Nature of Operations and Basis of Presentation |
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| Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Nature of Operations and Basis of Presentation | NATURE OF OPERATIONS AND BASIS OF PRESENTATION
We operate natural gas liquefaction and export facilities located in Cameron Parish, Louisiana at Sabine Pass and near Corpus Christi, Texas (respectively, the “Sabine Pass LNG Terminal” and “Corpus Christi LNG Terminal”), with total expected production capacity of over 60 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which approximately 5 mtpa was under construction and the remainder was in operation as of September 30, 2026, comprised of the following:
•over 30 mtpa of total production capacity in operation from natural gas liquefaction facilities at the Sabine Pass LNG Terminal owned by CQP (the “SPL Project”). The Sabine Pass LNG Terminal also has five LNG storage tanks, vaporizers and three marine berths. CQP also owns and operates 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”). As of September 30, 2026, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP.
•over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including over 25 mtpa in operation and approximately 5 mtpa under construction as of September 30, 2026, from our natural gas liquefaction facilities at the Corpus Christi LNG Terminal, of which we have 100% ownership interest. The Corpus Christi LNG Terminal also has three LNG storage tanks and two marine berths. We also own an approximately 21-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several large interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline”). The project under construction at the Corpus Christi LNG Terminal consists of two midscale Trains that is expected to add total production capacity of approximately 5 mtpa of LNG once fully completed, inclusive of estimated debottlenecking opportunities (the “CCL Midscale Trains 8 & 9 Project” and together with the existing assets at the Corpus Christi LNG Terminal and the Corpus Christi Pipeline, the “CCL Project”).
In addition to the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”), we are developing expansion projects to provide additional liquefaction capacity at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal and are commercializing to support the additional liquefaction capacity associated with these potential expansion projects. At the Sabine Pass LNG Terminal, we are developing a two-phased expansion adjacent to the SPL Project, inclusive of three liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “SPL Expansion Project”). In May 2026, SPL Stage V entered into a lump sum, turnkey EPC contract with Bechtel Energy, Inc. for the first phase of the SPL Expansion Project and has commenced early engineering and procurement pursuant to the limited notices to proceed issued. Additionally, at the Corpus Christi LNG Terminal, we are developing a further expansion adjacent to the CCL Project in a phased approach, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “CCL Expansion Project”). These projects or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, regulatory approvals and acceptable commercial and financing arrangements before our board of directors (our “Board”) makes a positive FID.
Basis of Presentation
The accompanying unaudited Consolidated Financial Statements of Cheniere 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, these Consolidated Financial Statements 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, 2025.
Results of operations for the three and nine months ended September 30, 2026 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2026.
Accounting for Derivative Instruments
In June 2026, we designated the NPNS scope exception under Accounting Standards Codification Topic 815, Derivatives and Hedging, for certain IPM agreements providing for natural gas deliveries along the U.S. Gulf Coast. This designation
comprised approximately 73% of total fixed minimum contractual IPM agreement volumes at the designation date. The remaining 27% of such total volumes was comprised of agreements for which deliveries occur upstream of our liquefaction facilities and were excluded from the NPNS designation. The NPNS exception is available for contracts that are expected to be physically settled and used or sold in the normal course of business, which is consistent with our intended purpose to consume the delivered physical natural gas to produce LNG. Our designation considered increased observable U.S. Gulf Coast third-party physical natural gas market activity involving contracts indexed to global LNG or natural gas prices, among other factors, in evaluating whether the pricing mechanism is consistent with the economics of the underlying physical market. Following the NPNS designation, physical natural gas purchases under these agreements are no longer remeasured at fair value through earnings. Amounts are recognized under the applicable inventory and cost-of-sales guidance as the natural gas is received, consumed in the production process and the related LNG is sold. The estimated fair values of these agreements as of the designation date were established as the new cost basis and are being amortized into cost of sales on a systematic basis over the remaining expected terms of the agreements. Because recognition is based on the timing and volume of contract deliveries, the amounts recognized in any reporting period are expected to vary and are not expected to follow a linear pattern. These non-cash amounts reflect the amortization of deferred gains and losses established at the designation date rather than changes in current-period market prices. If it is determined that the contracts designated as NPNS no longer meet the scope exception, the contracts would be recorded at fair value and any gains and losses would be immediately recognized in earnings.
As a result of the designation, the carrying amounts of the NPNS-designated agreements were reclassified on our Consolidated Balance Sheets as of the designation date from current derivative assets, derivative assets, current derivative liabilities and derivative liabilities as follows (in millions):
The following table presents management’s current estimated net (increase) reduction to cost of sales from the amortization of the remaining balance of the deferred NPNS assets and liabilities as of the designation date (in millions), which is based on estimated recognition periods of contractual delivery schedules as of the Balance Sheet date and may change if contract volumes, delivery timing, or contract modifications differ from current expectations:
(1)For the three and nine months ended September 30, 2026, we recorded a net reduction to cost of sales from amortization of $26 million and $31 million, respectively.
Prior to the designation date, we recognized $2.2 billion of derivative losses during the nine months ended September 30, 2026 and derivative gains of $598 million and $1.5 billion for the three and nine months ended September 30, 2025, respectively, for the designated agreements.
Recent Accounting Standards
ASU 2024-03
In November 2024, the FASB issued ASU No. 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, as clarified by ASU No. 2025-01 in January 2025. This guidance requires disaggregated disclosures about certain income statement expense line
items on an annual and interim basis. We continue to evaluate the impact of the provisions of this guidance on our disclosures, but plan to adopt this guidance prospectively and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2027.
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