				$ 1,206	$ (2,242)
Weighted average units outstanding			484.0			484.0				484.0	484.0
Basic and diluted net income (loss) per unit	[2]		$ 1.19			$ (1.49)				$ 5.53	$ (1.36)
Common Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss)			$ 774	610	1,897	$ (503)		335	157
Declared distributions			499			518				$ 1,496	$ 1,539
Assumed allocation of undistributed net income (loss)	[1]		75			(1,242)				1,181	(2,197)
Assumed allocation of net income			$ 574			$ (724)				$ 2,677	$ (658)
Weighted average units outstanding			484.0			484.0				484.0	484.0
Basic and diluted net income (loss) per unit			$ 1.19			$ (1.49)	[3]			$ 5.53	$ (1.36)
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		$ 1.03
Common Units [Member] | Subsequent Event [Member] | Base Amount [Member]
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 [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.255
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss)			$ 17	$ 12	$ 38	$ (11)		$ 7	$ 2
Declared distributions			14			15				$ 43	$ 45
Assumed allocation of undistributed net income (loss)	[1]		1			(25)				24	(45)
Assumed allocation of net income			15			(10)				67	0
IDR [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Declared distributions			201			220				603	645
Assumed allocation of undistributed net income (loss)	[1]		0			0				0	0
Assumed allocation of net income			$ 201			$ 220				$ 603	$ 645

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

[2] In computing basic and diluted net income (loss) per common unit, net income (loss) is reduced by the amount of undistributed net income (loss) allocated to participating securities other than common units, as required under the two-class method. See Note 12—Net Income (Loss) per Common Unit.

[3] Basic and diluted net income (loss) per unit in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

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Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member]	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Total Revenues from External Customers [Member] | Customer A [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17.00%	18.00%	23.00%	23.00%
Total Revenues from External Customers [Member] | Customer B [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	18.00%	16.00%	16.00%	16.00%
Total Revenues from External Customers [Member] | Customer C [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	17.00%	14.00%	16.00%	16.00%
Total Revenues from External Customers [Member] | Customer D [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	15.00%	16.00%	15.00%	16.00%
Total Revenues from External Customers [Member] | Customer E [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%
Total Revenues from External Customers [Member] | Customer F [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	0.00%	12.00%	0.00%
Total Revenues from External Customers [Member] | Customer G
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%		11.00%
Accounts Receivable, Net from External Customers [Member] | Customer A [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			19.00%		27.00%
Accounts Receivable, Net from External Customers [Member] | Customer B [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			14.00%		18.00%
Accounts Receivable, Net from External Customers [Member] | Customer C [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			22.00%
Accounts Receivable, Net from External Customers [Member] | Customer D [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			11.00%		18.00%
Accounts Receivable, Net from External Customers [Member] | Customer E [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage					13.00%
Accounts Receivable, Net from External Customers [Member] | Customer G
Concentration Risk [Line Items]
Concentration Risk, Percentage			15.00%

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Supplemental Cash Flow Information (Details) $ in Millions			1 Months Ended	3 Months Ended	9 Months Ended
		Mar. 15, 2022 USD ($)	Mar. 31, 2022 MMBTU	Mar. 31, 2022 USD ($)	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Dec. 31, 2022 USD ($)
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest on debt, net of amounts capitalized					$ 658	$ 585
Unpaid purchases of property, plant and equipment, net					31	$ 147
Nonmonetary Transaction [Line Items]
Distributions for novated IPM Agreement				$ 2,712
Current derivative liabilities	[1]				294		$ 769
Derivative liabilities	[1]				$ 1,731		$ 3,024
Novation of IPM Agreement [Member]
Nonmonetary Transaction [Line Items]
Distributions for novated IPM Agreement		$ 2,700
Current derivative liabilities		142
Derivative liabilities		$ 2,600
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

[1] Does not include collateral posted by counterparties to us of $1 million as of September 30, 2023, which is included in other current liabilities on our Consolidated Balance Sheets, and collateral posted with counterparties by us of $35 million as of December 31, 2022, which is included in margin deposits on our Consolidated Balance Sheets.