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美國
證券交易委員會
華盛頓特區 20549
表格 10-Q
☒根據1934年證券交易法第13或15(d)條款的季度報告。
截至2024年6月30日季度結束 2024年9月30日
或
☐根據1934年證券交易法第13或15(d)條款的過渡報告
過渡期從至
委員會檔案編號 001-33366
cheniere energy partners, L.P.
(正式註冊人的確切名稱，如章程所規定)
德拉瓦
20-5913059
(成立地或組織其他管轄區)
(I.R.S.雇主識別號碼。)
845德克薩斯大道, 1250套房
休斯頓, 德克薩斯77002
(主要行政辦公室的地址)（郵政編碼）
(713) 375-5000
(註冊人電話號碼，包括區號)
根據法律第12(b)條註冊的證券:
每種類別的名稱
交易符號
每個註冊交易所的名稱
代表有限合夥人權益的普通單位
CQP
紐約證券交易所
請以勾選的方式指示登記人是否（1）在過去12個月內（或在登記人需要提交報告的較短期間內）已提交根據1934年證券交易法第13條或15(d)條所要求的所有報告，以及（2）在過去90天內是否受到此類提交要求的約束。Yes ☒ No ☐
(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 11—Net Income per Common Unit.
The accompanying notes are an integral part of these consolidated financial statements.
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 a94-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 10—Related Party Transactions for additional details of the activity under these services agreements during the three and nine months ended September 30, 2024 and 2023.
As of September 30, 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 and nine months ended September 30, 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.
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 September 30, 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—TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES
Trade and other receivables, net of current expected credit losses, consisted of the following (in millions):
September 30,
December 31,
2024
2023
Trade receivables
$
233
$
364
Other receivables
6
9
Total trade and other receivables, net of current expected credit losses
$
239
$
373
NOTE 4—INVENTORY
Inventory consisted of the following (in millions):
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 5—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,
2024
2023
LNG terminal
Terminal and interconnecting pipeline facilities
$
20,250
$
20,176
Construction-in-process
211
189
Accumulated depreciation
(4,669)
(4,173)
Total LNG terminal, net of accumulated depreciation
15,792
16,192
Fixed assets
Fixed assets
32
29
Accumulated depreciation
(27)
(26)
Total fixed assets, net of accumulated depreciation
5
3
Assets under finance leases
Tug vessels
74
23
Accumulated depreciation
(3)
(6)
Total assets under finance leases, net of accumulated depreciation
71
17
Property, plant and equipment, net of accumulated depreciation
$
15,868
$
16,212
Depreciation expense was $169 million and $166 million during the three months ended September 30, 2024 and 2023, respectively, and $505 million and $497 million during the nine months ended September 30, 2024 and 2023, respectively.
NOTE 6—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 our 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
September 30, 2024
December 31, 2023
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)
$
5
$
7
$
(1,376)
$
(1,364)
$
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
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 significantly impact our results of operations if and when such uncertainties are resolved.
The Level 3 fair value measurements of our natural gas positions within the Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of September 30, 2024:
Net Fair Value Liability
(in millions)
Valuation Approach
Significant Unobservable Input
Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives
$(1,376)
Market approach incorporating present value techniques
Henry Hub basis spread
$(0.700) - $0.481 / $0.036
Option pricing model
International LNG pricing spread, relative to Henry Hub (2)
70% - 411% / 185%
(1)Unobservable inputs were weighted by the relative fair value of the instruments.
(2)Spread contemplates U.S. dollar-denominated pricing.
Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of the Liquefaction Supply Derivatives.
The following table shows the changes in the fair value of the Level 3 Liquefaction Supply Derivatives (in millions):
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Balance, beginning of period
$
(1,495)
$
(2,255)
$
(1,676)
$
(3,719)
Realized and change in fair value gains included in net income (1):
Included in cost of sales, existing deals (2)
46
294
163
1,275
Included in cost of sales, new deals (3)
2
8
17
23
Purchases and settlements:
Purchases (4)
—
—
—
—
Settlements (5)
69
59
119
522
Transfers out of level 3 (6)
2
2
1
7
Balance, end of period
$
(1,376)
$
(1,892)
$
(1,376)
$
(1,892)
Favorable changes in fair value relating to instruments still held at the end of the period
$
48
$
302
$
180
$
1,298
(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to the 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.
(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period.
(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.
Liquefaction Supply Derivatives
We hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of September 30, 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 5,744 TBtu and 6,245 TBtu as of September 30, 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 both September 30, 2024 and December 31, 2023.
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 September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Cost of sales
$
152
$
365
$
316
$
1,867
(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.
Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets
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 our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
The following table shows the fair value and location of the Liquefaction Supply Derivatives on our Consolidated Balance Sheets (in millions):
Fair Value Measurements as of (1)
Consolidated Balance Sheets Location
September 30, 2024
December 31, 2023
Current derivative assets
$
50
$
30
Derivative assets
64
40
Total derivative assets
114
70
Current derivative liabilities
(222)
(196)
Derivative liabilities
(1,256)
(1,531)
Total derivative liabilities
(1,478)
(1,727)
Derivative liability, net
$
(1,364)
$
(1,657)
(1)Does not include collateral posted with counterparties by us of $12 million and zero as of September 30, 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 September 30, 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 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
September 30, 2024
December 31, 2023
Gross assets
$
176
$
88
Offsetting amounts
(62)
(18)
Net assets
$
114
$
70
Gross liabilities
$
(1,478)
$
(1,746)
Offsetting amounts
—
19
Net liabilities
$
(1,478)
$
(1,727)
NOTE 7—ACCRUED LIABILITIES
Accrued liabilities consisted of the following (in millions):
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
Credit Facilities
Below is a summary of our credit facilities outstanding as of September 30, 2024 (in millions):
SPL Revolving Credit Facility
CQP Revolving Credit Facility
Total facility size
$
1,000
$
1,000
Less:
Outstanding balance
—
—
Letters of credit issued
234
—
Available commitment
$
766
$
1,000
Priority ranking
Senior secured
Senior 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 date
June 23, 2028
June 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.
Restrictive Debt Covenants
The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us and our restricted subsidiaries’ ability to make certain investments or pay dividends or distributions. SPL is restricted from making distributions under agreements governing its indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied.
As of September 30, 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 September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Total interest cost
$
201
$
207
$
609
$
626
Capitalized interest
(2)
(2)
(6)
(6)
Total interest expense, net of capitalized interest
$
199
$
205
$
603
$
620
Fair Value Disclosures
The following table shows the carrying amount and estimated fair value of our senior notes (in millions):
September 30, 2024
December 31, 2023
Carrying Amount
Estimated Fair Value (1)
Carrying Amount
Estimated Fair Value (1)
Senior notes
$
15,582
$
15,490
$
16,032
$
15,636
(1)As of both September 30, 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 the fair value of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
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 9—REVENUES
The following table represents a disaggregation of revenue earned (in millions):
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Revenues from contracts with customers
LNG revenues
$
1,479
$
1,564
$
4,653
$
5,085
LNG revenues—affiliate
526
515
1,441
1,745
Regasification revenues
34
34
102
101
Other revenues
16
15
48
47
Total revenues from contracts with customers
$
2,055
$
2,128
$
6,244
$
6,978
Contract Assets and Liabilities
The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets, net and other non-current assets, net on our Consolidated Balance Sheets (in millions):
September 30,
December 31,
2024
2023
Contract assets, net of current expected credit losses
$
1
$
1
The following table reflects the changes in our contract liabilities, which we classify as deferred revenue and other non-current liabilities on our Consolidated Balance Sheets (in millions):
Nine Months Ended September 30, 2024
Deferred revenue, beginning of period
$
190
Cash received but not yet recognized in revenue
237
Revenue recognized from prior period deferral
(190)
Deferred revenue, end of period
$
237
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):
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:
September 30, 2024
December 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)
$
45.2
7
$
47.6
8
LNG revenues—affiliate
0.8
1
1.4
2
Regasification revenues
0.6
3
0.7
3
Total revenues
$
46.6
$
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 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:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 10—RELATED PARTY TRANSACTIONS
Below is a summary of our transactions with our affiliates and other related parties, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
LNG revenues—affiliate
SPAs and Letter Agreements with Cheniere Marketing
$
526
$
513
$
1,441
$
1,742
Contracts for Sale and Purchase of Natural Gas and LNG
—
2
—
3
Total LNG revenues—affiliate
526
515
1,441
1,745
Cost of sales—affiliate
Cheniere Marketing Agreements
—
—
4
—
Contracts for Sale and Purchase of Natural Gas and LNG
(1)These arrangements are with a party who indirectly owns a portion of our limited partner interests.
Assets and liabilities arising from the agreements with affiliates and other related parties referenced in the above table are classified as affiliate and related party, respectively, on our Consolidated Balance Sheets.
Disclosures relating to future consideration under revenue contracts with affiliates is included in Note 9—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 $4 million during each of the three months ended September 30, 2024 and 2023 and $8 million during each of the nine months ended September 30, 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 11—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 or loss based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. Distributions declared by us during the period are presented on the Consolidated Statements of Partners’ Deficit. On October 25, 2024, we declared a cash distribution of$0.810per common unit to unitholders of record as of November 4, 2024, and the related general partner distribution, to be paid on November 14, 2024 with respect to the three months ended September 30, 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
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 general partner units and IDRs for purposes of computing basic and diluted net income per unit (in millions, except per unit data).
Total
Limited Partner Common Units
General Partner Units
IDR
Three Months Ended September 30, 2024
Net income
$
635
Declared distributions
501
392
10
99
Assumed allocation of undistributed net income (1)
$
134
132
3
—
Assumed allocation of net income
$
524
$
13
$
99
Weighted average units outstanding
484.0
Basic and diluted net income per unit
$
1.08
Three Months Ended September 30, 2023
Net income
$
791
Declared distributions
714
499
14
201
Assumed allocation of undistributed net income (1)
$
77
75
1
—
Assumed allocation of net income
$
574
$
15
$
201
Weighted average units outstanding
484.0
Basic and diluted net income per unit
$
1.19
Nine Months Ended September 30, 2024
Net income
$
1,887
Declared distributions
1,503
1,176
30
297
Assumed allocation of undistributed net income (1)
$
384
376
8
—
Assumed allocation of net income
$
1,552
$
38
$
297
Weighted average units outstanding
484.0
Basic and diluted net income per unit
$
3.21
Nine Months Ended September 30, 2023
Net income
$
3,348
Declared distributions
2,142
1,496
43
603
Assumed allocation of undistributed net income (1)
$
1,206
1,181
24
—
Assumed allocation of net income
$
2,677
$
67
$
603
Weighted average units outstanding
484.0
Basic and diluted net income per unit
$
5.53
(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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED
(unaudited)
NOTE 12—CUSTOMER CONCENTRATION
The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:
Percentage of Total Revenues from External Customers
Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
Three Months Ended September 30,
Nine Months Ended September 30,
September 30,
December 31,
2024
2023
2024
2023
2024
2023
Customer A
17%
17%
22%
23%
17%
22%
Customer B
18%
17%
15%
16%
*
16%
Customer C
15%
18%
15%
16%
16%
12%
Customer D
16%
15%
14%
15%
12%
15%
Customer E
*
10%
11%
11%
*
12%
Customer F
*
*
*
*
11%
*
* Less than 10%
NOTE 13—SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides supplemental disclosure of substantive cash flow information (in millions):
Nine Months Ended September 30,
2024
2023
Cash paid during the period for interest on debt, net of amounts capitalized
$
671
$
658
Non-cash investing activity:
Unpaid purchases of property, plant and equipment, net (1)
20
31
Right-of-use assets obtained in exchange for lease liabilities:
Operating lease liabilities (2)
3
—
Finance lease liabilities (3)
59
—
(1)Reflects unpaid portion, as of the end of each period, of assets and liabilities recognized during the respective periods.
(2)Net of $33 million reclassified from operating leases to finance leases during the nine months ended September 30, 2024, as a result of modifications of the underlying tug vessel leases.
(3)Net of $15 million reclassified from finance leases to operating leases during the nine months ended September 30, 2024, as a result of modifications of the underlying tug vessel leases.
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
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:
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 includefive 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,
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 80% of the total anticipated production from the Liquefaction Project with approximately 14 years of weighted average remaining life as of September 30, 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 2024, Cheniere published Energy Secured, Benefits Delivered, its fifth 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. In October 2024, the authorization from the DOE to export LNG to FTA countries was received.
Operational
•As of October 25, 2024, approximately 2,700 cumulative LNG cargoes totaling over 185 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Project.
Financial
•On October 25, 2024, with respect to the third quarter of 2024, we declared a cash distribution of $0.810 per common unit to unitholders of record as of November 4, 2024, and the related general partner distribution, to be paid on November 14, 2024. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.035 per unit.
•In May 2024, we issued $1.2 billion aggregate principal amount of 5.750% Senior Notes due 2034 (the “2034 CQP Senior Notes”). In June 2024, the net proceeds, together with cash on hand, were used to retire $1.2 billion outstanding aggregate principal amount of SPL’s 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes”).
•In May 2024, in connection with the 2034 CQP Senior Notes issuance, Moody’s Ratings (“Moody’s”) upgraded our issuer credit rating to Baa2 from Ba1 and revised our outlook to stable from positive. Moody’s also upgraded SPL’s issuer credit rating to Baa1 from Baa2 and revised SPL’s outlook to stable from positive.
•During the three and nine months ended September 30, 2024, SPL repaid $150 million and $450 million, respectively, of outstanding aggregate principal amounts of its senior secured notes.
Results of Operations
Three Months Ended September 30,
Nine Months Ended September 30,
(in millions, except per unit data)
2024
2023
Variance
2024
2023
Variance
Revenues
LNG revenues
$
1,479
$
1,564
$
(85)
$
4,653
$
5,085
$
(432)
LNG revenues—affiliate
526
515
11
1,441
1,745
(304)
Regasification revenues
34
34
—
102
101
1
Other revenues
16
15
1
48
47
1
Total revenues
2,055
2,128
(73)
6,244
6,978
(734)
Operating costs and expenses
Cost of sales (excluding items shown separately below)
773
682
91
2,398
1,598
800
Cost of sales—affiliate
—
2
(2)
4
20
(16)
Operating and maintenance expense
200
211
(11)
610
680
(70)
Operating and maintenance expense—affiliate
41
38
3
123
120
3
Operating and maintenance expense—related party
15
14
1
44
44
—
General and administrative expense
2
2
—
8
8
—
General and administrative expense—affiliate
23
20
3
68
66
2
Depreciation and amortization expense
171
166
5
509
500
9
Other operating costs and expenses
2
4
(2)
10
6
4
Other operating costs and expenses—affiliate
1
1
—
2
1
1
Total operating costs and expenses
1,228
1,140
88
3,776
3,043
733
Income from operations
827
988
(161)
2,468
3,935
(1,467)
Other income (expense)
Interest expense, net of capitalized interest
(199)
(205)
6
(603)
(620)
17
Loss on modification or extinguishment of debt
—
(4)
4
(3)
(6)
3
Interest and dividend income
7
12
(5)
25
39
(14)
Total other expense
(192)
(197)
5
(581)
(587)
6
Net income
$
635
$
791
$
(156)
$
1,887
$
3,348
$
(1,461)
Basic and diluted net income per common unit
$
1.08
$
1.19
$
(0.11)
$
3.21
$
5.53
$
(2.32)
Volumes loaded and recognized from the Liquefaction Project
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Variance
2024
2023
Variance
LNG volumes loaded and recognized as revenues (in TBtu)
Net income declined by $156 million and $1.5 billion between the three and nine months ended September 30, 2024, respectively, as compared to the same periods of 2023. The decline between the respective three and nine month periods was primarily attributable to unfavorable changes in fair value of derivatives of $215 million and $1.6 billion, respectively, principally attributable to our IPM agreement with Tourmaline Oil Marketing Corp, which decreased from $217 million and $1.5 billion during the three and nine months ended September 30, 2023, respectively, to $32 million and $238 million during the three and nine months ended September 30, 2024, respectively, due to the nonrecurrence of significant declines of historic volatility in international gas prices and moderated and sustained spot prices during the current periods relative to the same periods of 2023. The remaining unfavorable changes in fair value of derivatives of $30 million and $352 million during the three and nine month periods ended September 30, 2024, respectively, as compared to the same periods of 2023 were primarily due to an unfavorable shift in long-term U.S. natural gas forward prices.
Partially offsetting the aforementioned unfavorable changes between the three month periods was an increase in LNG revenues, net of cost of sales excluding the aforementioned changes in fair value of derivatives, of $51 million due to an increase in production volume compared to the same period of 2023. Partially offsetting the aforementioned unfavorable changes between the nine month periods was a decrease in maintenance expense of $70 million due to reduced operating and maintenance activities compared to the same period of 2023.
The following is an additional discussion of the significant drivers of the variance in net income by line item:
Revenues
We had $73 million and $734 million decreases in revenues between the three and nine months ended September 30, 2024, respectively, as compared to the same periods of 2023, which was primarily attributable to $137 million and $997 million decreases, respectively, from lower pricing per MMBtu as a result of declining Henry Hub pricing, partially offset by $82 million and $287 million increases, respectively, from higher production volume largely due to reduced maintenance activities compared to the same periods of 2023 and cooler weather.
Operating costs and expenses
The increases in operating costs and expenses of $88 million and $733 million between the three and nine months ended September 30, 2024, respectively, as compared to the same periods of 2023, was primarily attributable to $215 million and $1.6 billion unfavorable variances, respectively, over the same periods from changes in fair value of derivatives included in cost of sales, as discussed above under Net income. The unfavorable variances were partially offset by $125 million and $766 million decreases between the comparative three and nine month periods, respectively, in cost of sales excluding the effect of derivative changes, primarily as a result of $99 million and $661 million decreases, respectively, in cost of natural gas feedstock largely due to lower U.S. natural gas prices.
Significant factor affecting our results of operations
Below is a significant factor that affects 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 6—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, 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.
Liquidity and Capital Resources
The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt offerings by us or our subsidiaries and equity offerings by us. The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.
September 30, 2024
Cash and cash equivalents
$
331
Restricted cash and cash equivalents designated for the Liquefaction Project
80
Available commitments under our credit facilities (1):
SPL Revolving Credit Facility
766
CQP Revolving Credit Facility
1,000
Total available commitments under our credit facilities
1,766
Total available liquidity
$
2,177
(1)Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of September 30, 2024. See Note 8—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.
Our liquidity position subsequent to September 30, 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 or requirements 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
•SPL is restricted by affirmative and negative covenants included in certain of its debt agreements in its ability to make certain payments, including distributions, unless specific requirements are satisfied.
Despite the restrictions noted above, we believe that sufficient flexibility exists to enable each independent capital structure to meet its currently anticipated cash requirements. The sources of liquidity at SPL primarily fund the cash requirements of SPL, and any remaining liquidity not subject to restriction, as supplemented by liquidity provided by our other operations, is available to enable CQP to meet its cash requirements.
Supplemental Guarantor Information
Certain debt obligations of CQP (the “Guaranteed Obligations”) consist of the CQP Revolving Credit Facility, $1.5 billion of 4.500% Senior Notes due 2029, $1.5 billion of 4.000% Senior Notes due 2031, $1.2 billion of 3.25% Senior Notes due 2032, $1.4 billion of 5.950% Senior Notes due 2033 and the 2034 CQP Senior Notes (collectively, the “CQP Senior Notes”), all of which are jointly and severally guaranteed by certain subsidiaries of CQP, as prescribed within the respective debt agreements (each a “Guarantor” and collectively, the “CQP Guarantors”).
The CQP Guarantors’ guarantees of such obligations are full and unconditional, subject to certain release provisions including, as applicable, (1) the sale, disposition or transfer (by merger, consolidation or otherwise) of the capital stock or all or substantially all of the assets of a Guarantor, (2) the liquidation or dissolution of a Guarantor, (3) following the release of a Guarantor from another guarantee that resulted in the creation of its guarantee of the Guaranteed Obligation and (4) 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 respective debt obligation or by declaration of acceleration, call for redemption or otherwise, legal proceedings may be instituted against the CQP Guarantors to enforce the guarantee.
The Guaranteed Obligations contain affirmative and negative covenants that are customary for the respective debt instrument, including, with limited exceptions, restrictions on CQP’s and the CQP Guarantors’ ability to incur additional indebtedness and/or liens, enter into hedging arrangements and/or engage in transactions with affiliates. The Guaranteed Obligations also include events of default that are customary for the respective debt instrument, which are subject to customary grace periods and materiality standards.
The rights of holders of the Guaranteed Obligations 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 CQP Guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance or transfer under U.S. federal or state law. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of the CQP Guarantors. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.
The following tables include summarized financial information of CQP (the “Parent Issuer”), and the CQP Guarantors (together with the Parent Issuer, the “Obligor Group”) on a combined basis. Investments in and equity in the earnings of SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (collectively with SPL, the “Non-Guarantors”), which are not currently members of the Obligor Group, have been excluded. Intercompany balances and transactions between entities in the Obligor Group have been eliminated. Although the creditors of the Obligor Group have no claim against the Non-Guarantors, the Obligor Group may gain access to the assets of the Non-Guarantors upon bankruptcy, liquidation or reorganization of the Non-Guarantors due to its investment in these entities. However, such claims to the assets of the Non-Guarantors would be subordinated to any claims by the Non-Guarantors’ creditors, including trade creditors.
Summarized Balance Sheets (in millions)
September 30,
December 31,
2024
2023
ASSETS
Current assets
Current assets, net
$
370
$
614
Current assets—affiliate
85
86
Current assets with Non-Guarantors
40
56
Total current assets
495
756
Non-current assets, net
3,043
3,025
Total assets
$
3,538
$
3,781
LIABILITIES
Current liabilities
Current liabilities
$
154
$
155
Current liabilities—affiliate
34
46
Current liabilities due to Non-Guarantors
93
100
Total current liabilities
281
301
Long-term debt, net of premium, discount and debt issuance costs
The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash and cash equivalents (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.
Nine Months Ended September 30,
2024
2023
Net cash provided by operating activities
$
2,092
$
2,193
Net cash used in investing activities
(112)
(176)
Net cash used in financing activities
(2,200)
(2,479)
Net decrease in cash, cash equivalents and restricted cash and cash equivalents
$
(220)
$
(462)
Operating Cash Flows
The $101 million decrease between the periods was primarily related to cash flows attributed to working capital, mainly due to differences in timing of payments to suppliers and cash collections from the sale of LNG cargoes.
Investing Cash Flows
Cash outflows for property, plant and equipment during the nine months ended September 30, 2024 and 2023 were primarily related to optimization and other site improvement projects.
Financing Cash Flows
The following table summarizes our financing activities (in millions):
Nine Months Ended September 30,
2024
2023
Proceeds from issuances of debt
$
1,228
$
1,397
Redemptions and repayments of debt
(1,680)
(1,650)
Debt issuance and other financing costs
(15)
(32)
Distributions
(1,729)
(2,190)
Other
(4)
(4)
Net cash used in financing activities
$
(2,200)
$
(2,479)
Debt Activity
During the nine months ended September 30, 2024, we issued an aggregate amount of $1.2 billion of 2034 CQP Senior Notes and used the proceeds and cash on hand to retire $1.2 billion outstanding aggregate principal amount of the 2025 SPL Senior Notes. Additionally, during the nine months ended September 30, 2024, SPL repaid the outstanding aggregate principal amount of $300 million of the 5.750% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) and $150 million of the 2025 SPL Senior Notes. We also borrowed and repaid $30 million under the SPL Revolving Credit Facility during the nine months ended September 30, 2024. During the nine months ended September 30, 2023, we issued an aggregate amount of $1.4 billion of 2033 CQP Senior Notes and used the proceeds and cash on hand to redeem $1.4 billion of the 2024 SPL Senior Notes. Additionally, during the nine months ended September 30, 2023, SPL purchased $200 million of the 2024 SPL Senior Notes in the open market and redeemed an additional $50 million of the 2024 SPL Senior Notes.
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 nine months ended September 30, 2024 and 2023:
Total Distribution (in millions)
Date Paid
Period Covered by Distribution
Distribution Per Common Unit
Common Units
General Partner Units
Incentive Distribution Rights
August 14, 2024
April 1 - June 30, 2024
$
0.810
$
392
$
10
$
99
May 15, 2024
January 1 - March 31, 2024
0.810
392
10
99
February 14, 2024
October 1 - December 31, 2023
1.035
501
14
204
August 14, 2023
April 1 - June 30, 2023
1.030
499
14
201
May 15, 2023
January 1 - March 31, 2023
1.030
499
14
201
February 14, 2023
October 1 - December 31, 2022
1.070
518
15
220
In addition, Tug Services distributed $8 million during the nine months ended September 30, 2024 and 2023, respectively, to Cheniere Terminals in accordance with their terminal marine service agreement, which is recognized as part of the distributions to the holder of our general partner interest.
On October 25, 2024, with respect to the third quarter of 2024, we declared a cash distribution of $0.810 per common unit to unitholders of record as of November 4, 2024, and the related general partner distribution, to be paid on November 14, 2024. These distributions consist of a base amount of $0.775 per unit and a variable amount of $0.035per 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, 2023.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Marketing and Trading Commodity Price Risk
We have commodity derivatives consisting of natural gas supply contracts for the operation of the Liquefaction Project (the “Liquefaction Supply Derivatives”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location as follows (in millions):
September 30, 2024
December 31, 2023
Fair Value
Change in Fair Value
Fair Value
Change in Fair Value
Liquefaction Supply Derivatives
$
(1,364)
$
334
$
(1,657)
$
362
See Note 6—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our derivative instruments.
ITEM 4. CONTROLS AND PROCEDURES
We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our general partner’s management, including our general partner’s Chief Executive Officer and Chief Financial Officer, the
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.
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. There have been no material changes to the legal proceedings disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2023.
Rule 10b5-1 under the Exchange Act provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits the directors and executive officers of our general partner to enter into trading plans designed to comply with Rule 10b5-1. During the three-month period ending September 30, 2024, none of the executive officers or directors of our general partner adopted or terminated a Rule 10b5-1 trading plan or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*
Filed herewith.
**
Furnished herewith.
31
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:
October 30, 2024
By:
/s/ Zach Davis
Zach Davis
Executive Vice President and Chief Financial Officer
(on behalf of the registrant and as principal financial officer)
Date:
October 30, 2024
By:
/s/ David Slack
David Slack
Senior Vice President and Chief Accounting Officer
(on behalf of the registrant and as principal accounting officer)
