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, ~~2021~~2022

☐�� 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 ~~29, 2021,~~31, 2022, the registrant had ~~484,025,623~~484,031,623 common units outstanding.

CHENIERE ENERGY PARTNERS, L.P.

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	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	7
	Note 3—Restricted Cas h and Cash Equivalents	8
	Note 4—~~Accounts~~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	89
	Note 7—Derivative Instruments	9

	Note 8 —8—Accrued Liabilities	12
	Note 9 —9—Debt	13
	Note 110—Revenu 0 ~~—Revenues from Contracts with Customers~~es	1514
	Note 1 1 —11—Related Party Transactions	1817
	Note 1 2 —12—Net Income (Loss) per Common Unit	2221
	Note 1 3 —13—Customer Concentration	2423
	Note 1 4 —14—Supplemental Cash Flow Information	2423

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2524

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3835

Item 4.	Controls and Procedures	3936

Part II. Other Information
Item 1.	Legal Proceedings	4037

Item 1A.	Risk Factors	4037

Item 5.	Other Information	4037

Item 6.	Exhibits	4138

	Signatures	4239

Table of Contents

DEFINITIONS

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

Common Industry and Other Terms


ASU						Accounting Standards Update
Bcf						billion cubic feet
Bcf/d						billion cubic feet per day
Bcf/yr						billion cubic feet per year
Bcfe						billion cubic feet equivalent
DOE						U.S. Department of Energy
EPC						engineering, procurement and construction
FASB						Financial Accounting Standards Board
FERC						Federal Energy Regulatory Commission
FTA countries						countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP						generally accepted accounting principles in the United States
Henry Hub						the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
IPM agreements						integrated production marketing agreements in which the gas producer sells to us gas on a global LNG index price, less a fixed liquefaction fee, shipping and other costs
LIBOR						London Interbank Offered Rate
LNG						liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu						million British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
mtpa						million tonnes per annum
non-FTA countries						countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC						U.S. Securities and Exchange Commission
SPA						LNG sale and purchase agreement
TBtu						trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
Train						an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA						terminal use agreement

Table of Contents

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of September 30, ~~2021,~~2022, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

Unless the context requires otherwise, references to ~~“Cheniere Partners,~~“CQP,” “the Partnership,” “we,” “us” and “our” refer to Cheniere Energy Partners, L.P. and its consolidated subsidiaries, including SPLNG, SPL and CTPL.

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. 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,
2021 2020 2021 2020
Revenues
LNG revenues $ 1,791 $ 807 $ 5,057 $ 3,588
LNG revenues—affiliate 453 103 878 352
Regasification revenues 68 67 202 202
Other revenues 12 5 39 28
Total revenues 2,324 982 6,176 4,170
Operating costs and expenses
Cost of sales (excluding items shown separately below) 1,342 454 3,178 1,551
Cost of sales—affiliate 8 33 62 38
Cost of sales—related party — — 1 —
Operating and maintenance expense 148 146 465 463
Operating and maintenance expense—affiliate 34 34 103 115
Operating and maintenance expense—related party 12 — 34 —
Development expense — — 1 —
General and administrative expense 2 2 7 12
General and administrative expense—affiliate 22 24 64 73
Depreciation and amortization expense 140 137 417 413
Impairment expense and loss on disposal of assets — — 6 5
Total operating costs and expenses 1,708 830 4,338 2,670
Income from operations 616 152 1,838 1,500
Other income (expense)
Interest expense, net of capitalized interest (210) (221) (636) (691)
Loss on modification or extinguishment of debt (27) — (81) (43)
Other income, net 2 2 2 8
Total other expense (235) (219) (715) (726)
Net income (loss) $ 381 $ (67) $ 1,123 $ 774
Basic and diluted net income (loss) per common unit $ 0.69 $ (0.08) $ 2.07 $ 1.55
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation 484.0 414.8 484.0 370.9


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Revenues
LNG revenues	$	3,130	$	1,791	$	8,577	$	5,057
LNG revenues—affiliate	1,376		453		3,268		878
LNG revenues—related party	—		—		4		—
Regasification revenues	455		68		591		202

Other revenues	15		12		45		39

Total revenues	4,976		2,324		12,485		6,176

Operating costs and expenses
Cost of sales (excluding items shown separately below)	4,739		1,342		10,445		3,178
Cost of sales—affiliate	104		8		166		62
Cost of sales—related party	—		—		1		1
Operating and maintenance expense	189		148		550		465
Operating and maintenance expense—affiliate	39		34		118		103
Operating and maintenance expense—related party	18		12		45		34


General and administrative expense	3		2		3		7
General and administrative expense—affiliate	23		22		70		64
Depreciation and amortization expense	160		140		469		417
Other	—		—		—		7

Total operating costs and expenses	5,275		1,708		11,867		4,338

Income (loss) from operations	(299)		616		618		1,838

Other income (expense)
Interest expense, net of capitalized interest	(222)		(210)		(641)		(636)
Loss on modification or extinguishment of debt	—		(27)		—		(81)

Other income, net	7		2		10		2

Total other expense	(215)		(235)		(631)		(715)

Net income (loss)	$	(514)	$	381	$	(13)	$	1,123

Basic and diluted net income (loss) per common unit (1)	$	(1.49)	$	0.69	$	(1.36)	$	2.07


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 Unit.

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

September 30, December 31,
2021 2020
ASSETS (unaudited)
Current assets
Cash and cash equivalents $ 1,713 $ 1,210
Restricted cash 133 97
Accounts and other receivables, net of current expected credit losses 358 318
Accounts receivable—affiliate 198 184
Advances to affiliate 130 144
Inventory 134 107
Current derivative assets 44 14
Other current assets 105 61
Total current assets 2,815 2,135
Property, plant and equipment, net of accumulated depreciation 16,820 16,723
Operating lease assets, net of accumulated amortization 93 99
Debt issuance costs, net of accumulated amortization 13 17
Derivative assets 25 11
Other non-current assets, net 163 160
Total assets $ 19,929 $ 19,145
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable $ 14 $ 12
Accrued liabilities 846 658
Accrued liabilities—related party 5 4
Current debt, net of discount and debt issuance costs 944 —
Due to affiliates 45 53
Deferred revenue 166 137
Deferred revenue—affiliate 4 1
Current operating lease liabilities 8 7
Current derivative liabilities 23 11
Total current liabilities 2,055 883
Long-term debt, net of premium, discount and debt issuance costs 17,171 17,580
Non-current deferred revenue 1 —
Operating lease liabilities 85 90
Derivative liabilities 13 35
Other non-current liabilities — 1
Other non-current liabilities—affiliate 15 17
Partners’ equity
Common unitholders’ interest (484.0 million units issued and outstanding at both September 30, 2021 and December 31, 2020) 856 714
General partner’s interest (2% interest with 9.9 million units issued and outstanding at September 30, 2021 and December 31, 2020) (267) (175)
Total partners’ equity 589 539
Total liabilities and partners’ equity $ 19,929 $ 19,145



	September 30,		December 31,
	2022		2021
ASSETS	(unaudited)
Current assets
Cash and cash equivalents	$	988	$	876
Restricted cash and cash equivalents	195		98
Trade and other receivables, net of current expected credit losses	805		580
Accounts receivable—affiliate	447		232
Accounts receivable—related party	—		1
Advances to affiliate	150		141
Inventory	241		176
Current derivative assets	27		21
Margin deposits	59		7
Contract assets	387		—
Other current assets	74		80

Total current assets	3,373		2,212


Property, plant and equipment, net of accumulated depreciation	16,827		16,830
Operating lease assets	91		98
Debt issuance costs, net of accumulated amortization	9		12
Derivative assets	33		33
Other non-current assets, net	167		173

Total assets	$	20,500	$	19,358

LIABILITIES AND PARTNERS’ EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	31	$	21
Accrued liabilities	1,657		1,073
Accrued liabilities—related party	8		4
Current debt, net of discount and debt issuance costs	1,498		—
Due to affiliates	56		67
Deferred revenue	162		155
Deferred revenue—affiliate	1		1
Current operating lease liabilities	9		8
Current derivative liabilities	1,157		16
Other current liabilities	4		—
Total current liabilities	4,583		1,345

Long-term debt, net of premium, discount and debt issuance costs	15,699		17,177

Operating lease liabilities	82		89
Finance lease liabilities	18		—
Derivative liabilities	3,981		11

Other non-current liabilities—affiliate	21		18



Partners’ equity (deficit)
Common unitholders’ interest (484.0 million units issued and outstanding at both September 30, 2022 and December 31, 2021)	(3,059)		1,024

General partner’s interest (2% interest with 9.9 million units issued and outstanding at September 30, 2022 and December 31, 2021)	(825)		(306)
Total partners’ equity (deficit)	(3,884)		718
Total liabilities and partners’ equity (deficit)	$	20,500	$	19,358

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY (DEFICIT)

(in millions)

(unaudited)

Three and Nine Months Ended September 30, 2021
Common Unitholders’ Interest Subordinated Unitholder’s Interest General Partner’s Interest Total Partners’ Equity
Units Amount Units Amount Units Amount
Balance at December 31, 2020 484.0 $ 714 — $ — 9.9 $ (175) $ 539
Net income — 340 — — — 7 347
Distributions
Common units, $0.655/unit — (316) — — — — (316)
General partner units — — — — — (35) (35)
Balance at March 31, 2021 484.0 738 — — 9.9 (203) 535
Net income — 387 — — — 8 395
Distributions
Common units, $0.660/unit — (320) — — — — (320)
General partner units — — — — — (39) (39)
Balance at June 30, 2021 484.0 805 — — 9.9 (234) 571
Net income — 373 — — — 8 381
Distributions
Common units, $0.665/unit — (322) — — — — (322)
General partner units — — — — — (41) (41)
Balance at September 30, 2021 484.0 $ 856 — $ — 9.9 $ (267) $ 589


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)

Three and Nine Months Ended September 30, 2020
Common Unitholders’ Interest Subordinated Unitholder’s Interest General Partner’s Interest Total Partners’ Equity
Units Amount Units Amount Units Amount
Balance at December 31, 2019 348.6 $ 1,792 135.4 $ (996) 9.9 $ (81) $ 715
Net income — 307 — 119 — 9 435
Distributions
Common units, $0.630/unit — (220) — — — — (220)
Subordinated units, $0.630/unit — — — (85) — — (85)
General partner units — — — — — (25) (25)
Balance at March 31, 2020 348.6 1,879 135.4 (962) 9.9 (97) 820
Net income — 287 — 111 — 8 406
Distributions
Common units, $0.640/unit — (223) — — — — (223)
Subordinated units, $0.640/unit — — — (86) — — (86)
General partner units — — — — — (29) (29)
Balance at June 30, 2020 348.6 $ 1,943 135.4 $ (937) 9.9 $ (118) $ 888
Net loss — (65) — (1) — (1) (67)
Conversion of subordinated units into common units 135.4 (1,026) (135.4) 1,026 — — —
Distributions
Common units, $0.645/unit — (225) — — — — (225)
Subordinated units, $0.645/unit — — — (88) — — (88)
General partner units — — — — — (30) (30)
Balance at September 30, 2020 484.0 $ 627 — $ — 9.9 $ (149) $ 478


Three and Nine Months Ended September 30, 2021
	Common Unitholders’ Interest			General Partner’s Interest	Total Partners’ Equity
	Units	Amount				Units			Amount
















Balance at December 31, 2020	484.0	$	714		9.9		$	(175)		$	539
Net income	—	340			—		7			347
Distributions
Common units, $0.655/unit	—	(316)			—		—			(316)
General partner units	—	—			—		(35)			(35)
Balance at March 31, 2021	484.0	738			9.9		(203)			535
Net income	—	387			—		8			395
Distributions
Common units, $0.660/unit	—	(320)			—		—			(320)
General partner units	—	—			—		(39)			(39)
Balance at June 30, 2021	484.0	805			9.9		(234)			571
Net income	—	373			—		8			381
Distributions
Common units, $0.665/unit	—	(322)			—		—			(322)
General partner units	—	—			—		(41)			(41)
Balance at September 30, 2021	484.0	$	856		9.9		$	(267)		$	589

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

Nine Months Ended September 30,
2021 2020
Cash flows from operating activities
Net income $ 1,123 $ 774
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense 417 413
Amortization of debt issuance costs, premium and discount 22 24
Loss on modification or extinguishment of debt 81 43
Total losses (gains) on derivatives, net (64) 38
Net cash provided by (used for) settlement of derivative instruments 10 (2)
Impairment expense and loss on disposal of assets 6 5
Other 13 10
Changes in operating assets and liabilities:
Accounts and other receivables, net of current expected credit losses (41) 93
Accounts receivable—affiliate (13) 23
Advances to affiliate 11 31
Inventory (26) 2
Accounts payable and accrued liabilities 165 (96)
Accrued liabilities—related party 1 2
Due to affiliates (6) (3)
Deferred revenue 29 24
Other, net (62) (45)
Other, net—affiliate 1 (3)
Net cash provided by operating activities 1,667 1,333
Cash flows from investing activities
Property, plant and equipment (495) (795)
Net cash used in investing activities (495) (795)
Cash flows from financing activities
Proceeds from issuances of debt 2,700 1,995
Repayments of debt (2,172) (2,000)
Debt issuance and other financing costs (35) (34)
Debt extinguishment costs (61) (39)
Distributions to owners (1,073) (1,011)
Other 8 —
Net cash used in financing activities (633) (1,089)
Net increase (decrease) in cash, cash equivalents and restricted cash 539 (551)
Cash, cash equivalents and restricted cash—beginning of period 1,307 1,962
Cash, cash equivalents and restricted cash—end of period $ 1,846 $ 1,411


	Nine Months Ended September 30,
	2022		2021
Cash flows from operating activities
Net income (loss)	$	(13)	$	1,123
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	469		417
Amortization of debt issuance costs, premium and discount	22		22
Loss on modification or extinguishment of debt	—		81
Total losses (gains) on derivative instruments, net	2,447		(64)

Net cash provided by (used for) settlement of derivative instruments	(54)		10

Other	28		19

Changes in operating assets and liabilities:
Trade and other receivables, net of current expected credit losses	(290)		(41)
Accounts receivable—affiliate	(231)		(13)

Advances to affiliate	(10)		11
Inventory	(67)		(26)
Margin deposits	(52)		(25)
Contract assets	(387)		—
Accounts payable and accrued liabilities	592		165
Accrued liabilities—related party	5		1
Due to affiliates	2		(6)
Deferred revenue	6		29
Other, net	(30)		(37)
Other, net—affiliate	5		1
Net cash provided by operating activities	2,442		1,667

Cash flows from investing activities
Property, plant and equipment	(356)		(495)

Net cash used in investing activities	(356)		(495)

Cash flows from financing activities
Proceeds from issuances of debt	—		2,700
Redemptions and repayments of debt	—		(2,172)
Debt issuance and other financing costs	—		(35)
Debt extinguishment costs	—		(61)

Distributions	(1,877)		(1,073)
Other	—		8
Net cash used in financing activities	(1,877)		(633)

Net increase in cash, cash equivalents and restricted cash and cash equivalents	209		539
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	974		1,307
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$	1,183	$	1,846

Balances per Consolidated Balance ~~Sheets:~~Sheet:


	September 30,
	~~2021~~2022
Cash and cash equivalents	$	~~1,713~~988
Restricted cash and cash equivalents	~~133~~195

Total cash, cash equivalents and restricted cash and cash equivalents	$	~~1,846~~1,183

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

~~The Sabine Pass LNG terminal is~~We own the natural gas liquefaction and export facility located in Cameron Parish, Louisiana ~~and~~at Sabine Pass (the “Sabine Pass LNG Terminal”) which has ~~natural gas liquefaction facilities consisting of 5~~six operational ~~natural gas liquefaction~~ Trains, ~~and 1 additional~~with Train ~~that is undergoing commissioning and expected to be substantially completed in the first quarter of~~6 having achieved substantial completion on February 4, 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG ~~terminal~~Terminal also has operational regasification facilities that include 5five LNG storage tanks, vaporizers and 2three marine berths, with ~~an additional marine~~the third berth ~~that is under construction.~~having achieved substantial completion on October 27, 2022. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG ~~terminal~~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. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive final investment decision.

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

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of ~~Cheniere Partners~~CQP have been prepared in accordance with GAAP for interim financial information and in accordance with Rule 10-01 of Regulation ~~S-X.~~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, ~~2020~~2021.

Results of operations for the three and nine months ended September 30, ~~2021~~2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, ~~2021.~~2022.

We are not subject to either federal or state income tax, as our partners are taxed individually on their allocable share of our taxable income. ~~Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements.~~

Recent Accounting Standards

ASU 2020-04

In March 2020, the ~~Financial Accounting Standards Board (“FASB”)~~FASB issued ~~Accounting Standards Update (“ASU”)~~ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing debt agreements expected to arise from the market transition from LIBOR to alternative reference rates. The ~~optional expedients were available~~standard is effective from March 12, 2020 to ~~be used upon issuance of this guidance but we~~December 31, 2022. We have not yet applied the ~~guidance~~optional expedients available under the standard because we have not yet modified any of our existing contracts indexed to LIBOR, mainly our credit facilities as further described in Note 9—Debt, for reference rate reform. ~~Once~~However, we ~~apply an optional expedient to a modified contract and adopt this standard,~~do not expect the ~~guidance will be applied to all subsequent applicable contract modifications until December 31, 2022, at which time~~impact of applying the optional expedients ~~are no longer available.~~to any future contract modifications to be material, and we do not expect the transition to a replacement rate index to have a material impact on our future cash flows.

NOTE 2—UNITHOLDERS’ EQUITY

The common units represent limited partner interests in ~~us. The holders of~~us, which entitle the ~~units are entitled~~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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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.

Although common unitholders are not obligated to fund losses of the Partnership, its capital account, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continues to share in losses.

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights (“IDRs”), which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus as additional target levels are met, but may transfer these rights separately from its general partner interest. The higher percentages range from 15% to 50%, inclusive of the general partner interest.

~~CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED~~

~~(unaudited)~~

As of September 30, ~~2021,~~2022, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.4% by CQP Target Holdco L.L.C. (“CQP Target Holdco”) and other affiliates of ~~The~~ Blackstone ~~Group~~ Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) and 8.0% by the public. All of our 2% general partner interest was held by Cheniere. CQP Target Holdco’s equity interests are ~~50.00%~~50.0% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone, and ~~50.00%~~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

Restricted cash ~~consists~~and cash equivalents consist of funds that are contractually or legally restricted as to usage or ~~withdrawal~~withdrawal. As of September 30, 2022 and ~~have been presented separately from~~December 31, 2021, we had $195 million and $98 million of restricted cash and cash equivalents, ~~on our Consolidated Balance Sheets. As of September 30, 2021 and December 31, 2020, we had $133 million and $97 million of restricted cash,~~ respectively.

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

NOTE 4—~~ACCOUNTS~~TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

~~As of September 30, 2021 and December 31, 2020, accounts~~Trade and other receivables, net of current expected credit losses consisted of the following (in millions):

September 30, December 31,
2021 2020
SPL trade receivable $ 338 $ 300
Other accounts receivable 20 18
Total accounts and other receivables, net of current expected credit losses $ 358 $ 318



	September 30,		December 31,
	2022		2021
Trade receivables	$	761	$	546
Other receivables	44		34
Total trade and other receivables, net of current expected credit losses	$	805	$	580

NOTE 5—INVENTORY

~~As of September 30, 2021 and December 31, 2020, inventory~~Inventory consisted of the following (in millions):


		September 30,		December 31,			September 30,		December 31,
		2021		2020			2022		2021
Materials	Materials	$	83	$	81	Materials	$	100	$	86
LNG	LNG	33		8		LNG	107		45
Natural gas	Natural gas	16		17		Natural gas	32		43
Other	Other	2		1		Other	2		2
Total inventory	Total inventory	$	134	$	107	Total inventory	$	241	$	176

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

~~As of September 30, 2021 and December 31, 2020, property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):~~

September 30, December 31,
2021 2020
LNG terminal
LNG terminal and interconnecting pipeline facilities $ 16,950 $ 16,908
LNG terminal construction-in-process 2,623 2,154
Accumulated depreciation (2,757) (2,344)
Total LNG terminal, net of accumulated depreciation 16,816 16,718
Fixed assets
Fixed assets 30 29
Accumulated depreciation (26) (24)
Total fixed assets, net of accumulated depreciation 4 5
Property, plant and equipment, net of accumulated depreciation $ 16,820 $ 16,723

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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,
	2022		2021
LNG terminal
Terminal and interconnecting pipeline facilities	$	19,459	$	16,973

Construction-in-process	699		2,746
Accumulated depreciation	(3,356)		(2,893)
Total LNG terminal, net of accumulated depreciation	16,802		16,826
Fixed assets
Fixed assets	29		29
Accumulated depreciation	(26)		(25)
Total fixed assets, net of accumulated depreciation	3		4
Assets under finance lease
Tug vessels	23		—
Accumulated depreciation	(1)		—
Total assets under finance lease, net of accumulated depreciation	22		—
Property, plant and equipment, net of accumulated depreciation	$	16,827	$	16,830

The following table shows depreciation expense ~~during the three~~ and ~~nine months ended September 30, 2021 and 2020~~offsets to LNG terminal costs (in millions):

Three Months Ended September 30, Nine Months Ended September 30,
2021 2020 2021 2020
Depreciation expense $ 139 $ 135 $ 414 $ 409


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Depreciation expense	$	158	$	139	$	465	$	414
Offsets to LNG terminal costs (1)	—		—		148		—

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

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into commodity derivatives consisting of natural gas supply contracts, including those under SPL’s IPM agreement, for the ~~commissioning and~~ operation of the Liquefaction Project (“Physical Liquefaction Supply Derivatives”) and associated economic hedges (“Financial Liquefaction Supply Derivatives,” and collectively with the Physical Liquefaction Supply Derivatives, the “Liquefaction Supply Derivatives”).

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

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis ~~as of September 30, 2021 and December 31, 2020~~ (in millions):

Fair Value Measurements as of
September 30, 2021 December 31, 2020
Quoted Prices in Active Markets
(Level 1) Significant Other Observable Inputs
(Level 2) Significant Unobservable Inputs
(Level 3) Total Quoted Prices in Active Markets
(Level 1) Significant Other Observable Inputs
(Level 2) Significant Unobservable Inputs
(Level 3) Total
Liquefaction Supply Derivatives asset (liability) $ (18) $ (8) $ 59 $ 33 $ 1 $ (1) $ (21) $ (21)


	Fair Value Measurements as of
	September 30, 2022								December 31, 2021
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total

Liquefaction Supply Derivatives asset (liability)	$	(30)	$	(24)	$	(5,024)	$	(5,078)	$	2	$	(13)	$	38	$	27

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The fair value of our Physical Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value including, ~~evaluating~~but not limited to, evaluation of whether the respective market ~~is available~~exists from the perspective of market participants as ~~pipeline~~ infrastructure is developed. The fair value of our Physical Liquefaction Supply Derivatives incorporates risk premiums related to the satisfaction of conditions precedent, such as completion and placement into service of relevant pipeline infrastructure to accommodate marketable physical gas flow. As of September 30, 2021 and December 31, 2020, some of our Physical Liquefaction Supply Derivatives existed within markets for which the pipeline infrastructure was under development to accommodate marketable physical gas flow.

We include a portion of our Physical Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity ~~volatility~~ and ~~contract duration.~~volatility.

~~CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED~~

~~(unaudited)~~

The Level 3 fair value measurements of natural gas positions within our Physical Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Physical Liquefaction Supply Derivatives as of September 30, ~~2021:~~2022:

Net Fair Value ~~Asset~~Liability
(in millions)

Valuation Approach

Significant Unobservable Input

Range of Significant Unobservable Inputs / Weighted Average (1)

Physical Liquefaction Supply Derivatives

$59(5,024)

Market approach incorporating present value techniques

Henry Hub basis spread

$~~(1.333)~~(2.495) - ~~$0.415~~$0.677 / ~~$0.015~~$(0.028)

Option pricing model

International LNG pricing spread, relative to Henry Hub (2)

91% - 865% / 243%

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

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

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

The following table shows the changes in the fair value of our Level 3 Physical Liquefaction Supply Derivatives ~~during the three and nine months ended September 30, 2021 and 2020~~ (in millions):


		Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,						Nine Months Ended September 30,
		2021		2020		2021		2020				2022		2021			2022		2021
Balance, beginning of period	Balance, beginning of period	$	33	$	51	$	(21)	$	24		Balance, beginning of period	$	(3,456)	$	33		$	38	$	(21)
Realized and mark-to-market gains (losses):	Realized and mark-to-market gains (losses):										Realized and mark-to-market gains (losses):
Included in cost of sales	Included in cost of sales	25		(47)		79		(22)			Included in cost of sales	(1,545)		25			(155)		79
Purchases and settlements:	Purchases and settlements:										Purchases and settlements:
Purchases(1)	Purchases(1)	4		5		6		4			Purchases(1)	3		4			(4,896)		6
Settlements	Settlements	(3)		(8)		(5)		(6)			Settlements	(24)		(3)			(11)		(5)
Transfers out of Level 3, net ~~(1)~~(2)	Transfers out of Level 3, net ~~(1)~~(2)	—		(1)		—		—			Transfers out of Level 3, net ~~(1)~~(2)	(2)		—			—		—
Balance, end of period	Balance, end of period	$	59	$	—	$	59	$	—		Balance, end of period	$	(5,024)	$	59		$	(5,024)	$	59
Change in unrealized gains (losses) relating to instruments still held at end of period	Change in unrealized gains (losses) relating to instruments still held at end of period	$	25	$	(47)	$	79	$	(22)		Change in unrealized gains (losses) relating to instruments still held at end of period	$	(1,545)	$	25		$	(155)	$	79

(1)~~Transferred into Level 3~~Includes the assignment of an IPM agreement that occurred during the period, as ~~a result of unobservable market, or~~discussed in Note 1 4 —Supplemental Cash Flow Information.

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

All counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from our derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

counterparty’s nonperformance risk in fair value ~~measurements.~~measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

Liquefaction Supply Derivatives

SPL ~~has entered into~~holds Liquefaction Supply Derivatives which are primarily ~~index-based physical~~indexed to the natural gas ~~supply contracts~~market and ~~associated economic hedges to purchase natural gas for the commissioning and operation of the Liquefaction Project.~~international LNG indices. The remaining minimum terms of the ~~physical natural gas supply contracts~~Physical Liquefaction Supply Derivatives range up to 1015 years, some of which commence upon the satisfaction of certain events or states of affairs. The terms of the Financial Liquefaction Supply Derivatives range up to approximately three years.

The forward notional ~~natural gas position of~~amount for our Liquefaction Supply Derivatives was approximately ~~5,135~~5,220 TBtu and ~~4,970~~5,194 TBtu as of September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively, ~~of which 99 TBtu and 91 TBtu, respectively,~~excluding notional amounts associated with extension options that were ~~for a natural gas supply contract that SPL has with a related party.~~

~~CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED~~

~~(unaudited)~~

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

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

Fair Value Measurements as of (1)
Consolidated Balance Sheets Location September 30, 2021 December 31, 2020
Current derivative assets $ 44 $ 14
Derivative assets 25 11
Total derivative assets 69 25
Current derivative liabilities (23) (11)
Derivative liabilities (13) (35)
Total derivative liabilities (36) (46)
Derivative asset (liability), net $ 33 $ (21)

~~(1)Does not include collateral posted with counterparties by us of $29 million and $4 million, which are included in other current assets in our Consolidated Balance Sheets~~uncertain to be taken as of September 30, ~~2021 and December 31, 2020, respectively. Includes a natural gas supply contract that SPL has with a related party, which had a fair value of zero as of both September 30, 2021 and December 31, 2020.~~2022.

The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations ~~during the three and nine months ended September 30, 2021 and 2020~~ (in millions):


		Gain (Loss) Recognized in Consolidated Statements of Operations											Gain (Loss) Recognized in Consolidated Statements of Operations
Consolidated Statements of Operations Location (1)	Consolidated Statements of Operations Location (1)	Three Months Ended September 30,				Nine Months Ended September 30,				Consolidated Statements of Operations Location (1)	Three Months Ended September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020				Consolidated Statements of Operations Location (1)	2022		2021		2022		2021
LNG revenues	LNG revenues	$	—	$	7	$	—	$	3				$	(3)	$	—	$	1	$	—
Cost of sales	Cost of sales	10		(74)		64		(41)				Cost of sales	(1,625)		10		(2,448)		64

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

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

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




	Fair Value Measurements as of (1)
Consolidated Balance Sheets Location	September 30, 2022		December 31, 2021
Current derivative assets	$	27	$	21
Derivative assets	33		33
Total derivative assets	60		54

Current derivative liabilities	(1,157)		(16)
Derivative liabilities	(3,981)		(11)
Total derivative liabilities	(5,138)		(27)

Derivative asset (liability), net	$	(5,078)	$	27

(1)Does not include collateral posted with counterparties by us of $59 million and $7 million, as of September 30, 2022 and December 31, 2021, respectively, which are included in other current assets in our Consolidated Balance Sheets.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

Consolidated Balance Sheets Presentation

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


	Liquefaction Supply Derivatives
As of September 30, ~~2021~~2022
Gross assets	$	7667
Offsetting amounts	(7)
Net assets	$	6960

Gross liabilities	$	~~(43)~~(5,158)
Offsetting amounts	720
Net liabilities	$	~~(36)~~(5,138)

As of December 31, ~~2020~~2021
Gross assets	$	6979
Offsetting amounts	~~(44)~~(25)
Net assets	$	2554

Gross liabilities	$	~~(48)~~(33)
Offsetting amounts	26
Net liabilities	$	~~(46)~~(27)

NOTE 8—ACCRUED LIABILITIES

~~As of September 30, 2021 and December 31, 2020, accrued~~Accrued liabilities consisted of the following (in millions):


		September 30,		December 31,			September 30,		December 31,
		2021		2020			2022		2021
Natural gas purchases						Natural gas purchases	$	1,259	$	786
Interest costs and related debt fees	Interest costs and related debt fees	$	209	$	203	Interest costs and related debt fees	201		180
Accrued natural gas purchases		523		374
LNG terminal and related pipeline costs	LNG terminal and related pipeline costs	87		71		LNG terminal and related pipeline costs	172		101
Other accrued liabilities	Other accrued liabilities	27		10		Other accrued liabilities	25		6
Total accrued liabilities	Total accrued liabilities	$	846	$	658	Total accrued liabilities	$	1,657	$	1,073

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 9—DEBT

~~As of September 30, 2021 and December 31, 2020, our debt~~Debt consisted of the following (in millions):

September 30, December 31,
2021 2020
Long-term debt:
SPL — 4.200% to 6.25% senior secured notes due between March 2022 and September 2037 and working capital facility (“2020 SPL Working Capital Facility”) (1)
$ 13,128 $ 13,650
Cheniere Partners — 3.250% to 5.625% senior notes due between October 2025 and January 2032 and credit facilities (“2019 CQP Credit Facilities”)
4,200 4,100
Unamortized premium, discount and debt issuance costs, net of accumulated amortization (157) (170)
Total long-term debt, net of premium, discount and debt issuance costs 17,171 17,580
Current debt:
SPL — current portion of 6.25% senior secured notes due March 2022 (the “2022 SPL Senior Notes”) (1) (2)
522 —
Cheniere Partners — current portion of 5.625% senior notes due October 2026 (the “2026 CQP Senior Notes”) (3)
428 —
Unamortized discount and debt issuance costs, net of accumulated amortization (6) —
Total current debt, net of discount and debt issuance costs 944 —
Total debt, net of premium, discount and debt issuance costs $ 18,115 $ 17,580



	September 30,		December 31,
	2022		2021
SPL:
Senior Secured Notes:

5.625% due 2023 (the “2023 SPL Senior Notes”) (1)	$	1,500	$	1,500
5.75% due 2024	2,000		2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.27% weighted average rate due 2037	1,282		1,282
Total SPL Senior Secured Notes	13,132		13,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Total debt - SPL	13,132		13,132

CQP:
Senior Notes:


4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
Total CQP Senior Notes	4,200		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Total debt - CQP	4,200		4,200
Total debt	17,332		17,332


Short-term debt	(1,498)		—
Unamortized premium, discount and debt issuance costs, net	(135)		(155)
Total long-term debt, net of premium, discount and debt issuance costs	$	15,699	$	17,177

(1)~~A portion~~In October 2022, $300 million of the ~~2022~~2023 SPL Senior Notes ~~is categorized as long-term debt because~~were redeemed. As of September 30, 2022, the ~~proceeds from the expected series of sales of approximately $482 million aggregate principal~~entire amount of ~~senior secured notes due 2037 pursuant to executed note purchase agreements, expected to be issued in~~ the ~~fourth quarter of 2021, subject to customary closing conditions, will be used to strategically refinance a portion of the 2022 SPL Senior Notes and pay related fees, costs and expenses.~~

~~(2)In October 2021, $318 million of the 2022~~2023 SPL Senior Notes was ~~redeemed with $100 million of the proceeds from our issuance of the 3.250% senior notes due 2032 (the “2032 CQP Senior Notes”) and $218 million of cash on hand. See~~ ~~Issuances and Redemptions~~ ~~section below for further discussion.~~

~~(3)~~In October 2021, we redeemed the remaining outstanding aggregate principal amount of the 2026 CQP Senior Notes that were not purchased pursuant to the tender offer and consent solicitation in September 2021. See ~~Issuances and Redemptions~~ ~~section below for further discussion.~~classified as short-term debt.

~~CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED~~

~~(unaudited)~~

~~Issuances and Redemptions~~

~~The following table shows the issuances and redemptions of long-term debt during the nine months ended September 30, 2021 (in millions), excluding intra-quarter borrowings and repayments:~~

~~Issuances~~

~~Principal Amount Issued~~

~~Three Months Ended March 31, 2021~~

~~Cheniere Partners~~ ~~— 4.000% Senior Notes due 2031 (the “2031 CQP Senior Notes”) (1)~~

~~1,500~~

~~Three Months Ended September 30, 2021~~

~~Cheniere Partners~~ ~~— 2032 CQP Senior Notes (2)~~

~~1,200~~

~~Nine Months Ended September 30, 2021 total~~

~~2,700~~

~~Redemptions~~

~~Principal Amount Redeemed~~

~~Three Months Ended March 31, 2021~~

~~Cheniere Partners~~ ~~— 5.250% Senior Notes due 2025 (the “2025 CQP Senior Notes”) (1)~~

~~1,500~~

~~Three Months Ended September 30, 2021~~

~~Cheniere Partners~~ ~~— 2026 CQP Senior Notes (2)~~

~~672~~

~~Nine Months Ended September 30, 2021 total~~

~~2,172~~

~~(1)~~Net proceeds from the issuance of the 2031 CQP Senior Notes, together with cash on hand, were used to redeem all of our outstanding 2025 CQP Senior Notes, resulting in $54 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs.

~~(2)~~Net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem a portion of the 2026 CQP Senior Notes in September 2021 pursuant to the tender offer and consent solicitation, resulting in $27 million of loss on extinguishment of debt relating to the payment of early redemption fees and write off of unamortized debt premium and issuance costs. In October 2021, the remaining net proceeds from the issuance of the 2032 CQP Senior Notes were used to redeem the remaining outstanding principal amount of the 2026 CQP Senior Notes and, together with cash on hand, redeem $318 million of the 2022 SPL Senior Notes.

Credit Facilities

Below is a summary of our credit facilities outstanding as of September 30, ~~2021~~2022 (in millions):

2020 SPL Working Capital Facility (1)

2019 CQP Credit Facilities

SPL Working Capital Facility

CQP Credit Facilities

Original facility size

1,200

1,500

Total facility size

1,200

750

Less:

Outstanding balance

—

Outstanding balance

—

Commitments prepaid or terminated

—

750

Letters of credit issued

396

—

Letters of credit issued

363

—

Available commitment

804

750

Available commitment

837

750

Priority ranking

Senior secured

Priority ranking

Senior secured

Interest rate on available balance

LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%

LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%

Interest rate on available balance

LIBOR plus 1.125% - 1.750% or base rate plus 0.125% - 0.750%

LIBOR plus 1.25% - 2.125% or base rate plus 0.25% - 1.125%

Weighted average interest rate of outstanding balance

n/a

Commitment fees on undrawn balance

0.15%

0.49%

Maturity date

March 19, 2025

May 29, 2024

Maturity date

March 19, 2025

May 29, 2024

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

~~CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED~~

~~(unaudited)~~

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

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(unaudited)

investments or pay dividends or distributions. We and SPL are restricted from making distributions under agreements governing our and SPL’s indebtedness generally until, among other requirements, deposits are made into any required debt service reserve accounts and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.

As of September 30, ~~2021,~~2022, we and SPL were in compliance with all covenants related to our respective debt agreements.

Interest Expense

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


		Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020				2022		2021		2022		2021
Total interest cost	Total interest cost	$	244	$	246	$	732	$	759		Total interest cost	$	231	$	244	$	678	$	732
Capitalized interest	Capitalized interest	(34)		(25)		(96)		(68)			Capitalized interest	(9)		(34)		(37)		(96)
Total interest expense, net of capitalized interest	Total interest expense, net of capitalized interest	$	210	$	221	$	636	$	691		Total interest expense, net of capitalized interest	$	222	$	210	$	641	$	636

Fair Value Disclosures

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


		September 30, 2021				December 31, 2020					September 30, 2022				December 31, 2021
		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value			Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Senior notes — Level 2 (1)	Senior notes — Level 2 (1)	$	17,478	$	19,231	$	16,950	$	19,113	Senior notes — Level 2 (1)	$	16,050	$	15,036	$	16,050	$	17,496
Senior notes — Level 3 (2)	Senior notes — Level 3 (2)	800		997		800		1,036		Senior notes — Level 3 (2)	1,282		1,119		1,282		1,466
Credit facilities — Level 3 (3)		—		—		—		—

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

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

~~(3)~~

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

NOTE 10—REVENUES ~~FROM CONTRACTS WITH CUSTOMERS~~

The following table represents a disaggregation of revenue earned ~~from contracts with customers during the three and nine months ended September 30, 2021 and 2020~~ (in millions):


		Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,						Nine Months Ended September 30,
		2021		2020		2021		2020				2022		2021			2022		2021
LNG revenues (1)		$	1,791	$	800	$	5,057	$	3,585
Revenues from contracts with customers											Revenues from contracts with customers
LNG revenues											LNG revenues	$	3,133	$	1,791		$	8,576	$	5,057
LNG revenues—affiliate	LNG revenues—affiliate	453		103		878		352			LNG revenues—affiliate	1,376		453			3,268		878
LNG revenues—related party											LNG revenues—related party	—		—			4		—
Regasification revenues	Regasification revenues	68		67		202		202			Regasification revenues	455		68			591		202
Other revenues	Other revenues	12		5		39		28			Other revenues	15		12			45		39

Total revenues from customers		2,324		975		6,176		4,167
Net derivative loss (2)		—		7		—		3
Total revenues from contracts with customers											Total revenues from contracts with customers	4,979		2,324			12,484		6,176
Net derivative gain (loss) (1)											Net derivative gain (loss) (1)	(3)		—			1		—
Total revenues	Total revenues	$	2,324	$	982	$	6,176	$	4,170		Total revenues	$	4,976	$	2,324		$	12,485	$	6,176

(1)~~LNG revenues include revenues~~See Note 7—Derivative Instruments for ~~LNG cargoes in which~~additional information about our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the three and nine months ended September 30, 2020, we recognized $109 million and $513 million, respectively, in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $21 million would havederivatives.

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(unaudited)

been recognized subsequent to September 30, 2020 had the cargoes been lifted pursuant to the delivery schedules with the customers. LNG revenues during the three months ended September 30, 2020 excluded $244 million that would have otherwise been recognized during the period if the cargoes were lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the threeContract Assets and nine months ended September 30, 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied.

~~(2)See~~ ~~Note 7—Derivative Instruments~~ ~~for additional information about our derivatives.~~

~~Contract Assets~~Liabilities

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

September 30, December 31,
2021 2020
Contract assets, net of current expected credit losses $ 1 $ —

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the nine months ended September 30, 2021 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

~~Deferred Revenue Reconciliation~~



	September 30,		December 31,
	2022		2021
Contract assets, net of current expected credit losses	$	388	$	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, ~~2021~~2022

Deferred revenue, beginning of period	$	~~137~~155
Cash received but not yet recognized in revenue	~~166~~162
Revenue recognized from prior period deferral	~~(137)~~(155)
Deferred revenue, end of period	$	~~166~~162

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, ~~2021~~2022

Deferred revenue—affiliate, beginning of period	$	13
Cash received but not yet recognized in revenue	46
Revenue recognized from prior ~~period~~year end deferral	~~(1)~~(3)
Deferred revenue—affiliate, end of period	$	46

~~CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED~~

~~(unaudited)~~

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been ~~satisfied as of September 30, 2021 and December 31, 2020:~~satisfied:


		September 30, 2021			December 31, 2020				September 30, 2022			December 31, 2021
		Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)		Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues	LNG revenues	$	50.1	9	$	52.1	9	LNG revenues	$	51.6	8	$	49.3	9
LNG revenues—affiliate	LNG revenues—affiliate	0.7		3	0.1		1	LNG revenues—affiliate	2.0		2	2.1		3
Regasification revenues	Regasification revenues	1.9		4	2.1		5	Regasification revenues	1.6		2	1.9		4
Total revenues	Total revenues	$	52.7		$	54.3		Total revenues	$	55.2		$	53.3

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

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

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

(2)The table above excludes substantially all variable consideration under our SPAs and TUAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Approximately ~~63%~~78% and ~~39%~~63% of our LNG revenues from contracts included in the table above during the three

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(unaudited)

months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and approximately ~~56%~~74% and ~~37%~~56% of our LNG revenues from contracts included in the table above during the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively, were related to variable consideration received from customers. Approximately 77% and 96% of our LNG revenues—affiliate from contracts included in the table above during the three months ended September 30, 2022 and 2021, respectively, and approximately 76% and 94% of our LNG revenues—affiliate from contracts included in the table above during the ~~three and~~ nine months ended September 30, 2022 and 2021, respectively, ~~and 100% of our LNG revenues—affiliate~~were related to variable consideration received from ~~contracts included in the table above during each of~~customers. During the three and nine months ended September 30, ~~2020~~2022, approximately 1% and 2%, respectively, of our regasification revenues were related to variable consideration received from ~~customers. During~~customers, and during each of the three and nine months ended September 30, 2021, approximately 5% of our regasification revenues were related to variable consideration received from ~~customers, respectively, and during each of the three and nine months ended September 30, 2020, approximately 6% of our regasification revenues were related to variable consideration received from~~ customers.

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

Termination Agreement with Chevron

In June 2022, Chevron U.S.A. Inc. (“Chevron”) entered into an agreement with SPLNG providing for the early termination of the TUA and an associated terminal marine services agreement between the parties and their affiliates 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, will terminate upon the later of SPLNG’s receipt of the Termination Fee or December 31, 2022. The termination agreement became effective on July 6, 2022. We have allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which we are recognizing ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations, and an offsetting $31 million in cash outflows allocable to the extinguishment of other remaining obligations we have to Chevron, which will be recognized upon receipt of the Termination Fee as a loss on extinguishment of debt on our Consolidated Statements of Operations. As of September 30, 2022, we recorded contract assets of $387 million related to the termination of the TUA.

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(unaudited)

NOTE 11—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations ~~during the three and nine months ended September 30, 2021 and 2020~~ (in millions):


		Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020				2022		2021		2022		2021
LNG revenues—affiliate	LNG revenues—affiliate										LNG revenues—affiliate
Cheniere Marketing Agreements	Cheniere Marketing Agreements	$	441	$	87	$	860	$	328		Cheniere Marketing Agreements	$	1,328	$	441	$	3,173	$	860
Contracts for Sale and Purchase of Natural Gas and LNG	Contracts for Sale and Purchase of Natural Gas and LNG	12		16		18		24			Contracts for Sale and Purchase of Natural Gas and LNG	48		12		95		18
Total LNG revenues—affiliate	Total LNG revenues—affiliate	453		103		878		352			Total LNG revenues—affiliate	1,376		453		3,268		878

LNG revenues—related party											LNG revenues—related party
Natural Gas Transportation and Storage Agreements											Natural Gas Transportation and Storage Agreements	—		—		4		—

Cost of sales—affiliate	Cost of sales—affiliate										Cost of sales—affiliate
Cheniere Marketing Agreements	Cheniere Marketing Agreements	—		32		34		32			Cheniere Marketing Agreements	—		—		—		34
Contracts for Sale and Purchase of Natural Gas and LNG	Contracts for Sale and Purchase of Natural Gas and LNG	8		1		28		6			Contracts for Sale and Purchase of Natural Gas and LNG	104		8		166		28
Total cost of sales—affiliate	Total cost of sales—affiliate	8		33		62		38			Total cost of sales—affiliate	104		8		166		62

Cost of sales—related party	Cost of sales—related party										Cost of sales—related party
Natural Gas Transportation and Storage Agreements	Natural Gas Transportation and Storage Agreements	—		—		1		—			Natural Gas Transportation and Storage Agreements	—		—		1		1

Operating and maintenance expense—affiliate	Operating and maintenance expense—affiliate										Operating and maintenance expense—affiliate

Services Agreements	Services Agreements	34		34		103		115			Services Agreements	39		34		118		103

Operating and maintenance expense—related party	Operating and maintenance expense—related party										Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements	Natural Gas Transportation and Storage Agreements	12		—		34		—			Natural Gas Transportation and Storage Agreements	18		12		45		34

General and administrative expense—affiliate	General and administrative expense—affiliate										General and administrative expense—affiliate
Services Agreements	Services Agreements	22		24		64		73			Services Agreements	23		22		70		64

As of September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we had ~~$198~~$447 million and ~~$184~~$232 million, respectively, of accounts receivable—affiliate under the agreements described below.

Cheniere Marketing Agreements

Cheniere Marketing SPA

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

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

Cheniere Marketing Master SPA

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

Cheniere Marketing ~~that obligated~~Letter Agreements

In May 2022, SPL and Cheniere Marketing ~~in certain circumstances~~entered into a letter agreement for the sale of up to ~~buy~~32 TBtu of LNG ~~cargoes produced during the period while Bechtel Oil, Gas~~to be delivered between 2023 and ~~Chemicals, Inc. (“Bechtel”) had control~~2025 at a price of ~~and was commissioning, Train 5~~115% of ~~the Liquefaction Project.~~Henry Hub plus $3.00 per MMBtu.

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

~~In August 2021,~~ SPL and Cheniere Marketing entered into a letter agreement (amending and restating the previous letter agreement between the parties from February 2021) for the sale of up to 81 cargoes to be delivered between 2021 and 2027 at a price equal to 115% of Henry Hub plus $1.96 per MMBtu. Additionally, SPL and Cheniere Marketing entered into a letter agreement for the sale of (1) up to 6 cargoes to be delivered in 2022 and up to 6 cargoes to be delivered in 2023 at a price equal to 115% of Henry Hub plus $1.768 per MMBtu; and (2) up to 6 cargoes to be delivered in 2022 at a price equal to 115% of Henry Hub plus $1.952 per MMBtu.

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

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

Facility Swap Agreement

~~In August 2020,~~ SPL ~~entered into~~has an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be ~~(i)~~(1) 115% of the applicable natural gas feedstock purchase price or ~~(ii)~~(2) a free-on-board U.S. Gulf Coast LNG market price, whichever is greater.

Natural Gas Transportation and Storage Agreements

SPL is party to various natural gas transportation and storage agreements and CTPL is party to an operational balancing agreement with a related party in the ordinary course of business for the operation of the Liquefaction Project, with initial primary terms of up to 10 years with extension rights. This related party is partially owned by Brookfield, who indirectly acquired a portion of our limited partner interests in September 2020 through its purchase of a portion of CQP Target Holdco’s equity interests. We recorded operating and maintenance expense—related party of $12 million and $34 million and cost of sales—related party of zero and $1 million during the three and nine months ended September 30, 2021, respectively, and accrued liabilities—related party of $5$8 million and $4 million as of September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively, with this related party.

Services Agreements

As of September 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we had ~~$130~~$150 million and ~~$144~~$141 million of advances to affiliates, respectively, under the services agreements described below. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.

~~Cheniere Partners~~CQP Services Agreement

We have a services agreement with Cheniere Terminals ~~a subsidiary of Cheniere,~~ pursuant to which Cheniere Terminals is entitled to a quarterly non-accountable overhead reimbursement charge of $3 million (adjusted for inflation) for the provision of various general and administrative services for our ~~benefit.~~benefit through 2042. In addition, Cheniere Terminals is entitled to reimbursement for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Cheniere Investments Information Technology Services Agreement

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

~~CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED~~

~~(unaudited)~~

SPLNG O&M Agreement

SPLNG has a long-term operation and maintenance agreement (the “SPLNG O&M Agreement”) with Cheniere Investments pursuant to which SPLNG receives all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. SPLNG pays a fixed monthly fee of $130,000 (indexed for inflation) under the SPLNG O&M Agreement and the cost of a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between SPLNG and Cheniere Investments at the beginning of each operating ~~year.~~year through 2029. In addition, SPLNG is required to reimburse Cheniere Investments for its operating expenses, which consist primarily of labor expenses. Cheniere Investments provides the services required under the SPLNG O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPLNG O&M Agreement are required to be remitted to such subsidiary.

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SPLNG MSA

SPLNG has a long-term management services agreement (the “SPLNG MSA”) with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters provided for under the SPLNG O&M Agreement. SPLNG pays a monthly fixed fee of $520,000 (indexed for inflation) through 2029 under the SPLNG MSA.

SPL O&M Agreement

SPL has an operation and maintenance agreement (the “SPL O&M Agreement”) with Cheniere Investments pursuant to which SPL receives all ~~of the~~ necessary services required to ~~construct,~~ operate and maintain the Liquefaction Project. ~~Before~~After each Train of the Liquefaction Project is operational, the services to be provided include, among other services, obtaining governmental approvals on behalf of SPL, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After each Train is operational, the services include all necessary services required to operate and maintain the Train. Prior to the substantial completion of each Train of the Liquefaction Project, in addition to reimbursement of operating expenses, SPL is required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the Train is operational, SPL ~~will~~is required to pay, in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to the ~~Train.~~Train through 2042. Cheniere Investments provides the services required under the SPL O&M Agreement pursuant to a secondment agreement with a wholly owned subsidiary of Cheniere. All payments received by Cheniere Investments under the SPL O&M Agreement are required to be remitted to such subsidiary.

SPL MSA

SPL has a management services agreement (the “SPL MSA”) with Cheniere Terminals pursuant to which Cheniere Terminals manages the ~~construction and~~ operation of the Liquefaction Project, excluding those matters provided for under the SPL O&M Agreement. The services include, among other services, exercising the day-to-day management of SPL’s affairs and business, managing SPL’s regulatory matters, managing bank and brokerage accounts and financial books and records of SPL’s business and operations, entering into financial derivatives on SPL’s behalf and providing contract administration services for all contracts associated with the Liquefaction Project. Prior to the substantial completion of each Train of the Liquefaction Project, SPL ~~pays~~is required to pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, SPL ~~will~~is required to pay a fixed monthly fee of $541,667 (indexed for inflation) for services with respect to such ~~Train.~~Train through 2042.

CTPL O&M Agreement

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

~~CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED~~

~~(unaudited)~~

CTPL MSA

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

~~Natural Gas Supply Agreement~~

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

Agreement to Fund SPLNG’s Cooperative Endeavor Agreements

SPLNG has executed Cooperative Endeavor Agreements (“CEAs”) with various Cameron Parish, Louisiana taxing authorities that allowed them to collect certain advanced payments of annual ad valorem taxes from SPLNG from 2007 through

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

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

On a consolidated basis, these advance tax payments were recorded to other non-current assets, and payments from Cheniere Marketing that SPLNG utilized to make the ad valorem tax payments were recorded as obligations. We had $3 million and $2 million in due to affiliates as of ~~both~~ September 30, ~~2021~~2022 and December 31, ~~2020~~2021, respectively, and $15 ~~million and $17~~ million of other non-current liabilities—affiliate as of both September 30, ~~2021~~2022 and December 31, ~~2020, respectively,~~2021, from these payments received from Cheniere Marketing.

Contracts for Sale and Purchase of Natural Gas and LNG

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

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

Terminal Marine Services Agreement

In connection with its tug boat lease, Tug Services entered into an agreement with Cheniere Terminals to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG ~~terminal.~~Terminal. The agreement also provides that Tug Services shall contingently pay Cheniere Terminals a portion of its future revenues. ~~Accordingly,~~ Tug Services distributed $2 million ~~and $1 million~~ during each of the three months ended September 30, 2022 and 2021 and ~~2020, respectively,~~$7 million and $6 ~~million and~~

~~CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED~~

~~(unaudited)~~

$4 million during the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively, to Cheniere Terminals, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ ~~Equity.~~Equity (Deficit).

LNG Terminal Export Agreement

SPLNG and Cheniere Marketing have an LNG terminal export agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG ~~terminal.~~Terminal. SPLNG did not record any revenues associated with this agreement during the three and nine months ended September 30, ~~2021~~2022 and ~~2020.~~2021.

State Tax Sharing Agreements

SPLNG, ~~has~~SPL and CTPL each have a state tax sharing agreement with Cheniere. Under ~~this agreement,~~these agreements, Cheniere has agreed to prepare and file all state and local tax returns which ~~SPLNG~~each of the entities and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, ~~SPLNG~~each of the respective entities will pay to Cheniere an amount equal to the state and local tax that ~~SPLNG~~each of the entities would be required to pay if its state and local tax liability were calculated on a separate company basis. ~~There~~To date, there have been no state and local ~~taxes paid~~tax payments demanded by Cheniere ~~and Cheniere has not demanded any such payments from SPLNG~~ under the ~~agreement.~~tax sharing agreements. The ~~agreement is~~agreements for SPLNG, SPL and CTPL are effective for tax returns due on or after January ~~1, 2008.~~2008, August 2012 and May 2013, respectively.

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

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

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

(unaudited)

NOTE 12—NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit for a given period is based on the distributions that will be made to the common unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions paid by us are presented on the Consolidated Statements of Partners’ ~~Equity.~~Equity (Deficit). On October ~~26, 2021,~~24, 2022, we declared a ~~$0.680~~cash distribution of $1.070 per common unit ~~and the related distribution to our general partner and IDR holders that will be paid on November 12, 2021~~ to unitholders of record as of November ~~5, 2021 for~~3, 2022 and the ~~period from July 1, 2021~~related general partner distribution to ~~September 30, 2021.~~be paid on November 14, 2022. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.295 per unit.

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

2221

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

The following table provides a reconciliation of net income (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).


				Limited Partner Units
													Total		Limited Partner Common Units		General Partner Units		IDR
Three Months Ended September 30, 2022												Three Months Ended September 30, 2022
Net loss												Net loss	$	(514)
Declared distributions												Declared distributions	753		518		15		220
Assumed allocation of undistributed net loss (1)												Assumed allocation of undistributed net loss (1)	$	(1,267)	(1,242)		(25)		—
Assumed allocation of net loss												Assumed allocation of net loss			$	(724)	$	(10)	$	220

Weighted average units outstanding												Weighted average units outstanding			484.0
Basic and diluted net loss per unit (2)												Basic and diluted net loss per unit (2)			$	(1.49)
		Total		Common Units		Subordinated Units		General Partner Units		IDR
Three Months Ended September 30, 2021	Three Months Ended September 30, 2021											Three Months Ended September 30, 2021
Net income	Net income	$	381									Net income	$	381
Declared distributions	Declared distributions	375		329		—		8		38		Declared distributions	375		329		8		38
Assumed allocation of undistributed net income (1)	Assumed allocation of undistributed net income (1)	$	6	6		—		—		—		Assumed allocation of undistributed net income (1)	$	6	6		—		—
Assumed allocation of net income	Assumed allocation of net income			$	335	$	—	$	8	$	38	Assumed allocation of net income			$	335	$	8	$	38

Weighted average units outstanding	Weighted average units outstanding			484.0		—						Weighted average units outstanding			484.0
Basic and diluted net income per unit	Basic and diluted net income per unit			$	0.69	$	—					Basic and diluted net income per unit			$	0.69

Three Months Ended September 30, 2020
Nine Months Ended September 30, 2022												Nine Months Ended September 30, 2022
Net loss	Net loss	$	(67)									Net loss	$	(13)
Declared distributions	Declared distributions	346		315		—		6		25		Declared distributions	2,229		1,539		45		645
Assumed allocation of undistributed net loss (1)	Assumed allocation of undistributed net loss (1)	$	(413)	(347)		(58)		(8)		—		Assumed allocation of undistributed net loss (1)	$	(2,242)	(2,197)		(45)		—
Assumed allocation of net loss	Assumed allocation of net loss			$	(32)	$	(58)	$	(2)	$	25	Assumed allocation of net loss			$	(658)	$	—	$	645

Weighted average units outstanding	Weighted average units outstanding			414.8		69.2						Weighted average units outstanding			484.0
Basic and diluted net loss per unit	Basic and diluted net loss per unit			$	(0.08)	$	(0.84)					Basic and diluted net loss per unit			$	(1.36)

Nine Months Ended September 30, 2021	Nine Months Ended September 30, 2021											Nine Months Ended September 30, 2021
Net income	Net income	$	1,123									Net income	$	1,123
Declared distributions	Declared distributions	1,091		970		—		22		99		Declared distributions	1,091		970		22		99

Assumed allocation of undistributed net income (1)	Assumed allocation of undistributed net income (1)	$	32	31		—		1		—		Assumed allocation of undistributed net income (1)	$	32	31		1		—
Assumed allocation of net income				$	1,001	$	—	$	23	$	99

Weighted average units outstanding				484.0		—
Basic and diluted net income per unit				$	2.07	$	—

Nine Months Ended September 30, 2020
Net income		$	774
Declared distributions		1,024		763		174		20		67

Assumed allocation of undistributed net loss (1)		$	(250)	(188)		(57)		(5)		—
Assumed allocation of net income	Assumed allocation of net income			$	575	$	117	$	15	$	67	Assumed allocation of net income			$	1,001	$	23	$	99

Weighted average units outstanding	Weighted average units outstanding			370.9		113.1						Weighted average units outstanding			484.0
Basic and diluted net income per unit	Basic and diluted net income per unit			$	1.55	$	1.03					Basic and diluted net income per unit			$	2.07

(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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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

(unaudited)

NOTE 13—CUSTOMER CONCENTRATION

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


		Percentage of Total Revenues from External Customers				Percentage of Accounts Receivable, Net and Contract Assets, Net from External Customers			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,		Three Months Ended September 30,			Nine Months Ended September 30,		September 30,	December 31,
		2021	2020	2021	2020		2021	2020			2022	2021	2022	2021		2022	2021
Customer A	Customer A	20%	*	24%	22%		26%	31%		Customer A	18%	20%	23%	24%		17%	28%
Customer B	Customer B	17%	14%	16%	15%		18%	21%		Customer B	16%	19%	16%	17%		*	17%
Customer C	Customer C	18%	26%	18%	18%		17%	*		Customer C	14%	18%	16%	18%		*	*
Customer D	Customer D	19%	22%	17%	18%		17%	22%		Customer D	16%	17%	16%	16%		13%	14%
Customer E	Customer E	11%	*	11%	12%		*	*		Customer E	*	11%	*	11%		*	12%

Customer F										Customer F	10%	*	*	*		*	12%
Customer G										Customer G	12%	*	*	*		32%	—

* 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,
2021 2020
Cash paid during the period for interest on debt, net of amounts capitalized $ 601 $ 636


	Nine Months Ended September 30,
	2022		2021
Cash paid during the period for interest on debt, net of amounts capitalized	$	585	$	601

The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $314 million and $233 million as of ~~both~~ September 30, 2022 and 2021, respectively.

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

In March 2022, in connection with a prior commitment from Cheniere to collateralize financing for Train 6 of the Liquefaction Project, SPL and ~~2020, respectively.~~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 has been accounted for as a transfer between entities under common control, which required us to recognize the obligations assumed at the historical basis of Cheniere. Upon the transfer, which occurred on March 15, 2022, we recognized $2.7 billion in distributions to Cheniere’s common unitholder interest within our Consolidated Statements of Partners’ Equity (Deficit) based on our assumption of current derivative liabilities and derivative liabilities of $142 million and $2.6 billion, respectively, which represented a non-cash financing activity.

2423

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

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

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

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

•statements that we expect to commence or complete construction of our proposed LNG ~~terminals,~~terminal, liquefaction ~~facilities,~~facility, pipeline ~~facilities~~facility or other projects, or any expansions or portions thereof, by certain dates, or at all;

•statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;

•statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;

•statements regarding our future sources of liquidity and cash requirements;

•statements relating to the construction of our Trains, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;

•statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;

•statements regarding counterparties to our commercial contracts, construction contracts and other contracts;

•statements regarding our planned development and construction of additional Trains, including the financing of such Trains;

•statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;

•statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;

•statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;

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

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

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve

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

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from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the fiscal year ended December 31, ~~2020~~2021. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future.

Our discussion and analysis includes the following subjects:

•Overview ~~of Business~~

•Overview of Significant Events

•Results of Operations

•Liquidity and Capital Resources

•~~Off-Balance Sheet Arrangements~~

•Summary of Critical Accounting Estimates

•Recent Accounting Standards

Overview ~~of Business~~

We are a publicly traded Delaware limited partnership formed in 2006 by ~~Cheniere in 2006.~~Cheniere. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.

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

~~The~~

We own the natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG ~~terminal,~~Terminal”), one of the largest LNG production facilities in the world, ~~is located in Cameron Parish, Louisiana, and~~which has ~~natural gas liquefaction facilities consisting of five~~six operational ~~natural gas liquefaction~~ Trains, ~~and one additional~~with Train ~~that is undergoing commissioning and expected to be substantially completed in the first quarter of~~6 having achieved substantial completion on February 4, 2022, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG ~~terminal~~Terminal also has operational regasification facilities that include five LNG storage tanks with aggregate capacity of approximately 17 Bcfe, ~~two existing~~three marine berths, ~~and one under construction that~~with the third berth having achieved substantial completion on October 27, 2022, two of which can ~~each~~ 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, and vaporizers with total regasification capacity of approximately 4 Bcf/d. We also own a 94-mile pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG ~~terminal~~Terminal with a number of large interstate and intrastate pipelines.

Our customer arrangements provide us with significant, stable and long-term cash flows. We contract our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which the gas producer sells natural gas to us on a global LNG index price, less a fixed liquefaction fee, shipping and other costs. Our

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long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Through our SPAs and IPM agreements, we have contracted approximately 85% of the total production capacity from the Liquefaction Project with approximately 15 years of weighted average remaining life as of September 30, 2022. In March 2022, the DOE authorized the export of an additional 152.64 Bcf/yr of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December 31, 2050 to non-FTA countries, that were previously authorized for FTA countries only. For further discussion of the contracted future cash flows under our revenue arrangements, see the liquidity and capital resources disclosures in our annual report on Form 10-K for the fiscal year ended December 31, 2021.

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

Additionally, we are committed to the responsible and proactive management of our most important environmental, social and governance (“ESG”) impacts, risks and opportunities. In June 2022, Cheniere published its ~~2020~~2021 Corporate Responsibility (“CR”) report, which details our ~~strategy~~approach and progress on ESG issues, including Cheniere’s collaboration with natural gas midstream companies, methane detection technology providers and leading academic institutions to implement quantification, monitoring, reporting and verification of greenhouse gas (“GHG”) emissions at natural gas gathering, processing, transmission and storage systems specific to our supply chain, as well as our ~~efforts on integrating climate considerations into our business strategy and taking~~contributions to energy security during a ~~leadership position on increased environmental transparency, including conducting a climate scenario analysis and our plan~~critical time in history. Additionally, Cheniere commenced providing Cargo Emissions Tags (“CE Tags”) to its long-term customers in June 2022. The CE Tags provide ~~LNG~~ customers with ~~Cargo Emission Tags. In August 2021,~~estimated GHG emissions data associated with each LNG cargo produced at the Liquefaction Project and are provided for both free-on-board (“FOB”) and delivered ex-ship (“DES”) LNG cargoes. Cheniere also ~~announced~~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 in October 2022. OGMP 2.0 is a ~~peer-reviewed LNG life cycle assessment study which allows for improved greenhouse gas~~comprehensive, measurement-based reporting framework intended to improve the accuracy and transparency of methane emissions ~~assessment, which was published~~reporting in the ~~American Chemical Society Sustainable Chemistry & Engineering Journal~~.oil and gas sector. Cheniere’s CR report is available at cheniere.com/~~IMPACT.~~our-responsibility/reporting-center. Information on our website, including the CR report, is not incorporated by reference into this Quarterly Report on Form 10-Q.

Overview of Significant Events

Our significant events since January 1, ~~2021~~2022 and through the filing date of this Form 10-Q include the following:

Strategic

•On September 23, 2022, Corey Grindal, Executive Vice President, Worldwide Trading and Tim Wyatt, Senior Vice President, Corporate Development and Strategy, were appointed to the Board of Directors of Cheniere Energy Partners GP, LLC (“Cheniere GP”). Mr. Grindal was also appointed as Executive Vice President and Chief Operating Officer of Cheniere GP, effective January 2, 2023.

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

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

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

◦Our board of directors approved the entry by SPL into (1) an agreement to novate to SPL an IPM agreement between Corpus Christi Liquefaction Stage III, LLC (“CCL Stage III”), formerly a wholly owned direct subsidiary of Cheniere (as purchaser) that merged with and into Corpus Christi Liquefaction, LLC, and Tourmaline Oil Marketing Corp., a subsidiary of Tourmaline Oil Corp (as supplier), to purchase 140,000 MMBtu per day of natural gas at a price based on Platts Japan Korea Marker (“JKM”), for a term of

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approximately 15 years beginning in early 2023 (the “Tourmaline IPM”) and (2) a FOB SPA with Cheniere Marketing International LLP to sell LNG associated with the natural gas to be supplied under the IPM agreement. The agreement to assign the Tourmaline IPM agreement from CCL Stage III to SPL was executed and the assignment was effective on March 15, 2022.

Operational

•As of October 31, ~~2021, over 1,430~~2022, approximately 1,850 cumulative LNG cargoes totaling ~~approximately 110~~over 125 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.

•~~In September 2021, feed gas~~On October 27, 2022, substantial completion of the third berth at the Sabine Pass LNG Terminal was ~~introduced to~~achieved.

•On February 4, 2022, substantial completion of Train 6 of the Liquefaction ~~Project.~~Project was achieved (the “Train 6 Completion”).

Financial

•~~We completed the following financing transactions:~~

◦In September 2021, we issued an aggregate principal amount of $1.2 billion of 3.52% Senior Notes due 2032 (the “2032 CQP Senior Notes”). Net proceeds of the 2032 CQP Senior Notes were used to redeem a portion of the outstanding $1.1 billion aggregate principal amount of the 5.625% Senior Notes due 2026 (the “2026 CQP Senior Notes”) in September 2021 pursuant to a tender offer and consent solicitation. In October 2021, the remaining net proceeds of the 2032 CQP Senior Notes were used to redeem the remaining outstanding principal amount of the 2026 CQP Senior Notes and, together with cash on hand, redeem $318 million of the 6.25% Senior Secured Notes due 2022 (the “2022 SPL Senior Notes”).

◦During 2021, SPL entered into a series of note purchase agreements for the sale of approximately $482 million aggregate principal amount of Senior Secured Notes due 2037, on a private placement basis (the “2037 SPL Private Placement Senior Secured Notes”). The 2037 SPL Private Placement Senior Secured Notes are expected to be issued in the fourth quarter of 2021, subject to customary closing conditions, and the net proceeds will be used to redeem a portion of the 2022 SPL Senior Notes and pay related fees, costs and expenses. The 2037 SPL Private Placement Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years and a weighted average interest rate of 3.07%.

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

•In ~~April 2021, S&P Global~~October 2022, SPL redeemed $300 million of outstanding borrowings under its 5.625% Senior Secured Notes due 2023 (the “2023 SPL Senior Notes”) pursuant to a notice of redemption issued in September 2022.

•In September 2022, Moody’s Corporation upgraded its issuer credit ratings of CQP and SPL from Ba2 and Baa3, respectively, to Ba1 and Baa2, respectively, with a stable outlook. Additionally in September 2022, Fitch Ratings ~~changed~~upgraded its issuer credit ratings of CQP and SPL from BB+ and BBB-, respectively, to BBB- and BBB, respectively, with a stable outlook.

•We paid aggregate distributions of $2.81 per common unit during the ~~outlook~~nine months ended September 30, 2022. On October 24, 2022, we declared a cash distribution of $1.070 per common unit to unitholders of record as of November 3, 2022 and the related general partner distribution to be paid on ~~our ratings to positive from negative.~~November 14, 2022. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.295 per unit.

•In February ~~2021, Fitch Ratings (“Fitch”) changed~~2022, we announced the ~~outlook~~initiation of ~~SPL’s senior secured notes rating~~quarterly distributions to ~~positive from stable~~be comprised of a base amount plus a variable amount, which began with the distribution related to the first quarter of 2022. The variable amount takes into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash and cash reserves to provide for the ~~outlook~~proper conduct of ~~our long-term issuer default rating and senior unsecured notes rating to positive from stable.~~the business.

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Results of Operations

The following charts summarize the total revenues and total LNG volumes loaded from our Liquefaction Project ~~(including both operational and commissioning volumes)~~ during the nine months ended September 30, ~~2021~~2022 and ~~2020:~~2021:

(1)

The nine months ended September 30, 2021 excludes eight TBtu under our contracts that were loaded at our affiliate’s facility.

Net income (loss)


		Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,				Nine Months Ended September 30,
(in millions, except per share data)	(in millions, except per share data)	2021		2020		Change		2021		2020		Change			(in millions, except per share data)	2022		2021		Variance		2022		2021		Variance
Net income (loss)	Net income (loss)	$	381	$	(67)	$	448	$	1,123	$	774	$	349		Net income (loss)	$	(514)	$	381	$	(895)	$	(13)	$	1,123	$	(1,136)
Basic and diluted net income (loss) per common unit	Basic and diluted net income (loss) per common unit	0.69		(0.08)		0.77		2.07		1.55		0.52			Basic and diluted net income (loss) per common unit	(1.49)		0.69		(2.18)		(1.36)		2.07		(3.43)

~~Net income increased by $448~~The unfavorable variances of $895 million and ~~$349 million~~$1.1 billion during the three and nine months ended September 30, ~~2021~~2022 from the comparable periods in ~~2020,~~2021, respectively, were primarily a result of losses of $1.3 billion and $2.2 billion, respectively, on the derivative liability associated with the Tourmaline IPM agreement following its assignment to SPL from CCL Stage III in March 2022. See Overview of Significant Events for further discussion of the assignment. The associated losses following the assignment were primarily attributed to SPL’s lower credit risk profile relative to that of CCL Stage III, resulting in a higher derivative liability given reduced risk of SPL’s own nonperformance, and unfavorable shifts in the international forward commodity curve. Partially offsetting the unfavorable variances in both comparable periods was increased gross margin per MMBtu on LNG delivered, due to higher margins on sales indexed to Henry Hub plus a mark up, generally at 115%, as a result of increases in the index, and increased ~~margins attributable~~volumes delivered, in part due to the Train 6 Completion. Additionally offsetting the unfavorable variances in both comparable periods was the recognition of increased ~~volume of LNG delivered between the periods and decreased losses~~regasification revenues from ~~commodity derivatives to secure natural gas feedstock for the Liquefaction Project.~~Chevron, as further described below.

~~We enter into derivative~~Derivative instruments are utilized to manage our exposure to commodity-related marketing and price ~~risk. Derivative instruments~~risks and are reported at fair value on our Consolidated Financial Statements. ~~In some cases,~~For commodity derivative instruments related to our IPM agreement novated to SPL during the nine months ended September 30, 2022 as further described in Overview of Significant Events, the underlying ~~transactions~~LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues ~~and expenses~~expected to be derived from the future LNG sales are recognized only upon delivery ~~receipt~~ or realization of the underlying transaction. Because the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors, notwithstanding the operational intent to mitigate risk exposure over time.

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In June 2022, 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 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, will terminate upon the later of SPLNG’s receipt of the Termination Fee or December 31, 2022. The termination agreement became effective on July 6, 2022. We have allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which we are recognizing ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations, and an offsetting $31 million in cash outflows allocable to the extinguishment of other remaining obligations we have to Chevron, which will be recognized upon receipt of the Termination Fee as a loss on extinguishment of debt on our Consolidated Statements of Operations.

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

Revenues


		Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,				Nine Months Ended September 30,
(in millions, except volumes)	(in millions, except volumes)	2021		2020		Change		2021		2020		Change			(in millions, except volumes)	2022		2021		Variance		2022		2021		Variance
LNG revenues	LNG revenues	$	1,791	$	807	$	984	$	5,057	$	3,588	$	1,469		LNG revenues	$	3,130	$	1,791	$	1,339	$	8,577	$	5,057	$	3,520
LNG revenues—affiliate	LNG revenues—affiliate	453		103		350		878		352		526			LNG revenues—affiliate	1,376		453		923		3,268		878		2,390

LNG revenues—related party															LNG revenues—related party	—		—		—		4		—		4
Regasification revenues	Regasification revenues	68		67		1		202		202		—			Regasification revenues	455		68		387		591		202		389

Other revenues	Other revenues	12		5		7		39		28		11			Other revenues	15		12		3		45		39		6

Total revenues	Total revenues	$	2,324	$	982	$	1,342	$	6,176	$	4,170	$	2,006		Total revenues	$	4,976	$	2,324	$	2,652	$	12,485	$	6,176	$	6,309

LNG volumes recognized as revenues (in TBtu) (1)	LNG volumes recognized as revenues (in TBtu) (1)	308		132		176		946		666		280			LNG volumes recognized as revenues (in TBtu) (1)	363		308		55		1,110		946		164

(1)~~Excludes volume associated with cargoes for which customers notified us that they would not take delivery. During the~~The nine months ended September 30, 2021 includes eight TBtu that were loaded at our affiliate’s facility.

Total revenues increased by approximately ~~$1.3~~$2.7 billion and ~~$2.0~~$6.3 billion during the three and nine months ended September 30, ~~2021, respectively,~~2022 from the comparable periods in ~~2020,~~2021, respectively, primarily as a result of increased pricing due to appreciation in the Henry Hub index. To a lesser extent, revenues increased as a result of higher volumes of LNG delivered between the periods due to the ~~delivery~~addition of ~~all available volume~~approximately 5 mtpa of production capacity following the Train 6 Completion.

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes from that Train are offset against LNG ~~in 2021 and increased revenues per MMBtu~~terminal construction-in-process, because these amounts are earned or loaded during the ~~three and~~testing phase for the construction of that Train. During the nine months ended September 30, ~~2021. During the three and nine months ended September 30, 2020,~~2022, we ~~recognized $109~~realized offsets to LNG terminal costs of $148 million, ~~and $513 million, respectively, in LNG revenues associated with LNG cargoes for which customers notified us~~corresponding to 13 TBtu, that ~~they would not take delivery, of which $21 million would have been recognized subsequent to September 30, 2020 had the cargoes been lifted pursuant~~were related to the ~~delivery schedules with~~sale of commissioning cargoes from Train 6 of the ~~customers.~~Liquefaction Project. We did not realize any offsets to LNG ~~revenues~~terminal costs during the three months ended September 30, 2020 excluded $244 million that would have otherwise been recognized during the quarter if the cargoes were lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during2022 or the three and nine months ended September 30, 2021.

Also included in LNG revenues are sales of certain unutilized natural gas procured for the liquefaction process and gains and losses from derivative instruments, which include the realized value associated with a portion of derivative instruments that settle through physical delivery. We recognized revenues of ~~$52~~$40 million and ~~$130~~$52 million during the three months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~$112~~$161 million and ~~$211~~$112 million during the nine months ended September 30, ~~2021~~2022 and ~~2020,~~2021, respectively, related to these transactions.

~~Operating costs~~Regasification revenues increased by $387 million and ~~expenses~~

Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2021 2020 Change 2021 2020 Change
Cost of sales $ 1,342 $ 454 $ 888 $ 3,178 $ 1,551 $ 1,627
Cost of sales—affiliate 8 33 (25) 62 38 24
Cost of sales—related party — — — 1 — 1
Operating and maintenance expense 148 146 2 465 463 2
Operating and maintenance expense—affiliate 34 34 — 103 115 (12)
Operating and maintenance expense—related party 12 — 12 34 — 34
Development expense — — — 1 — 1
General and administrative expense 2 2 — 7 12 (5)
General and administrative expense—affiliate 22 24 (2) 64 73 (9)
Depreciation and amortization expense 140 137 3 417 413 4
Impairment expense and loss on disposal of assets — — — 6 5 1
Total operating costs and expenses $ 1,708 $ 830 $ 878 $ 4,338 $ 2,670 $ 1,668

~~Total operating costs and expenses increased~~$389 million during the three and nine months ended September 30, 2022 from the comparable periods in 2021, respectively, due primarily to the recognition of increased regasification revenues from Chevron, as described in Net income (loss) above.

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Operating costs and expenses


	Three Months Ended September 30,						Nine Months Ended September 30,
(in millions)	2022		2021		Variance		2022		2021		Variance
Cost of sales	$	4,739	$	1,342	$	3,397	$	10,445	$	3,178	$	7,267
Cost of sales—affiliate	104		8		96		166		62		104
Cost of sales—related party	—		—		—		1		1		—
Operating and maintenance expense	189		148		41		550		465		85
Operating and maintenance expense—affiliate	39		34		5		118		103		15
Operating and maintenance expense—related party	18		12		6		45		34		11


General and administrative expense	3		2		1		3		7		(4)
General and administrative expense—affiliate	23		22		1		70		64		6
Depreciation and amortization expense	160		140		20		469		417		52
Other	—		—		—		—		7		(7)

Total operating costs and expenses	$	5,275	$	1,708	$	3,567	$	11,867	$	4,338	$	7,529

Total operating costs and expenses increased by $3.6 billion and $7.5 billion during the three and nine months ended September 30, ~~2020, primarily as a result of increased cost of sales.~~2022 from the comparable periods in 2021, respectively. Cost of sales includes costs incurred directly for the production and delivery of LNG from the Liquefaction Project, to the extent those costs are not utilized for the commissioning process. Cost of sales ~~increased during the three and nine months ended September 30, 2021 from the comparable periods~~also includes change in ~~2020 primarily due~~fair value of commodity derivatives to ~~the increase in pricing of~~secure natural gas feedstock ~~as a result of higher US natural gas prices and increased volume of LNG delivered, partially offset by a decrease in net~~for the Liquefaction Project, costs associated with the sale of certain unutilized natural gas procured for the liquefaction process, ~~and the increased fair value of commodity derivatives to secure~~

~~natural gas feedstock for the Liquefaction Project due to favorable shifts in long-term forward prices relative to our hedged position. Cost of sales also includes~~ variable transportation and storage costs and other costs to convert natural gas into LNG.

~~Cost~~ Substantially all of ~~sales—affiliate decreased~~the increase in operating costs and expenses in both comparable periods was attributed to third party cost of sales, which increased by $3.4 billion and $7.3 billion during the three ~~months ended September 30, 2021~~ and ~~increased during the~~ nine months ended September 30, ~~2021~~2022, respectively, as a result of increased pricing of natural gas feedstock due to higher U.S. natural gas prices and, to a lesser extent, from increased volume of LNG delivered as discussed under Revenues. During the three and nine months ended September 30, 2022, cost of ~~cargoes procured~~sales additionally included an unfavorable change in the valuation associated with the Tourmaline IPM agreement that was assigned to SPL as discussed in Net income (loss) above.

Operating and maintenance expense (including affiliate and related party) primarily includes costs associated with operating and maintaining the Liquefaction Project and also includes service and maintenance, insurance, regulatory costs and other operating costs. During the three and nine months ended September 30, 2022, operating and maintenance expense increased from ~~our affiliate~~the comparable periods in 2021, primarily due to ~~fulfill our commitments~~increased third party service and maintenance contract costs in addition to ~~our long-term customers during operational constraints.~~increased natural gas transportation and storage capacity demand charges following the Train 6 Completion.

Other expense (income)


		Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	(in millions)	2021		2020		Change		2021		2020		Change			(in millions)	2022		2021		Variance		2022		2021		Variance
Interest expense, net of capitalized interest	Interest expense, net of capitalized interest	$	210	$	221	$	(11)	$	636	$	691	$	(55)		Interest expense, net of capitalized interest	$	222	$	210	$	12	$	641	$	636	$	5
Loss on modification or extinguishment of debt	Loss on modification or extinguishment of debt	27		—		27		81		43		38			Loss on modification or extinguishment of debt	—		27		(27)		—		81		(81)

Other income, net	Other income, net	(2)		(2)		—		(2)		(8)		6			Other income, net	(7)		(2)		(5)		(10)		(2)		(8)

Total other expense	Total other expense	$	235	$	219	$	16	$	715	$	726	$	(11)		Total other expense	$	215	$	235	$	(20)	$	631	$	715	$	(84)

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Total interest cost	$	231	$	244	$	678	$	732
Capitalized interest	(9)		(34)		(37)		(96)
Total interest expense, net of capitalized interest	$	222	$	210	$	641	$	636

Interest expense, net of capitalized interest, increased during the three and nine months ended September 30, 2022 from the comparable periods in 2021 primarily as a result of a lower portion of total interest costs eligible for capitalization following the Train 6 Completion, which was partially offset by lower interest cost as a result of reduced outstanding debt between the periods.

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Loss on modification or extinguishment of debt decreased during the three and nine months ended September 30, ~~2021~~2022 from the comparable periods in ~~2020 primarily due to lower interest costs as a result of refinancing higher cost debt and an increase in the portion of total interest costs that is eligible for capitalization primarily~~2021 due to the ~~continued construction~~recognition of the remaining assets of the Liquefaction Project. During the three months ended September 30, 2021 and 2020, we incurred $244 million and $246 million of total interest cost, respectively, of which we capitalized $34 million and $25 million, respectively. During the nine months ended September 30, 2021 and 2020, we incurred $732 million and $759 million of total interest cost, respectively, of which we capitalized $96 million and $68 million, respectively.

Loss on modification or extinguishment of debt increased during the three and nine months ended September 30, 2021 from the comparable periods in 2020. Loss on modification or extinguishment of debt recognized in 2021 was primarily attributable to debt extinguishment costs relating to the payment of early redemption fees, ~~and~~ premiums and ~~the~~ write off of unamortized debt issuance costs with the redemption of the 5.250% Senior Notes due 2025 (the “2025 CQP Senior ~~Notes~~Notes”) in March 2021 and 2026 CQP Senior Notes. Loss on modification or extinguishment of debt recognized in 2020 was primarily attributable to $43 million of debt extinguishment costs relating to the payment of early redemption fees and write off of unamortized debt premiums and issuance costs associated with the 5.625% Senior ~~Secured~~ Notes due ~~2021~~2026 (the ~~“2021 SPL~~“2026 CQP Senior Notes”) in September 2021.

Other income, net decreased during the three and nine months ended September 30, 2022 from the comparable 2021 periods due to higher interest income earned on cash and cash equivalents from higher interest rates in 2022.

Liquidity and Capital Resources

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


	September 30, 2022


Cash and cash equivalents	$	988
Restricted cash and cash equivalents designated for the Liquefaction Project	195

Available commitments under our credit facilities (1):

SPL’s Working capital revolving credit and letter of credit reimbursement agreement	837
CQP’s Credit facilities	750

Total available commitments under our credit facilities	1,587

Total available liquidity	$	2,770

(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of September 30, ~~2021~~2022. See Note 9—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and ~~December 31, 2020 (in millions):~~

September 30, December 31,
2021 2020
Cash and cash equivalents $ 1,713 $ 1,210
Restricted cash designated for the Liquefaction Project 133 97
Available commitments under the following credit facilities:
$1.2 billion Working Capital Revolving Credit and Letter of Credit Reimbursement Agreement (the “2020 SPL Working Capital Facility”) 804 787
CQP Credit Facilities executed in 2019 (“2019 CQP Credit Facilities”) 750 750
other debt instruments.

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

Although our sources and uses of cash are presented below from a consolidated standpoint, we and our subsidiary SPL operate with independent capital structures. Certain restrictions under debt instruments executed by 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. The majority of the cash held by SPL that is restricted to CQP relates to advance funding for operation and construction of the Liquefaction Project; and

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

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

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Revised Capital Allocation Plan

In September 2022, the board of directors of Cheniere approved a revised long-term capital allocation plan, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of debt, including senior notes of CQP and SPL. Pursuant to the capital allocation plan, $300 million of 2023 SPL Senior Notes were redeemed in October 2022.

Supplemental Guarantor Information

The $1.5 billion of 4.500% Senior Notes due 2029, $1.5 billion of 4.000% Senior Notes due 2031 (the ~~“2029~~“2031 CQP Senior Notes”)~~, the 2031 CQP~~ and $1.2 billion of 3.25% Senior Notes ~~and the~~due 2032 ~~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 Senior Notes are governed by the same base indenture (the “CQP Base Indenture”). The 2029 CQP Senior Notes are further governed by the Third Supplemental Indenture, the 2031 CQP Senior Notes are further governed by the Fifth Supplemental Indenture and the 2032 CQP Senior Notes are further governed by the Sixth Supplemental Indenture. The indentures governing the CQP Senior Notes contain terms and events of default and certain covenants that, among other things, limit our ability and the CQP Guarantors’ ability to incur liens and sell assets, enter into transactions with affiliates, enter into sale-leaseback transactions and consolidate, merge or sell, lease or otherwise dispose of all or substantially all of the applicable entity’s properties or assets.

At any time prior to October 1, 2024 for the 2029 CQP Senior Notes, March 1, 2026 for the 2031 CQP Senior Notes and January 31, 2027 for the 2032 CQP Senior Notes, we may redeem all or a part of the applicable CQP Senior Notes at a redemption price equal to 100% of the aggregate principal amount of the CQP Senior Notes redeemed, plus the “applicable premium” set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. In addition, at any time prior to October 1, 2024 for the 2029 CQP Senior Notes, March 1, 2024 for the 2031 CQP Senior Notes and January 31, 2025 for the 2032 CQP Senior Notes, we may redeem up to 35%, and in the case of the 2032 CQP Senior Notes, up to 40%, of the aggregate principal amount of the CQP Senior Notes with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price equal to 104.5% of the aggregate principal amount of the 2029 CQP Senior Notes, 104.000% of the aggregate principal amount of the 2031 CQP Senior Notes and 103.250% of the aggregate principal amount of the 2032 CQP Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption. We also may at any time on or after October 1, 2024 through the maturity date of October 1, 2029 for the 2029 CQP Senior Notes, March 1, 2026 through the maturity date of March 1, 2031 for the 2031 CQP Senior Notes and January 31, 2027 through maturity date of January 31, 2032 for the 2032 CQP Senior Notes, redeem the CQP Senior Notes, in whole or in part, at the redemption prices set forth in the respective indentures governing the CQP Senior Notes.

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

The CQP Guarantors’ guarantees are full and unconditional, subject to certain release provisions including (1) the sale, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of the CQP Guarantors, (2) upon the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from its guarantee obligations and (4) upon the legal defeasance or satisfaction and discharge of obligations under the indenture governing the CQP Senior Notes. In the event of a default in payment of the principal or interest by us, whether at maturity of the CQP Senior Notes or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the CQP Guarantors to enforce the guarantee.

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

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The following tables include summarized financial information of ~~Cheniere Partners (“Parent~~CQP (the “Parent Issuer”), and the CQP Guarantors (together with the Parent Issuer, the “Obligor Group”) on a combined basis. Investments in and equity in the earnings of SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”), which are not currently members of the Obligor Group, have been excluded. Intercompany balances and transactions between entities in the Obligor Group have been eliminated. Although the creditors of the Obligor Group have no claim against the Non-Guarantors, the Obligor Group may gain access to the assets of the Non-Guarantors upon bankruptcy, liquidation or reorganization of the Non-Guarantors due to its investment in these entities. However, such claims to the assets of the Non-Guarantors would be subordinated to the any claims by the Non-Guarantors’ creditors, including trade creditors. ~~See Sabine Pass LNG Terminal—SPL Senior Notes for additional detail on restrictions of Non-Guarantor debt.~~


Summarized Balance Sheets (in millions)	Summarized Balance Sheets (in millions)	September 30,		December 31,		Summarized Balance Sheets (in millions)	September 30,		December 31,
		2021		2020			2022		2021
ASSETS	ASSETS					ASSETS
Current assets	Current assets					Current assets
Cash and cash equivalents	Cash and cash equivalents	$	1,713	$	1,210	Cash and cash equivalents	$	988	$	876
Accounts receivable from Non-Guarantors	Accounts receivable from Non-Guarantors	38		46		Accounts receivable from Non-Guarantors	42		49
Contract assets						Contract assets	387		—
Other current assets	Other current assets	54		42		Other current assets	53		53
Current assets—affiliate	Current assets—affiliate	126		137		Current assets—affiliate	146		137
Current assets with Non-Guarantors	Current assets with Non-Guarantors	—		—		Current assets with Non-Guarantors	—		1
Total current assets	Total current assets	1,931		—		Total current assets	1,616		1,116

Property, plant and equipment, net of accumulated depreciation	Property, plant and equipment, net of accumulated depreciation	2,441		2,493		Property, plant and equipment, net of accumulated depreciation	2,391		2,422
Other non-current assets, net	Other non-current assets, net	108		117		Other non-current assets, net	107		119
Total assets	Total assets	$	4,480	$	2,610	Total assets	$	4,114	$	3,657

LIABILITIES	LIABILITIES					LIABILITIES
Current liabilities	Current liabilities					Current liabilities
Due to affiliates	Due to affiliates	$	145	$	156	Due to affiliates	$	160	$	167
Deferred revenue from Non-Guarantors	Deferred revenue from Non-Guarantors	21		22		Deferred revenue from Non-Guarantors	23		22

Other current liabilities	Other current liabilities	543		100		Other current liabilities	114		95

Other current liabilities from Non-Guarantors						Other current liabilities from Non-Guarantors	4		—
Total current liabilities	Total current liabilities	709		278		Total current liabilities	301		284

Long-term debt, net of premium, discount and debt issuance costs	Long-term debt, net of premium, discount and debt issuance costs	4,153		4,060		Long-term debt, net of premium, discount and debt issuance costs	4,158		4,154
Other non-current liabilities	Other non-current liabilities	85		85		Other non-current liabilities	83		87
Non-current liabilities—affiliate	Non-current liabilities—affiliate	15		17		Non-current liabilities—affiliate	15		15
Total liabilities	Total liabilities	$	4,962	$	4,440	Total liabilities	$	4,557	$	4,540


Summarized Statement of Income (in millions)	Nine Months Ended September 30, ~~2021~~2022

Revenues	$	~~241~~638
Revenues from Non-Guarantors	~~396~~402
Total revenues	~~637~~1,040

Operating costs and expenses	~~143~~154
Operating costs and expenses—affiliate	~~145~~149
Total operating costs and expenses	~~288~~303

Income from operations	~~348~~737
Net income	~~107~~599

~~2019 CQP Credit Facilities~~

We have a $750 million revolving credit facility under the 2019 CQP Credit Facilities. Borrowings under the 2019 CQP Credit Facilities are being used to fund the development and construction of Train 6 of the Liquefaction Project and for general corporate purposes, subject to a sublimit, and the 2019 CQP Credit Facilities are also available for the issuance of letters of credit. As of both September 30, 2021 and December 31, 2020, we had $750 million of available commitments and no letters of credit issued or loans outstanding under the 2019 CQP Credit Facilities.

The 2019 CQP Credit Facilities mature on May 29, 2024. Any outstanding balance may be repaid, in whole or in part, at any time without premium or penalty, except for interest rate breakage costs. The 2019 CQP Credit Facilities contain conditions precedent for extensions of credit, as well as customary affirmative and negative covenants, and limit our ability to make restricted payments, including distributions, to once per fiscal quarter and one true-up per fiscal quarter as long as certain conditions are satisfied.

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

~~Sabine Pass LNG Terminal~~

~~Liquefaction Facilities~~

The Liquefaction Project is one of the largest LNG production facilities in the world. We are currently operating five Trains and two marine berths at the Liquefaction Project, undergoing commissioning of one additional Train that is expected to be substantially completed in the first quarter of 2022 and constructing a third marine berth. We have achieved substantial completion of the first five Trains of the Liquefaction Project and commenced commercial operating activities for each Train at various times starting in May 2016. The following table summarizes the project completion and construction status of Train 6 of the Liquefaction Project as of September 30, 2021:


						~~Train 6~~
~~Overall project completion percentage~~						~~97.1%~~
~~Completion percentage of:~~
~~Engineering~~						~~100.0%~~
~~Procurement~~						~~100.0%~~
~~Subcontract work~~						~~95.8%~~
~~Construction~~						~~92.9%~~
~~Date of expected substantial completion~~						~~1Q 2022~~

We received approval from FERC to site, construct and operate up to a combined total equivalent of approximately 1,661.94 Bcf/yr (approximately 33 mtpa) of natural gas from the Liquefaction Project. The DOE has has issued multiple orders authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG terminal through December 31, 2050 to FTA countries and non-FTA countries for 1,509.3 Bcf/yr (approximately 30 mtpa) of natural gas, and an additional 152.64 Bcf/yr (approximately 3 mtpa) of natural gas to FTA countries only, with the authorization for the additional volume to non-FTA countries pending.

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

~~Customers~~

SPL has entered into fixed price long-term SPAs with third-parties, generally with terms of 20 years (plus extension rights) and with a weighted average remaining contract length of approximately 16 years (plus extension rights) for Trains 1 through 6 of the Liquefaction Project to make available an aggregate amount of LNG that is approximately 75% of the total production capacity from these Trains, potentially increasing up to approximately 85% after giving effect to an SPA that Cheniere has committed to provide to us. Under these SPAs, the customers will purchase LNG from SPL for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to approximately 115% of Henry Hub. The customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension. We refer to the fee component that is applicable regardless of a cancellation or suspension of LNG cargo deliveries under the SPAs as the fixed fee component of the price under SPL’s SPAs. We refer to the fee component that is applicable only in connection with LNG cargo deliveries as the variable fee component of the price under SPL’s SPAs. The variable fees under SPL’s SPAs were generally sized at the time of entry into each SPA with the intent to cover the costs of gas purchases and transportation and liquefaction fuel to produce the LNG to be sold under each such SPA. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train.

In aggregate, the annual fixed fee portion to be paid by the third-party SPA customers is approximately $2.9 billion for Trains 1 through 5. After giving effect to an SPA that Cheniere has committed to provide to SPL and upon the date of first commercial delivery of Train 6, the annual fixed fee portion to be paid by the third-party SPA customers is expected to increase to at least $3.3 billion.

In addition, Cheniere Marketing has agreements with SPL to purchase: (1) at Cheniere Marketing’s option, any LNG produced by SPL in excess of that required for other customers, (2) up to 30 cargoes scheduled for delivery in 2021 at a price of 115% of Henry Hub plus $0.728 per MMBtu (3) up to 81 cargoes to be delivered between 2021 and 2027 at a price equal to 115% of Henry Hub plus $1.96 per MMBtu, (4) up to six cargoes to be delivered in 2022 and up to six cargoes to be delivered in 2023 at a price equal to 115% of Henry Hub plus $1.768 per MMBtu and (5) up to six cargoes to be delivered in 2022 at a price equal to 115% of Henry Hub plus $1.952 per MMBtu.

~~Natural Gas Transportation, Storage and Supply~~

To ensure SPL is able to transport adequate natural gas feedstock to the Sabine Pass LNG terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation capacity with CTPL and third-party pipeline companies. SPL has entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Project. SPL has also entered into enabling agreements and long-term natural gas supply contracts with third parties in order to secure natural gas feedstock for the Liquefaction Project. As of September 30, 2021, SPL had secured up to approximately 5,033 TBtu of natural gas feedstock through long-term and short-term natural gas supply contracts with remaining terms that range up to 10 years, a portion of which is subject to conditions precedent.

~~Construction~~

SPL entered into lump sum turnkey contracts with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of Trains 1 through 6 of the Liquefaction Project, under which Bechtel charges a lump sum for all work performed and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel may cause SPL to enter into a change order, or SPL agrees with Bechtel to a change order.

The total contract price of the EPC contract for Train 6 of the Liquefaction Project is approximately $2.5 billion, including estimated costs for the third marine berth that is currently under construction. As of September 30, 2021, we have incurred $2.2 billion under this contract.

~~Regasification Facilities~~

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. Approximately 2 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which SPLNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Each of TotalEnergies Gas & Power North America, Inc. (“Total”) and Chevron U.S.A. Inc. (“Chevron”) has reserved approximately 1 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to SPLNG aggregating approximately $125 million annually, prior to inflation adjustments, for 20 years that commenced in 2009. Total S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions, and Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

The remaining approximately 2 Bcf/d of capacity has been reserved under a TUA by SPL. SPL is obligated to make monthly capacity payments to SPLNG aggregating approximately $250 million annually, prior to inflation adjustments, continuing until at least May 2036. SPL entered into a partial TUA assignment agreement with Total, whereby upon substantial completion of Train 5 of the Liquefaction Project, SPL gained access to substantially all of Total’s capacity and other services provided under Total’s TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity, permit SPL to more flexibly manage its LNG storage capacity and accommodate the development of Train 6. Notwithstanding any arrangements between Total and SPL, payments required to be made by Total to SPLNG will continue to be made by Total to SPLNG in accordance with its TUA. During each of the three months ended September 30, 2021 and 2020, SPL recorded $32 million as operating and maintenance expense under this partial TUA assignment agreement. During

~~each of the nine months ended September 30, 2021 and 2020, SPL recorded $97 million as operating and maintenance expense under this partial TUA assignment agreement.~~

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

~~Capital Resources~~

We currently expect that SPL’s capital resources requirements with respect to the Liquefaction Project will be financed through cash flows under the SPAs, project debt and borrowings and equity contributions from us. We believe that with the net proceeds of borrowings, available commitments under the 2020 SPL Working Capital Facility and 2019 CQP Credit Facilities, cash flows from operations and equity contributions from us, SPL will have adequate financial resources available to meet its currently anticipated capital, operating and debt service requirements with respect to Trains 1 through 6 of the Liquefaction Project. Additionally, SPLNG generates cash flows from the TUAs, as discussed above.

The following table provides a summary of our capital resources from borrowings and available commitments for the Sabine Pass LNG terminal, excluding equity contributions to our subsidiaries and cash flows from operations (as described in ~~Sources and Uses of Cash), at September 30, 2021 and December 31, 2020 (in millions):~~

September 30, December 31,
2021 2020
Senior notes (1) $ 18,278 $ 17,750
Credit facilities outstanding balance (2) — —
Letters of credit issued (3) 396 413
Available commitments under credit facilities (3) 1,554 1,537
Total capital resources from borrowings and available commitments (4) $ 20,228 $ 19,700

~~(1)Includes SPL’s 4.200% to 6.25% senior secured notes due between March 2022 and September 2037 (collectively, the “SPL Senior Notes”) and our CQP Senior Notes.~~

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

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

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

~~SPL Senior Notes~~

The SPL Senior Notes are governed by a common indenture (the “SPL Indenture”) and the terms of the 5.00% Senior Secured Notes due 2037 (the “2037 SPL Senior Notes”) are governed by a separate indenture (the “2037 SPL Senior Notes Indenture”). Both the SPL Indenture and the 2037 SPL Senior Notes Indenture contain terms and events of default and certain covenants that, among other things, limit SPL’s ability and the ability of SPL’s restricted subsidiaries to incur additional indebtedness or issue preferred stock, make certain investments or pay dividends or distributions on capital stock or subordinated indebtedness or purchase, redeem or retire capital stock, sell or transfer assets, including capital stock of SPL’s restricted subsidiaries, restrict dividends or other payments by restricted subsidiaries, incur liens, enter into transactions with affiliates, dissolve, liquidate, consolidate, merge, sell or lease all or substantially all of SPL’s assets and enter into certain LNG sales contracts. Subject to permitted liens, the SPL Senior Notes are secured on a ~~pari passu~~ first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. SPL may not make any distributions until, among other requirements, deposits are made into debt service reserve accounts as required and a debt service coverage ratio test of 1.25:1.00 is satisfied.

At any time prior to six months before the respective dates of maturity for each series of the SPL Senior Notes (except for the 2022 SPL Senior Notes, 5.625% Senior Secured Notes due 2023 (the “2023 SPL Senior Notes”), 5.75% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) and 5.625% Senior Notes due 2025 (the “2025 SPL Senior Notes”), in which case the time period is three months before the respective dates of maturity), SPL may redeem all or part of such series of the SPL Senior Notes at a redemption price equal to the ‘make-whole’ price (except for the 2037 SPL Senior Notes, in which case

the redemption price is equal to the “optional redemption” price) set forth in the respective indentures governing the SPL Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption. SPL may also, at any time within six months of the respective maturity dates for each series of the SPL Senior Notes (except for the 2022 SPL Senior Notes, 2023 SPL Senior Notes, 2024 SPL Senior Notes and 2025 SPL Senior Notes, in which case the time period is within three months of the respective dates of maturity), redeem all or part of such series of the SPL Senior Notes at a redemption price equal to 100% of the principal amount of such series of the SPL Senior Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

SPL may incur additional indebtedness in the future, including by issuing additional notes, and such indebtedness could be at higher interest rates and have different maturity dates and more restrictive covenants than the current outstanding indebtedness of SPL, including the SPL Senior Notes and the 2020 SPL Working Capital Facility. Semi-annual principal payments for the 2037 SPL Senior Notes are due on March 15 and September 15 of each year beginning September 15, 2025 and are fully amortizing according to a fixed sculpted amortization schedule.

During 2021, SPL entered into a series of note purchase agreements for the sale of approximately $482 million aggregate principal amount of the 2037 SPL Private Placement Senior Secured Notes on a private placement basis. The 2037 SPL Private Placement Senior Secured Notes are expected to be issued in the fourth quarter of 2021, subject to customary closing conditions, and the net proceeds will be used to strategically refinance a portion of the 2022 SPL Senior Notes and pay related fees, costs and expenses. The 2037 SPL Private Placement Senior Secured Notes will be fully amortizing, with a weighted average life of over 10 years and a weighted average interest rate of 3.07%.

~~2020 SPL Working Capital Facility~~

In March 2020, SPL entered into the 2020 SPL Working Capital Facility with aggregate commitments of $1.2 billion, which replaced the $1.2 billion Amended and Restated SPL Working Capital Facility (the “2015 SPL Working Capital Facility”). The 2020 SPL Working Capital Facility is intended to be used for loans to SPL, swing line loans to SPL and the issuance of letters of credit on behalf of SPL, primarily for (1) the refinancing of the 2015 SPL Working Capital Facility, (2) fees and expenses related to the 2020 SPL Working Capital Facility, (3) SPL and its future subsidiaries’ gas purchase obligations and (4) SPL and certain of its future subsidiaries’ general corporate purposes. SPL may, from time to time, request increases in the commitments under the 2020 SPL Working Capital Facility of up to $800 million. As of September 30, 2021 and December 31, 2020, SPL had $804 million and $787 million of available commitments and $396 million and $413 million aggregate amount of issued letters of credit, respectively. As of both September 30, 2021 and December 31, 2020, SPL had no outstanding borrowings under the 2020 SPL Working Capital Facility.

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

The 2020 SPL Working Capital Facility contains customary conditions precedent for extensions of credit, as well as customary affirmative and negative covenants. SPL is restricted from making certain distributions under agreements governing its indebtedness generally until, among other requirements, satisfaction of a 12-month forward-looking and backward-looking 1.25:1.00 debt service reserve ratio test. The obligations of SPL under the 2020 SPL Working Capital Facility are secured by substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries of SPL on a ~~pari passu~~ ~~basis by a first priority lien with the SPL Senior Notes.~~

~~Restrictive Debt Covenants~~

~~As of September 30, 2021, we and SPL were in compliance with all covenants related to our respective debt agreements.~~

~~LIBOR~~

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

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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 ~~for the nine months ended September 30, 2021~~ and ~~2020~~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,
2021 2020
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities $ 1,667 $ 1,333
Proceeds from issuances of debt 2,700 1,995
Other 8 —
$ 4,375 $ 3,328
Uses of cash, cash equivalents and restricted cash:
Property, plant and equipment $ (495) $ (795)
Repayments of debt (2,172) (2,000)
Debt issuance and other financing costs (35) (34)
Debt extinguishment costs (61) (39)
Distributions to owners (1,073) (1,011)
(3,836) (3,879)
Net increase (decrease) in cash, cash equivalents and restricted cash $ 539 $ (551)


	Nine Months Ended September 30,
	2022		2021

Net cash provided by operating activities	$	2,442	$	1,667
Net cash used in investing activities	(356)		(495)
Net cash used in financing activities	(1,877)		(633)












Net increase in cash, cash equivalents and restricted cash and cash equivalents	$	209	$	539

Operating Cash Flows

Our operating cash net inflows during the nine months ended September 30, 2022 and 2021 were $2.4 billion and ~~2020 were $1,667 million and $1,333 million,~~$1.7 billion, respectively. The ~~$334~~$775 million increase ~~in operating cash inflows in 2021 compared to 2020~~between the periods was primarily related to ~~cash provided by working capital primarily from payment timing differences and timing of~~increases in cash receipts ~~from the sale~~on LNG delivered due to increases in price per MMBtu and volume of LNG ~~cargoes.~~delivered, which was partially offset by higher operating cash outflows primarily due to higher natural gas feedstock costs.

~~Proceeds from Issuance~~Investing Cash Flows

Cash outflows for property, plant and equipment were primarily for the construction costs for Train 6 of the Liquefaction Project, which achieved substantial completion on February 4, 2022.

Financing Cash Flows

Our financing cash net outflows during the nine months ended September 30, 2022 and 2021 were $1.9 billion and $633 million, respectively. The $1.2 billion increase in outflows between the periods was primarily related to an increase in cash distributions to unitholders of $804 million and a decrease of $440 million of net inflows related to debt activity, each described further below.

Debt ~~Repayments of Debt, Debt Issuance and Other Financing Costs and Debt Extinguishment Costs~~Activity

During the nine months ended September 30, 2021, we issued an aggregate principal amount of $1.5 billion of the 2031 CQP Senior Notes and $1.2 billion of the 3.25% Senior Notes due 2032 (the “2032 CQP Senior ~~Notes~~Notes”) and incurred $35 million of debt issuance costs related to these issuances. The proceeds ~~from~~of these issuances, together with cash on hand, were used to redeem ~~all~~the $1.5 billion principal amount of the ~~outstanding~~ 2025 CQP Senior Notes and $672 million of the 2032 CQP Senior Notes, and we paid $61 million of debt extinguishment costs related to ~~these redemptions, primarily for the payment of early redemption fees and write off of unamortized issuance costs.~~

~~During~~premiums associated with this redemption. We did not have any debt activity during the nine months ended September 30, 2020, we entered into the 2020 SPL Working Capital Facility to replace the previous working capital facility and issued an aggregate principal amount of $2.0 billion of the 2030 SPL Senior Notes, which was used to redeem all of SPL’s outstanding 2021 SPL Senior Notes. We incurred $34 million of debt issuance costs primarily related to up-front fees paid upon closing of the 2030 SPL Senior Notes and the 2020 SPL Working Capital Facility and $39 million of debt extinguishment costs related to the redemption of the 2021 SPL Senior Notes, primarily for the payment of early redemption fees and write off of unamortized issuance costs.2022.

~~Property, Plant and Equipment~~

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

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Cash Distributions to Unitholders

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


				Total Distribution (in millions)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Common Units		General Partner Units		Incentive Distribution Rights

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


August 13, 2021	April 1 - June 30, 2021	0.665		322		7		32
May 14, 2021	January 1 - March 31, 2021	0.660		320		7		30
February 12, 2021	October 1 - December 31, 2020	0.655		316		7		27

In addition, Tug Services distributed $2 million during each of the three months ended September 30, 2022 and 2021 and ~~2020:~~

Total Distribution (in millions)
Date Paid Period Covered by Distribution Distribution Per Common Unit Distribution Per Subordinated Unit Common Units Subordinated Units General Partner Units Incentive Distribution Rights
August 13, 2021 April 1 - June 30, 2021 $ 0.665 $ — $ 322 $ — $ 7 $ 32
May 14, 2021 January 1 - March 31, 2021 0.660 — 320 — 7 30
February 12, 2021 October 1 - December 31, 2020 0.655 — 316 — 7 27
August 14, 2020 April 1 - June 30, 2020 0.645 0.645 225 88 7 22
May 15, 2020 January 1 - March 31, 2020 0.64 0.64 223 86 7 20
February 14, 2020 October 1 - December 31, 2019 0.63 0.63 220 85 6 18
$7 million and $6 million during the nine months ended September 30, 2022 and 2021, respectively, to Cheniere Terminals in accordance with their terminal marine service agreement, which is recognized as part of the distributions to our general partner interest holders.

On October ~~26, 2021,~~24, 2022, we declared a ~~$0.680~~cash distribution of $1.070 per common unit ~~and the related distribution to our general partner and incentive distribution right holders to be paid on November 12, 2021~~ to unitholders of record as of November ~~5, 2021 for~~3, 2022 and the ~~period from July 1, 2021~~related general partner distribution to ~~September 30, 2021.~~

~~Off-Balance Sheet Arrangements~~

Asbe paid on November 14, 2022. These distributions consist of ~~September 30, 2021, we had no transactions that met the definition~~a base amount of ~~off-balance sheet arrangements that may have~~$0.775 per unit and a ~~current or future material effect on our consolidated financial position or operating results.~~ variable amount of $0.295 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, ~~2020~~2021.

Recent Accounting Standards

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Marketing and Trading Commodity Price Risk

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

September 30, 2021 December 31, 2020
Fair Value Change in Fair Value Fair Value Change in Fair Value
Liquefaction Supply Derivatives $ 33 $ 2 $ (21) $ 4


	September 30, 2022				December 31, 2021
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(5,078)	$	692	$	27	$	1

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

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ITEM 4. CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our general partner’s management, including our general partner’s Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. Other than discussed below, there have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the fiscal year ended December 31, ~~2020~~2021.

Louisiana Department of Environmental Quality (“LDEQ”) Matter

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

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

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

ITEM 1A. RISK FACTORS

~~Other than as set forth below, there~~There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the fiscal year ended December 31, ~~2020~~2021.

~~Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.~~

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our common units will generally be considered to be “effectively connected” with a U.S. trade or business and subject to U.S. federal income tax. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.

Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, withholding may be required on the amount realized unless the disposing unitholder certifies that it is not a foreign person. Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the unitholder. The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. In Notice 2021-51, the Internal Revenue Service announced that it intends to amend the Treasury regulations to defer the applicability date for withholding on a transfer of an interest in a publicly traded partnership to January 1, 2023. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

ITEM 5. OTHER INFORMATION

On November ~~3, 2021,~~1, 2022, SPL and Cheniere Marketing entered into ~~a letter~~an SPA for approximately 0.85 mtpa of LNG associated with the previously announced IPM agreement ~~for the sale of up to thirty-five (35) cargoes to be scheduled for delivery in the 2022 Contract Year at a price equal to 115% of Henry Hub plus $1.92 per MMBtu.~~

between SPL and Tourmaline Oil Marketing Corp.

4037

ITEM 6. EXHIBITS

Exhibit No.

Description

~~4.1~~

~~Sixth Supplemental Indenture, dated as of September 27, 2021, among~~ ~~the Partnership, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indentur~~e ~~(incorporated by reference to Exhibit 4.1 to~~ ~~the Partnership~~’s ~~Current Report on Form 8-K (SEC File No. 001-33366), filed on September 27, 2021)~~

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 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order ~~CO-00049~~CO-00067 Performance and Attendance Bonus (“PAB”) Provisional Sum Closure, dated August 18, 2022, (ii) the Change Order CO-00068 Performance and Attendance Bonus (“PAB”) Provisional Sum Closure (Reconciliation to CO-00067), dated August 18, 2022, and (iii) the Change Order CO-00069 COVID-19 Impacts ~~2Q2021,~~1Q2022 and 2Q2022, dated ~~July 6, 2021, (ii) CO-00050 Third Berth Bunkering Ship Modifications — Pre-Investment for Foundations, dated July 6, 2021, (iii) CO-00051 Thermal Oxidizer Controls Change, dated September 8, 2021~~, ~~(iv) CO-00052 Third Berth Spare Beacon and Additional Cable Tray, dated September 8, 2021 and (v) CO-00053 Train 6 Gearbox Assembly Replacement for Unit 1411, dated September 24, 202~~1August 29, 2022

10.2*

~~First Amendment to Third Amended and Restated Common Terms~~F orm of Indemnification Agreement ~~dated as~~for officers and/or directors of July 26, 2021, among SPL, as borrower, the Secured Debt Holder Group Representatives party thereto, the Secured Hedge Representatives party thereto, the Secured Gas Hedge Representatives party thereto and Société Générale, as the Common Security Trustee and the Intercreditor AgentCheniere Partners GP

10.3*

~~Letter agreement, dated November~~ 3 ~~, 2021, regarding the Amended and Restated~~ LNG Sale and Purchase Agreement ~~(FOB)~~(Tourmaline Oil Marketing Corp ), dated ~~August 5, 2014,~~June 15, 2022, between SPL and Cheniere Marketing International LLP ~~(as assignee of Cheniere Marketing, LLC)~~

~~10.4~~

~~Registration Rights Agreement, dated as of September 27, 2021, among~~ ~~the Partnership, the guarantors party thereto and RBC Capital Markets, LLC~~ ~~(incorporated by reference to Exhibit 10.1 to~~ ~~the Partnership~~’s ~~Current Report on Form 8-K (SEC File No. 001-33366), filed on September 27, 2021)~~

22.1*22.1

List of Issuers and Guarantor Subsidiaries (Incorporated by reference to Exhibit 22.1 to the Partnership’s Annual Report on Form 10-K (SEC File No. 001-33366), filed on February 24, 2022)

31.1*

Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

31.2*

Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

32.1**

Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2**

Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS*

XBRL Instance Document

101.SCH*

XBRL Taxonomy Extension Schema Document

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*

XBRL Taxonomy Extension Labels Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

104*

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)



*			Filed herewith.
**			Furnished herewith.

4138

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 ~~3, 2021~~2, 2022	By:	/s/ Zach Davis
			Zach Davis
			~~Senior~~Executive Vice President and Chief Financial Officer
			(on behalf of the registrant and as principal financial officer)

Date:	November ~~3, 2021~~2, 2022	By:	/s/ ~~Leonard E. Travis~~David Slack
			~~Leonard E. Travis~~David Slack
			~~Senior~~ Vice President and Chief Accounting Officer
			(on behalf of the registrant and as principal accounting officer)

4239


Three and Nine Months Ended September 30, 2021
	Common Unitholders’ Interest			Subordinated Unitholder’s Interest		General Partner’s Interest			Total Partners’ Equity
	Units	Amount			Units	Amount		Units			Amount













Balance at December 31, 2020	484.0	$	714		—	$	—	9.9	$	(175)		$	539
Net income	—	340			—	—		—	7			347
Distributions
Common units, $0.655/unit	—	(316)			—	—		—	—			(316)

General partner units	—	—			—	—		—	(35)			(35)
Balance at March 31, 2021	484.0	738			—	—		9.9	(203)			535
Net income	—	387			—	—		—	8			395
Distributions
Common units, $0.660/unit	—	(320)			—	—		—	—			(320)
General partner units	—	—			—	—		—	(39)			(39)
Balance at June 30, 2021	484.0	805			—	—		9.9	(234)			571
Net income	—	373			—	—		—	8			381

Distributions
Common units, $0.665/unit	—	(322)			—	—		—	—			(322)

General partner units	—	—			—	—		—	(41)			(41)

Balance at September 30, 2021	484.0	$	856		—	$	—	9.9	$	(267)		$	589