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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q    
    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2024
or
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from            to            
Commission file number 001-33366
Cheniere Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware20-5913059
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
845 Texas Avenue, Suite 1250
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 classTrading SymbolName of each exchange on which registered
Common Units Representing Limited Partner InterestsCQPNew York Stock Exchange
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 filerAccelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes     No ☒
As of April 25, 2024, the registrant had 484,040,623 common units outstanding.




CHENIERE ENERGY PARTNERS, L.P.
TABLE OF CONTENTS







i

DEFINITIONS

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

Common Industry and Other Terms
ASUAccounting Standards Update
Bcf/dbillion cubic feet per day
Bcfebillion cubic feet equivalent
DOEU.S. Department of Energy
EPCengineering, procurement and construction
ESGenvironmental, social and governance
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FIDfinal investment decision
FTA countriescountries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAPgenerally accepted accounting principles in the United States
Henry Hubthe final settlement price (in U.S. dollars 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 agreementsintegrated production marketing agreements in which the gas producer sells to us gas on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs
LNGliquefied 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
MMBtumillion 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
mtpamillion tonnes per annum
non-FTA countriescountries 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
SECU.S. Securities and Exchange Commission
SOFRSecured Overnight Financing Rate
SPALNG 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
Trainan industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUAterminal use agreement



1

Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of March 31, 2024, including our ownership of certain subsidiaries, and the references to these entities used in this quarterly report:

CQP_OrgChart_Q1_2024.jpg

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



2



PART I.     FINANCIAL INFORMATION



ITEM I.     CONSOLIDATED FINANCIAL STATEMENTS
CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per unit data)
(unaudited)

Three Months Ended March 31,
20242023
Revenues
LNG revenues$1,720 $2,106 
LNG revenues—affiliate524 761 
Regasification revenues34 34 
Other revenues17 16 
Total revenues2,295 2,917 
Operating costs and expenses
Cost of sales (excluding items shown separately below)964 313 
Cost of sales—affiliate4 17 
Operating and maintenance expense200 206 
Operating and maintenance expense—affiliate43 44 
Operating and maintenance expense—related party13 16 
General and administrative expense3 3 
General and administrative expense—affiliate22 22 
Depreciation and amortization expense168 167 
Other3  
Total operating costs and expenses1,420 788 
Income from operations875 2,129 
Other income (expense)
Interest expense, net of capitalized interest(202)(208)
Interest and dividend income9 14 
Total other expense(193)(194)
Net income$682 $1,935 
Basic and diluted net income per common unit (1)
$1.18 $3.50 
Weighted average basic and diluted number of common units outstanding484.0 484.0 
(1)In computing basic and diluted net income per common unit, net income is reduced by the amount of undistributed net income allocated to participating securities other than common units, as required under the two-class method. See Note 12—Net Income per Common Unit.

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

3

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except unit data)

March 31,December 31,
20242023
ASSETS(unaudited) 
Current assets  
Cash and cash equivalents$333 $575 
Restricted cash and cash equivalents59 56 
Trade and other receivables, net of current expected credit losses237 373 
Trade receivables—affiliate160 278 
Advances to affiliate109 84 
Inventory134 142 
Current derivative assets37 30 
Other current assets, net33 43 
Other current assets—affiliate1  
Total current assets1,103 1,581 
Property, plant and equipment, net of accumulated depreciation16,071 16,212 
Operating lease assets78 81 
Derivative assets59 40 
Other non-current assets, net186 188 
Total assets$17,497 $18,102 
LIABILITIES AND PARTNERS’ DEFICIT
 
Current liabilities
Accounts payable$34 $69 
Accrued liabilities488 806 
Accrued liabilities—related party5 5 
Current debt, net of unamortized debt issuance costs2,145 300 
Due to affiliates32 55 
Deferred revenue84 114 
Deferred revenue—affiliate 3 
Current derivative liabilities144 196 
Other current liabilities16 18 
Total current liabilities2,948 1,566 
Long-term debt, net of unamortized discount and debt issuance costs13,616 15,606 
Operating lease liabilities69 71 
Finance lease liabilities13 14 
Derivative liabilities1,566 1,531 
Other non-current liabilities84 75 
Other non-current liabilities—affiliate23 23 
Partners’ deficit
Common unitholders’ interest (484.0 million units issued and outstanding at both March 31, 2024 and December 31, 2023)
1,205 1,038 
General partner’s interest (2% interest with 9.9 million units issued and outstanding at both March 31, 2024 and December 31, 2023)
(2,027)(1,822)
Total partners’ deficit
(822)(784)
Total liabilities and partners’ deficit
$17,497 $18,102 

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

4

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ DEFICIT
(in millions)
(unaudited)

Three Months Ended March 31, 2024
Common Unitholders’ InterestGeneral Partner’s InterestTotal Partners’ Deficit
UnitsAmountUnitsAmount
Balance at December 31, 2023484.0 $1,038 9.9 $(1,822)$(784)
Net income
— 668 — 14 682 
Distributions
Common units, $1.035/unit
— (501)— — (501)
General partner units— — — (219)(219)
Balance at March 31, 2024484.0 $1,205 9.9 $(2,027)$(822)

Three Months Ended March 31, 2023
Common Unitholders’ InterestGeneral Partner’s InterestTotal Partners’ Deficit
UnitsAmountUnitsAmount
Balance at December 31, 2022484.0 $(1,118)9.9 $(1,013)$(2,131)
Net income— 1,897 — 38 1,935 
Distributions
Common units, $1.070/unit
— (518)— — (518)
General partner units— — — (236)(236)
Balance at March 31, 2023484.0 $261 9.9 $(1,211)$(950)

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

5

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
(unaudited)
 Three Months Ended March 31,
20242023
Cash flows from operating activities  
Net income
$682 $1,935 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense168 167 
Amortization of discount and debt issuance costs7 7 
Total gains on derivative instruments, net
(55)(1,260)
Net cash provided by (used for) settlement of derivative instruments
12 (11)
Other5 6 
Changes in operating assets and liabilities:
Trade and other receivables136 358 
Trade receivables—affiliate118 288 
Advances to affiliate(25)18 
Inventory8 10 
Accounts payable and accrued liabilities(343)(617)
Accrued liabilities—related party (2)
Due to affiliates(22)(40)
Total deferred revenue(21)(61)
Other, net3 53 
Other, net—affiliate(4)(4)
Net cash provided by operating activities
669 847 
Cash flows from investing activities  
Property, plant and equipment, net(36)(89)
Other(1)(5)
Net cash used in investing activities
(37)(94)
Cash flows from financing activities  
Repayments of debt(150) 
Distributions(720)(754)
Other(1)(1)
Net cash used in financing activities
(871)(755)
Net decrease in cash, cash equivalents and restricted cash and cash equivalents
(239)(2)
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period631 996 
Cash, cash equivalents and restricted cash and cash equivalents—end of period$392 $994 

Balances per Consolidated Balance Sheet:
March 31,
2024
Cash and cash equivalents$333 
Restricted cash and cash equivalents59 
Total cash, cash equivalents and restricted cash and cash equivalents$392 
The accompanying notes are an integral part of these consolidated financial statements.

6

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)


NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

We own a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”) which has six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include five LNG storage tanks, vaporizers and three marine berths. Additionally, the Sabine Pass LNG Terminal includes a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several large interstate and intrastate pipelines (the “Creole Trail Pipeline”).

We are pursuing an expansion project to provide additional liquefaction capacity, and we have commenced commercialization to support the additional liquefaction capacity associated with this potential expansion project. The development of this site or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.

We do not have employees and thus we and our subsidiaries have various services agreements with affiliates of Cheniere in the ordinary course of business, including services required to construct, operate and maintain the Liquefaction Project, and administrative services. See Note 11—Related Party Transactions for additional details of the activity under these services agreements during the three months ended March 31, 2024 and 2023.

As of March 31, 2024, Cheniere owned 48.6% of our limited partner interest in the form of 239.9 million of our common units. Cheniere also owns 100% of our general partner interest and our incentive distribution rights (“IDRs”).

Basis of Presentation

The accompanying unaudited Consolidated Financial Statements of CQP have been prepared in accordance with GAAP for interim financial information and in accordance with Rule 10-01 of Regulation S-X and reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair statement of the financial results for the interim periods presented. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements and should be read in conjunction with the Consolidated Financial Statements and accompanying notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2023.

Results of operations for the three months ended March 31, 2024 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2024.

We are not subject to either federal or state income tax, as our partners are taxed individually on their allocable share of our taxable income.

Recent Accounting Standards

ASU 2023-07

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280). This guidance requires a public entity, including entities with a single reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis and provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. We plan to adopt this guidance and conform with the applicable disclosures retrospectively when it becomes mandatorily effective for our annual report for the year ending December 31, 2024.

NOTE 2—UNITHOLDERS’ EQUITY
 
The common units represent limited partner interests in us, which entitle the unitholders to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. Although common unitholders are not obligated to fund losses of the Partnership, their capital account, which would be considered in allocating the net assets of the Partnership were it to be liquidated, continues to share in losses.
7

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
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, which, as defined in our partnership agreement, is generally our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions we have paid to date have been made from accumulated operating surplus as defined in the partnership agreement.
As of March 31, 2024, our total securities beneficially owned in the form of common units were held 48.6% by Cheniere, 41.5% by CQP Target Holdco L.L.C. (“CQP Target Holdco”) and other affiliates of Blackstone Inc. (“Blackstone”) and Brookfield Asset Management Inc. (“Brookfield”) and 7.9% by the public. All of our 2% general partner interest was held by Cheniere. CQP Target Holdco’s equity interests are 50.0% owned by BIP Chinook Holdco L.L.C., an affiliate of Blackstone, and 50.0% owned by BIF IV Cypress Aggregator (Delaware) LLC, an affiliate of Brookfield. The ownership of CQP Target Holdco, Blackstone and Brookfield are based on their most recent filings with the SEC.

NOTE 3—RESTRICTED CASH AND CASH EQUIVALENTS
 
As of March 31, 2024 and December 31, 2023, we had $59 million and $56 million of restricted cash and cash equivalents, respectively, for which the usage or withdrawal of such cash is contractually or legally restricted to the payment of liabilities related to the Liquefaction Project as required under certain debt arrangements.

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

Trade and other receivables, net of current expected credit losses, consisted of the following (in millions):
 March 31,December 31,
20242023
Trade receivables$235 $364 
Other receivables2 9 
Total trade and other receivables, net of current expected credit losses$237 $373 

NOTE 5—INVENTORY

Inventory consisted of the following (in millions):
 March 31,December 31,
20242023
Materials$109 $107 
LNG7 12 
Natural gas16 22 
Other2 1 
Total inventory$134 $142 

8

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 6—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION
 
Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):
March 31,December 31,
20242023
LNG terminal  
Terminal and interconnecting pipeline facilities$20,194 $20,176 
Construction-in-process196 189 
Accumulated depreciation(4,339)(4,173)
Total LNG terminal, net of accumulated depreciation16,051 16,192 
Fixed assets 
Fixed assets30 29 
Accumulated depreciation(26)(26)
Total fixed assets, net of accumulated depreciation4 3 
Assets under finance leases
Tug vessels23 23 
Accumulated depreciation(7)(6)
Total assets under finance leases, net of accumulated depreciation16 17 
Property, plant and equipment, net of accumulated depreciation$16,071 $16,212 

Depreciation expense was $167 million and $165 million during the three months ended March 31, 2024 and 2023, respectively.

NOTE 7—DERIVATIVE INSTRUMENTS

We have commodity derivatives consisting of natural gas supply contracts, including those under our IPM agreements, for the operation of the Liquefaction Project and expansion project, as well as the associated economic hedges (collectively, the “Liquefaction Supply Derivatives”).

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

The following table shows the fair value of the derivative instruments that are required to be measured at fair value on a recurring basis, distinguished by the fair value hierarchy levels prescribed by GAAP (in millions):
Fair Value Measurements as of
March 31, 2024December 31, 2023
Quoted Prices in Active Markets
(Level 1)
Significant Other Observable Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
TotalQuoted Prices in Active Markets
(Level 1)
Significant Other Observable Inputs
(Level 2)
Significant Unobservable Inputs
(Level 3)
Total
Liquefaction Supply Derivatives asset (liability)
$18 $3 $(1,635)$(1,614)$18 $1 $(1,676)$(1,657)

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

We include a significant portion of the Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual
9

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.

In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility includes the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control. Our fair value estimates incorporate market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.

The Level 3 fair value measurements of the natural gas positions within the Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of March 31, 2024:
Net Fair Value Liability
(in millions)
Valuation ApproachSignificant Unobservable InputRange of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives$(1,635)Market approach incorporating present value techniques
Henry Hub basis spread
$(0.470) - $0.445 / $0.025
Option pricing model
International LNG pricing spread, relative to Henry Hub (2)
92% - 502% / 187%
(1)Unobservable inputs were weighted by the relative fair value of the instruments.
(2)Spread contemplates U.S. dollar-denominated pricing.
Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of the Liquefaction Supply Derivatives.

The following table shows the changes in the fair value of the Level 3 Liquefaction Supply Derivatives (in millions):
Three Months Ended March 31,
20242023
Balance, beginning of period$(1,676)$(3,719)
Realized and change in fair value gains (losses) included in net income (1):
Included in cost of sales, existing deals (2)(2)1,049 
Included in cost of sales, new deals (3)9 3 
Purchases and settlements:
Purchases (4)  
Settlements (5)34 165 
Transfers out of level 3 (6)  
Balance, end of period$(1,635)$(2,502)
Favorable changes in fair value relating to instruments still held at the end of the period
$7 $1,052 
(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to contractually fixed price from trade date multiplied by contractual volume.  See settlements line item in this table.
(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.
(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.
10

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period.
(5)Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.
(6)Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

All existing counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from those derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when the derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where the derivative instruments are in a liability position. We incorporate both our nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of the derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

Liquefaction Supply Derivatives

We hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of March 31, 2024, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence or accelerate upon the satisfaction of certain events or development of infrastructure to support natural gas gathering and transport.

The forward notional amount for the Liquefaction Supply Derivatives was approximately 6,199 TBtu and 6,245 TBtu as of March 31, 2024 and December 31, 2023, respectively, inclusive of amounts under contracts with unsatisfied contractual conditions, and exclusive of extension options that were uncertain to be taken as of March 31, 2024.

The following table shows the effect and location of the Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations (in millions):
Gain Recognized in Consolidated Statements of Operations
 Consolidated Statements of Operations Location (1)
Three Months Ended March 31,
20242023
Cost of sales$55 $1,260 
(1)Does not include the realized value associated with the Liquefaction Supply Derivatives that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

11

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 the Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):
Fair Value Measurements as of (1)
Consolidated Balance Sheets LocationMarch 31, 2024December 31, 2023
Current derivative assets$37 $30 
Derivative assets59 40 
Total derivative assets96 70 
Current derivative liabilities(144)(196)
Derivative liabilities(1,566)(1,531)
Total derivative liabilities(1,710)(1,727)
Derivative liability, net$(1,614)$(1,657)
(1)Does not include collateral posted with counterparties by us of $1 million and zero as of March 31, 2024 and December 31, 2023, respectively, which is included in other current assets, net on our Consolidated Balance Sheets, and collateral posted by counterparties to us of zero and $4 million as of March 31, 2024 and December 31, 2023, respectively, which is included in other current liabilities on our Consolidated Balance Sheets.

Consolidated Balance Sheets Presentation

The following table shows the fair value of the derivatives outstanding on a gross and net basis (in millions) for the derivative instruments that are presented on a net basis on our Consolidated Balance Sheets:
Liquefaction Supply Derivatives
March 31, 2024December 31, 2023
Gross assets$130 $88 
Offsetting amounts(34)(18)
Net assets$96 $70 
Gross liabilities$(1,713)$(1,746)
Offsetting amounts3 19 
Net liabilities$(1,710)$(1,727)

NOTE 8—ACCRUED LIABILITIES
 
Accrued liabilities consisted of the following (in millions):
 March 31,December 31,
20242023
Natural gas purchases$263 $464 
Interest costs and related debt fees145 256 
LNG terminal and related pipeline costs63 77 
Other accrued liabilities17 9 
Total accrued liabilities $488 $806 

12

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 9—DEBT

Debt consisted of the following (in millions):
March 31,December 31,
20242023
SPL:
Senior Secured Notes:
5.750% due 2024 (the “2024 SPL Senior Notes”)
$150 $300 
5.625% due 2025
2,000 2,000 
5.875% due 2026
1,500 1,500 
5.00% due 2027
1,500 1,500 
4.200% due 2028
1,350 1,350 
4.500% due 2030
2,000 2,000 
4.746% weighted average rate due 2037
1,782 1,782 
Total SPL Senior Secured Notes
10,282 10,432 
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)
  
Total debt - SPL
10,282 10,432 
CQP:
Senior Notes:
4.500% due 2029
1,500 1,500 
4.000% due 2031
1,500 1,500 
3.25% due 2032
1,200 1,200 
5.950% due 2033 (the “2033 CQP Senior Notes”)
1,400 1,400 
Total CQP Senior Notes
5,600 5,600 
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)
  
Total debt - CQP
5,600 5,600 
Total debt15,882 16,032 
Current debt, net of unamortized debt issuance costs(2,145)(300)
Unamortized discount and debt issuance costs(121)(126)
Total long-term debt, net of unamortized discount and debt issuance costs$13,616 $15,606 

Credit Facilities

Below is a summary of our credit facilities outstanding as of March 31, 2024 (in millions):
SPL Revolving Credit Facility
CQP Revolving Credit Facility
Total facility size$1,000 $1,000 
Less:
Outstanding balance  
Letters of credit issued272  
Available commitment$728 $1,000 
Priority rankingSenior securedSenior unsecured
Interest rate on available balance (1)
SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%
SOFR plus credit spread adjustment of 0.1%, plus margin of 1.125% - 2.0% or base rate plus 0.125% - 1.0%
Commitment fees on undrawn balance (1)
0.075% - 0.30%
0.10% - 0.30%
Maturity dateJune 23, 2028June 23, 2028
(1)The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.

13

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

As of March 31, 2024, we and SPL were in compliance with all covenants related to our respective debt agreements.
Interest Expense

Total interest expense, net of capitalized interest, consisted of the following (in millions):
Three Months Ended March 31,
20242023
Total interest cost$204 $210 
Capitalized interest(2)(2)
Total interest expense, net of capitalized interest$202 $208 

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our senior notes (in millions):
March 31, 2024December 31, 2023
 Carrying
Amount
Estimated
Fair Value (1)
Carrying
Amount
Estimated
Fair Value (1)
Senior notes$15,882 $15,345 $16,032 $15,636 
(1)As of both March 31, 2024 and December 31, 2023, $1.3 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

The estimated fair value of our credit facilities approximates the principal amount outstanding because the interest rates are variable and reflective of market rates and the debt may be repaid, in full or in part, at any time without penalty.
NOTE 10—REVENUES

The following table represents a disaggregation of revenue earned (in millions):
Three Months Ended March 31,
20242023
Revenues from contracts with customers
LNG revenues$1,720 $2,106 
LNG revenues—affiliate524 761 
Regasification revenues34 34 
Other revenues17 16 
Total revenues from contracts with customers$2,295 $2,917 


14

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
Contract Assets and Liabilities

The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets, net and other non-current assets, net on our Consolidated Balance Sheets (in millions):
March 31,December 31,
20242023
Contract assets, net of current expected credit losses$1 $1 

The following table reflects the changes in our contract liabilities, which we classify as deferred revenue and other non-current liabilities on our Consolidated Balance Sheets (in millions):
Three Months Ended March 31, 2024
Deferred revenue, beginning of period$190 
Cash received but not yet recognized in revenue168 
Revenue recognized from prior period deferral(190)
Deferred revenue, end of period$168 

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):
Three Months Ended March 31, 2024
Deferred revenue—affiliate, beginning of period$5 
Cash received but not yet recognized in revenue6 
Revenue recognized from prior period deferral(5)
Deferred revenue—affiliate, end of period$6 

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied:
March 31, 2024December 31, 2023
Unsatisfied
Transaction Price
(in billions)
Weighted Average Recognition Timing (years) (1)Unsatisfied
Transaction Price
(in billions)
Weighted Average Recognition Timing (years) (1)
LNG revenues (2)$46.7 8$47.6 8
LNG revenues—affiliate1.1 21.4 2
Regasification revenues0.6 30.7 3
Total revenues$48.4 $49.7 
(1)The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.
(2)We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones such as reaching FID on a certain liquefaction Train, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the transaction price above when the conditions are considered probable of being met and consideration is not otherwise constrained from ultimate pricing and receipt.

The following potential future sources of revenue are omitted from the table above under exemptions we have elected: (1) all performance obligations that are part of a contract that has an original expected duration of one year or less and (2) substantially all variable consideration under our SPAs and TUAs as well as 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 the underlying variable index, primarily Henry Hub, throughout the contract terms, to the extent customers elect to take delivery of their LNG, and
15

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Additionally, we have excluded variable consideration related to volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.

The following table summarizes the amount of variable consideration earned under contracts with customers included in the table above:
Three Months Ended March 31,
20242023
LNG revenues50 %61 %
LNG revenues—affiliate63 %73 %
Regasification revenues8 %7 %

NOTE 11—RELATED PARTY TRANSACTIONS
 
Below is a summary of our transactions with our affiliates and other related parties, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):
Three Months Ended March 31,
20242023
LNG revenues—affiliate
SPAs and Letter Agreements with Cheniere Marketing
$524 $761 
Cost of sales—affiliate
Cheniere Marketing Agreements4  
Contracts for Sale and Purchase of Natural Gas and LNG 17 
Total cost of sales—affiliate4 17 
Operating and maintenance expense—affiliate
Services Agreements (see Note 1)
43 44 
Operating and maintenance expense—related party
Natural Gas Transportation and Storage Agreements (1)13 16 
General and administrative expense—affiliate
Services Agreements (see Note 1)
22 22 
(1)This related party is partially owned by Brookfield, who indirectly owns a portion of our limited partner interests.
We had $32 million and $55 million due to affiliates as of March 31, 2024 and December 31, 2023, respectively, under the agreements with affiliates referenced in the above table.

Disclosures relating to future consideration under revenue contracts with affiliates is included in Note 10—Revenues.

See our annual report on Form 10-K for the fiscal year ended December 31, 2023 for additional information regarding the agreements referenced in the above table, as well as a description of other agreements we have with our affiliates, including the Terminal Marine Services Agreement. Under this agreement, Tug Services distributed $1 million during both the three months ended March 31, 2024 and 2023 to Cheniere Terminals, which is recognized as part of the distributions to our general partner interest holders on our Consolidated Statements of Partners’ Deficit.

NOTE 12—NET INCOME PER COMMON UNIT
 
Net income per common unit for a given period is based on the distributions we incur to the common unitholders with respect to earnings or losses of the reporting period plus an allocation of undistributed net income based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions declared by us
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
during the period are presented on the Consolidated Statements of Partners’ Deficit. On April 29, 2024, we declared a cash distribution of $0.810 per common unit to unitholders of record as of May 9, 2024 and the related general partner distribution to be paid on May 15, 2024 with respect to the three months ended March 31, 2024. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.035 per unit.

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

The following table provides a reconciliation of net income and the allocation of net income to the common units, the subordinated units, the general partner units and IDRs for purposes of computing basic and diluted net income per unit (in millions, except per unit data).
 TotalLimited Partner Common UnitsGeneral Partner Units
IDR
Three Months Ended March 31, 2024
Net income$682 
Declared distributions501 392 10 99 
Assumed allocation of undistributed net income (1)$181 177 4  
Assumed allocation of net income$569 $14 $99 
Weighted average units outstanding484.0 
Basic and diluted net income per unit$1.18 
Three Months Ended March 31, 2023
Net income$1,935 
Declared distributions714 499 14 201 
Assumed allocation of undistributed net income (1)$1,221 1,197 24  
Assumed allocation of net income$1,696 $38 $201 
Weighted average units outstanding484.0 
Basic and diluted net income per unit$3.50 
(1)Under our partnership agreement, the IDRs participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income.
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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 13—CUSTOMER CONCENTRATION
  
The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:
Percentage of Total Revenues from External CustomersPercentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
Three Months Ended March 31,March 31,December 31,
2024202320242023
Customer A24%27%23%22%
Customer B15%17%16%16%
Customer C14%15%29%12%
Customer D13%15%*15%
Customer E12%11%*12%
Customer F*%13%%
* Less than 10%

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION
 
The following table provides supplemental disclosure of substantive cash flow information (in millions):
Three Months Ended March 31,
20242023
Cash paid during the period for interest on debt, net of amounts capitalized$304 $252 
Non-cash investing activity:
 Unpaid purchases of property, plant and equipment20 44 
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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.” All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:
statements regarding our ability to pay distributions to our unitholders; 
statements regarding our expected receipt of cash distributions from SPLNG, SPL or CTPL; 
statements that we expect to commence or complete construction of our proposed LNG terminal, liquefaction facility, pipeline facility or other projects, or any expansions or portions thereof, by certain dates, or at all;
statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
statements regarding our future sources of liquidity and cash requirements;
statements relating to the construction of our Trains, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;
statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;
statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
statements regarding our planned development and construction of additional Trains, including the financing of such Trains;
statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
statements relating to our goals, commitments and strategies in relation to environmental matters;
statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions; and
any other statements that relate to non-historical or future information.
All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially
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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, 2023. 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

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

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

We own a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, which has six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “Liquefaction Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include five LNG storage tanks with aggregate capacity of approximately 17 Bcfe and vaporizers with regasification capacity of approximately 4 Bcf/d, as well as three marine berths, two of which can accommodate vessels with nominal capacity of up to 266,000 cubic meters and the third berth which can accommodate vessels with nominal capacity of up to 200,000 cubic meters. We also own a 94-mile natural gas supply pipeline through our subsidiary, CTPL, that interconnects the Sabine Pass LNG Terminal with several large interstate and intrastate pipelines (the “Creole Trail Pipeline”).

Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted most of our anticipated production capacity under SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and under IPM agreements, in which a gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component,
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which is generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. Through our SPAs and IPM agreement, we have contracted approximately 85% of the total anticipated production from the Liquefaction Project with approximately 14 years of weighted average remaining life as of March 31, 2024, excluding volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation.
We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. We have increased available liquefaction capacity at our Liquefaction Project as a result of debottlenecking and other optimization projects. We believe these factors provide a foundation for additional growth in our portfolio of customer contracts in the future. We hold a significant land position at the Sabine Pass LNG Terminal, which provides opportunity for further liquefaction capacity expansion. We are developing an expansion adjacent to the Liquefaction Project with a total production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “SPL Expansion Project”). In February 2024, certain of our subsidiaries submitted an application to the FERC under the Natural Gas Act (the “NGA”) for authorization to site, construct and operate the SPL Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking. The development of the SPL Expansion Project 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 a positive FID is made.

Additionally, we are committed to the management of our most important ESG impacts, risks and opportunities. In August 2023, Cheniere published The Power of Connection, its fourth Corporate Responsibility (“CR”) report, which details its approach and progress on ESG matters. Cheniere’s CR report is available at cheniere.com/our-responsibility/reporting-center. Information on Cheniere’s website, including the CR report, is not incorporated by reference into this Quarterly Report on Form 10-Q.

Overview of Significant Events

Our significant events since January 1, 2024 and through the filing date of this Form 10-Q include the following:  

Strategic

In February 2024, certain of our subsidiaries submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking.
Operational

As of April 25, 2024, over 2,490 cumulative LNG cargoes totaling over 170 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
Financial

On April 29, 2024, with respect to the first quarter of 2024, we declared a cash distribution of $0.810 per common unit to unitholders of record as of May 9, 2024 and the related general partner distribution to be paid on May 15, 2024. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.035 per unit.
In March 2024, SPL prepaid $150 million of outstanding aggregate principal amount of its 5.750% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”).

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Results of Operations

Three Months Ended March 31,
(in millions, except per unit data)20242023Variance
Revenues
LNG revenues$1,720 $2,106 $(386)
LNG revenues—affiliate524 761 (237)
Regasification revenues34 34 — 
Other revenues17 16 
Total revenues2,295 2,917 (622)
Operating costs and expenses
Cost of sales (excluding items shown separately below)964 313 651 
Cost of sales—affiliate17 (13)
Operating and maintenance expense200 206 (6)
Operating and maintenance expense—affiliate43 44 (1)
Operating and maintenance expense—related party13 16 (3)
General and administrative expense— 
General and administrative expense—affiliate22 22 — 
Depreciation and amortization expense168 167 
Other— 
Total operating costs and expenses1,420 788 632 
Income from operations875 2,129 (1,254)
Other income (expense)
Interest expense, net of capitalized interest(202)(208)
Interest and dividend income14 (5)
Total other expense(193)(194)
Net income$682 $1,935 $(1,253)
Basic and diluted net income per common unit
$1.18 $3.50 $(2.32)
Volumes loaded and recognized from the Liquefaction Project

Three Months Ended March 31,
20242023Variance
LNG volumes loaded and recognized as revenues (in TBtu)417 403 14 
Net income

Substantially all of the unfavorable variance of $1.3 billion in net income for the three months ended March 31, 2024 as compared to the same period of 2023 was attributable to unfavorable changes in fair value and settlements of derivatives of $1.2 billion between the periods. The derivative variance was substantially all due to significant decrease in gains attributable to our IPM agreement with Tourmaline Oil Marketing Corp, which changed from a gain of $1.0 billion in the three months ended March 31, 2023 to a gain of $6 million in the three months ended March 31, 2024, due to moderation of changes in volatility in international gas prices during the current period relative to the same period of 2023. Excluding the aforementioned changes in fair value and settlements of derivatives, LNG revenues, net of cost of sales was relatively consistent between the comparable periods.

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The following is an additional discussion of the significant drivers of the variance in net income by line item:
Revenues

We had a $622 million decrease in revenues between the three months ended March 31, 2024 as compared to the same period of 2023, which was primarily attributable to a $731 million decrease from lower pricing per MMBtu as a result of decreased Henry Hub pricing, partially offset by a $104 million increase from higher production volume largely due to reduced operating and maintenance activities compared to the same period of 2023 and colder weather.

Operating costs and expenses

The $632 million increase between the three months ended March 31, 2024 and 2023 was attributable to a $1.2 billion unfavorable variance from changes in fair value and settlements of derivatives included in cost of sales, from a $1.3 billion gain in the three months ended March 31, 2023 to a $55 million gain in the three months ended March 31, 2024, primarily due to moderating volatility in international gas prices during the current period resulting in decreased non-cash gains in fair value of our commodity derivatives indexed to such prices during the three months ended March 31, 2024, specifically associated with the Tourmaline IPM Agreement as discussed above under Net income. This increase was partially offset by a $567 million decrease in cost of sales excluding the effect of derivative changes described above, primarily as a result of a $515 million decrease in cost of natural gas feedstock largely due to lower U.S. natural gas prices.

Significant factors affecting our results of operations

Below are significant factors that affect our results of operations.

Gains and losses on derivative instruments

Derivative instruments are utilized to manage our exposure to commodity-related marketing and price risks and are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments related to our IPM agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, 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, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

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Liquidity and Capital Resources
 
The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt offerings by us or our subsidiaries and equity offerings by us. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
March 31, 2024
Cash and cash equivalents$333 
Restricted cash and cash equivalents designated for the Liquefaction Project
59 
Available commitments under our credit facilities (1):
SPL Revolving Credit Facility
728 
CQP Revolving Credit Facility
1,000 
Total available commitments under our credit facilities1,728 
Total available liquidity$2,120 
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of March 31, 2024. See Note 9—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

Our liquidity position subsequent to March 31, 2024 will be driven by future sources of liquidity and future cash requirements. For a discussion of our future sources and uses of liquidity, see the liquidity and capital resources disclosures in our annual report on Form 10-K for the fiscal year ended December 31, 2023.

Although our sources and uses of cash are presented below from a consolidated standpoint, we and our subsidiary SPL operate with independent capital structures. Certain restrictions under debt instruments executed by SPL limit its ability to distribute cash, including the following:
SPL is required to deposit all cash received into restricted cash and cash equivalents accounts under certain of their debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments. In addition, SPL’s operating costs are managed by subsidiaries of Cheniere under affiliate agreements, which may require SPL to advance cash to the respective affiliates; and