Document and Entity Information
Document and Entity Information $ in Millions | 12 Months Ended |
Dec. 31, 2022 USD ($) shares | |
Cover [Abstract] | |
Document Type | 10-K |
Document Annual Report | true |
Document Period End Date | Dec. 31, 2022 |
Document Transition Report | false |
Entity File Number | 333-215435 |
Entity Registrant Name | Cheniere Corpus Christi Holdings, LLC |
Entity Incorporation, State or Country Code | DE |
Entity Tax Identification Number | 47-1929160 |
Entity Address, Address Line One | 700 Milam Street |
Entity Address, Address Line Two | Suite 1900 |
Entity Address, City or Town | Houston |
Entity Address, State or Province | TX |
Entity Address, Postal Zip Code | 77002 |
City Area Code | 713 |
Local Phone Number | 375-5000 |
Title of 12(b) Security | None |
Entity Well-known Seasoned Issuer | No |
Entity Voluntary Filers | Yes |
Entity Current Reporting Status | No |
Entity Interactive Data Current | Yes |
Entity Filer Category | Non-accelerated Filer |
Entity Small Business | false |
Entity Emerging Growth Company | false |
ICFR Auditor Attestation Flag | false |
Entity Shell Company | false |
Documents Incorporated by Reference | None |
Entity Central Index Key | 0001693317 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Document Fiscal Year Focus | 2022 |
Document Fiscal Period Focus | FY |
No Trading Symbol Flag | true |
Entity Common Stock, Shares Outstanding | shares | 0 |
Entity Public Float | $ | $ 0 |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2022 | |
Audit Information [Abstract] | |
Auditor Name | KPMG LLP |
Auditor Location | Houston, Texas |
Auditor Firm ID | 185 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Revenues | ||||
Revenues | $ 9,363 | $ 5,794 | $ 2,529 | |
Revenues from contracts with customers | 9,362 | 5,790 | 2,530 | |
Operating costs and expenses | ||||
Cost of sales (excluding items shown separately below) | 9,656 | 4,326 | 901 | |
Cost of sales—affiliate | 103 | 50 | 30 | |
Cost of sales—related party | 0 | 146 | 114 | |
Operating and maintenance expense | 458 | 423 | 347 | |
Operating and maintenance expense—affiliate | 121 | 106 | 90 | |
Operating and maintenance expense—related party | 9 | 9 | 6 | |
General and administrative expense | 8 | 7 | 7 | |
General and administrative expense—affiliate | 38 | 28 | 20 | |
Depreciation and amortization expense | 445 | 420 | 342 | |
Other | 6 | 2 | 1 | |
Total operating costs and expenses | 10,844 | 5,517 | 1,858 | |
Income (loss) from operations | (1,481) | 277 | 671 | |
Other income (expense) | ||||
Interest expense, net of capitalized interest | (432) | (447) | (365) | |
Loss on modification or extinguishment of debt | (37) | (9) | (9) | |
Interest rate derivative gain (loss), net | 2 | (1) | (233) | |
Other income (expense), net | 6 | 0 | (1) | |
Total other expense | (461) | (457) | (608) | |
Net income (loss) | (1,942) | (180) | 63 | |
LNG [Member] | ||||
Revenues | ||||
Revenues | 6,336 | 3,907 | 2,046 | |
Revenues from contracts with customers | [1] | 6,335 | 3,903 | 2,047 |
LNG—affiliate [Member] | ||||
Revenues | ||||
Revenues from contracts with customers | $ 3,027 | $ 1,887 | $ 483 | |
[1]LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized during the year ended December 31, 2021 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2022 and 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied. |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Current assets | ||
Restricted cash and cash equivalents | $ 738 | $ 44 |
Trade and other receivables, net of current expected credit losses | 348 | 280 |
Accounts receivable—affiliate | 240 | 315 |
Advances to affiliate | 132 | 128 |
Inventory | 178 | 156 |
Current derivative assets | 12 | 17 |
Margin deposits | 76 | 13 |
Other current assets | 18 | 15 |
Total current assets | 1,742 | 968 |
Property, plant and equipment, net of accumulated depreciation | 13,673 | 12,607 |
Debt issuance and deferred financing costs, net of accumulated amortization | 40 | 7 |
Derivative assets | 7 | 37 |
Other non-current assets, net | 225 | 145 |
Total assets | 15,687 | 13,764 |
Current liabilities | ||
Accounts payable | 85 | 119 |
Accrued liabilities | 901 | 631 |
Accrued liabilities—related party | 1 | 1 |
Current debt, net of discount and debt issuance costs | 495 | 366 |
Due to affiliates | 43 | 35 |
Current derivative liabilities | 1,374 | 668 |
Other current liabilities | 1 | 1 |
Total current liabilities | 2,900 | 1,821 |
Long-term debt, net of discount and debt issuance costs | 6,698 | 9,986 |
Derivative liabilities | 4,923 | 638 |
Other non-current liabilities | 78 | 38 |
Other non-current liabilities—affiliate | 4 | 0 |
Commitments and contingencies | ||
Member’s equity | 1,084 | 1,281 |
Total liabilities and member’s equity | $ 15,687 | $ 13,764 |
Consolidated Statements of Memb
Consolidated Statements of Member's Equity - USD ($) $ in Millions | Total | Cheniere CCH HoldCo I, LLC [Member] |
Member's equity, beginning of period at Dec. 31, 2019 | $ 2,418 | $ 2,418 |
Contributions | 145 | 145 |
Distributions | (2) | (2) |
Net income (loss) | 63 | 63 |
Member's equity, end of period at Dec. 31, 2020 | 2,624 | 2,624 |
Distributions | (1,163) | (1,163) |
Net income (loss) | (180) | (180) |
Member's equity, end of period at Dec. 31, 2021 | 1,281 | 1,281 |
Contributions | 2,182 | 2,182 |
Contribution of CCL Stage III entity | (1,482) | (1,482) |
Non-cash contribution from affiliate | 1,245 | 1,245 |
Distributions | (200) | (200) |
Net income (loss) | (1,942) | (1,942) |
Member's equity, end of period at Dec. 31, 2022 | $ 1,084 | $ 1,084 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Cash flows from operating activities | |||
Net income (loss) | $ (1,942) | $ (180) | $ 63 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation and amortization expense | 445 | 420 | 342 |
Amortization of discount and debt issuance costs | 20 | 24 | 20 |
Loss on modification or extinguishment of debt | 37 | 9 | 9 |
Total losses on derivative instruments, net | 3,243 | 1,241 | 261 |
Total gains on derivatives, net—related party | 0 | (11) | 1 |
Net cash used for settlement of derivative instruments | (155) | (107) | (174) |
Other | 33 | 3 | 4 |
Changes in operating assets and liabilities: | |||
Trade and other receivables, net of current expected credit losses | (68) | (84) | (138) |
Accounts receivable—affiliate | 76 | (273) | 15 |
Advances to affiliate | (58) | 14 | (11) |
Inventory | (22) | (62) | (18) |
Margin deposits | (63) | (8) | 0 |
Accounts payable and accrued liabilities | 184 | 468 | 63 |
Accrued liabilities—related party | 0 | (14) | 11 |
Due to affiliates | 7 | 9 | 5 |
Deferred revenue | 42 | 35 | 0 |
Other, net | (44) | (60) | (56) |
Other, net—affiliate | (1) | 0 | (1) |
Net cash provided by operating activities | 1,734 | 1,424 | 396 |
Cash flows from investing activities | |||
Property, plant and equipment | (981) | (238) | (790) |
Other | 1 | (2) | (6) |
Net cash used in investing activities | (980) | (240) | (796) |
Cash flows from financing activities | |||
Proceeds from issuances of debt | 440 | 1,150 | 1,050 |
Repayments of debt | (2,419) | (1,188) | (797) |
Debt issuance and deferred financing costs | (44) | (4) | (8) |
Debt extinguishment costs | (19) | (5) | 0 |
Contributions | 2,182 | 0 | 145 |
Distributions | (200) | (1,163) | 0 |
Net cash used in financing activities | (60) | (1,210) | 390 |
Net increase (decrease) in restricted cash and cash equivalents | 694 | (26) | (10) |
Restricted cash and cash equivalents—beginning of period | 44 | 70 | 80 |
Restricted cash and cash equivalents—end of period | $ 738 | $ 44 | $ 70 |
Organization and Nature of Oper
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | ORGANIZATION AND NATURE OF OPERATIONS We operate a natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”) through CCL, which has three operational Trains for a total operational production capacity of approximately 15 mtpa of LNG, three LNG storage tanks and two marine berths. Additionally, we are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for up to seven midscale Trains with an expected total operational production capacity of over 10 mtpa of LNG. CCL Stage III, CCL and CCP received approval from FERC in November 2019 to site, construct and operate the Corpus Christi Stage 3 Project. In March 2022, CCL Stage III issued limited notice to proceed to Bechtel Energy Inc. (“Bechtel”) to commence early engineering, procurement and site works. In June 2022, Cheniere’s board of directors made a positive FID with respect to the investment in the construction and operation of the Corpus Christi Stage 3 Project and issued a full notice to proceed with construction to Bechtel effective June 16, 2022. In connection with the positive FID, CCL Stage III, through which Cheniere was developing and constructing the Corpus Christi Stage 3 Project, was contributed to us from Cheniere (the “Contribution”) on June 15, 2022. Immediately following the Contribution, CCL Stage III was merged with and into CCL (the “Merger”), the surviving entity of the merger and our wholly owned subsidiary. Refer to Note 3 —CCL Stage III Contribution and Merger for additional information on the Contribution and Merger of CCL Stage III. Through our subsidiary CCP, we also own a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the existing operational Trains, midscale Trains, storage tanks and marine berths, the “Liquefaction Project”). |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Our Consolidated Financial Statements have been prepared in accordance with GAAP. Our Consolidated Financial Statements include the accounts of CCH and its subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Use of Estimates The preparation of our 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. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments useful lives of property, plant and equipment and asset retirement obligations (“AROs”), as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market. In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates. Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 8—Derivative Instruments . The carrying amount of restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, contract assets, margin deposits, accounts payable and accrued liabilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 11—Debt , are based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments using observable or unobservable inputs. Revenue Recognition We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 12—Revenues for further discussion of our revenue streams and accounting policies related to revenue recognition. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Current Expected Credit Losses Trade and other receivables and contract assets are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status, and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Consolidated Statements of Operations. As of both December 31, 2022 and 2021, we had current expected credit losses of zero on our trade and other receivables, and as of December 31, 2022 and 2021, we had current expected credit losses of $4 million and $3 million, respectively, on our non-current contract assets. Inventory LNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or, for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method. Property, Plant and Equipment Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. Generally, we begin capitalizing the costs of our LNG terminal once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminal. Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets. We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction. We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives. Refer to Note 7—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses on disposal are recorded in other operating costs and expenses. Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We did not record any material impairments related to property, plant and equipment during the years ended December 31, 2022, 2021 and 2020. Interest Capitalization We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. Upon placing the underlying asset in service, these costs are transferred out of construction-in-process into the respective in-service asset category and depreciated over the estimated useful life of the corresponding assets, except for capitalized interest associated with land, which is not depreciated. Regulated Natural Gas Pipelines The Corpus Christi Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are classified in our Consolidated Balance Sheets as other assets and other liabilities. Upon a triggering event, we evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to write off the associated regulatory assets and liabilities. Items that may influence our assessment are: • inability to recover cost increases due to rate caps and rate case moratoriums; • inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings; • excess capacity; • increased competition and discounting in the markets we serve; and • impacts of ongoing regulatory initiatives in the natural gas industry. Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipeline. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipeline is placed in service. Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception, under which we account for the instrument under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis. For those derivative instruments measured at fair value, changes in the fair value of the instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did not have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2022, 2021 and 2020. See Note 8—Derivative Instruments for additional details about our derivative instruments. Concentration of Credit Risk Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable related to our long-term SPAs, as discussed further below. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within margin deposits. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments. CCL has entered into fixed price long-term SPAs generally with terms of 20 years with 15 third parties and have entered into agreements with Cheniere Marketing International LLP (“Cheniere Marketing”). CCL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 15—Customer Concentration for additional details about our customer concentration. Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Debt Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors. Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees, printing costs and in certain cases, commitment fees. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in loss on modification or extinguishment of debt on our Consolidated Statements of Operations. We classify debt on our Consolidated Balance Sheets based on contractual maturity, with the following exceptions: • We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement. • We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date. Asset Retirement Obligations We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. We have not recorded an ARO associated with the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly. Income Taxes We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is included in the consolidated federal income tax return of Cheniere. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements. Business Segment Our liquefaction and pipeline business at the Corpus Christi LNG Terminal represents a single reportable segment. Our chief operating decision maker reviews the financial results of CCH in total when evaluating financial performance and for purposes of allocating resources. Recent Accounting Standards ASU 2020-04 In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting . This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing contracts expected to arise from the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard. We had interest rate swaps and various credit facilities indexed to LIBOR, as further described in Note 8 —Derivative Instruments and Note 11 —Debt , respectively. In June 2022, we amended our credit facilities to bear interest at a variable rate per annum based on SOFR as a result of the expected LIBOR transition. Since adoption of the standard, we elected to apply the optional expedients as applicable to certain modified facilities; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows. |
CCL Stage III Contribution and
CCL Stage III Contribution and Merger | 12 Months Ended |
Dec. 31, 2022 | |
Business Combination and Asset Acquisition [Abstract] | |
CCL Stage III Contribution and Merger | CCL STAGE III CONTRIBUTION AND MERGER As described in Note 1— Organization and Nature of Operations , the Contribution of the CCL Stage III legal entity to us from Cheniere occurred on June 15, 2022, which was immediately followed by the Merger, in which CCL Stage III was merged with and into CCL, with CCL continuing as the surviving company. The Contribution was accounted for as a common control transaction as the assets and liabilities were transferred between entities under Cheniere’s control. As a result, the net liability transfer was recognized as a contribution in our Consolidated Statement of Member’s Equity and at the historical basis of Cheniere on June 15, 2022 in our Consolidated Balance Sheets. The Contribution has been presented prospectively as we have concluded that the Contribution did not represent a change in our reporting entity, primarily as we concluded that CCL Stage III did not constitute a business under FASB topic Accounting Standards Codification 805, Business Combinations . The Merger had no impact on our Consolidated Financial Statements as it occurred between our consolidated subsidiaries. The net liabilities of CCL Stage III contributed to us and recognized on our Consolidated Balance Sheets on June 15, 2022 consisted of the following (in millions): June 15, 2022 ASSETS Property, plant and equipment, net of accumulated depreciation $ 441 Derivatives assets 112 Other non-current assets, net 19 Total assets $ 572 LIABILITIES Current liabilities Accounts payable $ 3 Due to affiliates 1 Total current liabilities 4 Derivative liabilities 2,050 Total net liabilities contributed $ (1,482) Amended and Restated Debt Agreements In June 2022, in connection with the FID with respect to the Corpus Christi Stage 3 Project referenced above, CCH amended and restated its term loan credit facility (the “CCH Credit Facility”) and its working capital facility (“CCH Working Capital Facility”) to, among other things, (1) increase the commitments to approximately $4.0 billion and $1.5 billion for the CCH Credit Facility and the CCH Working Capital Facility, respectively, (2) extend the maturity of the CCH Credit Facility to the earlier of June 15, 2029 or two years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project and of the CCH Working Capital Facility through June 15, 2027, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of the existing facility. See Note 11—Debt for additional information on our credit facilities. |
Restricted Cash and Cash Equiva
Restricted Cash and Cash Equivalents | 12 Months Ended |
Dec. 31, 2022 | |
Restricted Cash and Cash Equivalents [Abstract] | |
Restricted Cash and Cash Equivalents | RESTRICTED CASH AND CASH EQUIVALENTS Pursuant to the accounts agreement entered into with the collateral trustee for the benefit of our debt holders, we are required to deposit all cash received into reserve accounts controlled by the collateral trustee. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Project and other restricted payments. As of December 31, 2022 and 2021, we had $738 million and $44 million of restricted cash and cash equivalents, respectively, as required by the above agreement, of which $498 million as of December 31, 2022 related to the cash contributed from Cheniere for the redemption of the remaining outstanding principal balance of the 7.000% Senior Notes due 2024 (the “2024 CCH Senior Notes”) in January 2023. |
Trade and Other Receivables, Ne
Trade and Other Receivables, Net of Current Expected Credit Losses | 12 Months Ended |
Dec. 31, 2022 | |
Receivables [Abstract] | |
Trade and Other Receivables, Net of Current Expected Credit Losses | TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES Trade and other receivables, net of current expected credit losses consisted of the following (in millions): December 31, 2022 2021 Trade receivables $ 319 $ 256 Other receivables 29 24 Total trade and other receivables, net of current expected credit losses $ 348 $ 280 |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2022 | |
Inventory Disclosure [Abstract] | |
Inventory | INVENTORY Inventory consisted of the following (in millions): December 31, 2022 2021 Materials $ 92 $ 88 LNG 53 45 Natural gas 31 21 Other 2 2 Total inventory $ 178 $ 156 |
Property, Plant and Equipment,
Property, Plant and Equipment, Net of Accumulated Depreciation | 12 Months Ended |
Dec. 31, 2022 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment, Net of Accumulated Depreciation | PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions): December 31, 2022 2021 LNG terminal Terminal and interconnecting pipeline facilities $ 13,299 $ 13,222 Site and related costs 302 294 Construction-in-process 1,486 66 Accumulated depreciation (1,421) (981) Total LNG terminal, net of accumulated depreciation 13,666 12,601 Fixed assets Fixed assets 26 23 Accumulated depreciation (19) (17) Total fixed assets, net of accumulated depreciation 7 6 Property, plant and equipment, net of accumulated depreciation $ 13,673 $ 12,607 The following table shows depreciation expense and offsets to LNG terminal costs (in millions): Year Ended December 31, 2022 2021 2020 Depreciation expense $ 444 $ 419 $ 341 Offsets to LNG terminal costs (1) — 143 32 (1) We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction. LNG Terminal Costs LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 6 and 50 years, as follows: Components Useful life (years) LNG storage tanks 50 Natural gas pipeline facilities 40 Marine berth, electrical, facility and roads 35 Water pipelines 30 Liquefaction processing equipment 6-50 Other 15-30 Fixed Assets Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | DERIVATIVE INSTRUMENTS We have entered into the following derivative instruments: • interest rate swaps (“CCH Interest Rate Derivatives”) to hedge the exposure to volatility in a portion of the floating-rate interest payments on our CCH Credit Facility, which expired in May 2022, and previously, to hedge against changes in interest rates that could impact anticipated future issuances of debt by CCH (the “Interest Rate Forward Start Derivatives” and, collectively with the CCH Interest Rate Derivatives, the “Interest Rate Derivatives”), which were settled in August 2020; and • commodity derivatives consisting of natural gas and power supply contracts, including those under our IPM agreements, for the development, commissioning and operation of the Liquefaction Project and associated economic hedges (collectively, “Liquefaction Supply Derivatives”). We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow or fair value hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process, in which case 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 (in millions): Fair Value Measurements as of December 31, 2022 December 31, 2021 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Interest Rate Derivatives liability $ — $ — $ — $ — $ — $ (40) $ — $ (40) Liquefaction Supply Derivatives asset (liability) (54) (19) (6,205) (6,278) 5 4 (1,221) (1,212) We valued our Interest Rate Derivatives using an income-based approach utilizing observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data. We value our Liquefaction Supply Derivatives using a market or option-based approach incorporating present value techniques, as needed, using observable commodity price curves, when available, and other relevant data. The fair value of our Liquefaction Supply Derivatives is predominantly driven by observable and unobservable market commodity prices and, as applicable to our natural gas supply contracts, our assessment of the associated events deriving fair value, including, but not limited to, evaluation of whether the respective market exists from the perspective of market participants as infrastructure is developed. We include a significant portion of our Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks, such as future prices of energy units for unobservable periods, liquidity and volatility. The Level 3 fair value measurements of natural gas positions within our Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of December 31, 2022: Net Fair Value Liability Valuation Approach Significant Unobservable Input Range of Significant Unobservable Inputs / Weighted Average (1) Liquefaction Supply Derivatives $(6,205) Market approach incorporating present value techniques Henry Hub basis spread $(1.049) - $0.160 / $(0.258) Option pricing model International LNG pricing spread, relative to Henry Hub (2) 73% - 532% / 157% (1) Unobservable inputs were weighted by the relative fair value of the instruments. (2) Spread contemplates U.S. dollar-denominated pricing. Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of our Liquefaction Supply Derivatives. The following table shows the changes in the fair value of our Level 3 Liquefaction Supply Derivatives (in millions): Year Ended December 31, 2022 2021 (1) 2020 Balance, beginning of period $ (1,221) $ 12 $ 35 Realized and change in fair value gains (losses) included in net income (2): Included in cost of sales, existing deals (3) (1,492) (1,276) 28 Included in cost of sales, new deals (4) (2,172) — — Purchases and settlements: Purchases (5) (1,938) 9 — Settlements (6) 618 34 (58) Transfers in and/or out of level 3 Transfers into level 3 (7) — — 7 Balance, end of period $ (6,205) $ (1,221) $ 12 Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period $ (3,664) $ (1,276) $ 28 (1) Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 13—Related Party Transactions . (2) 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. (3) Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period. (4) Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period. (5) Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period. For further discussion of IPM agreements that were novated to us during the period, see Note 3—CCL Stage III Contribution and Merger . (6) 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. (7) Transferred into level 3 as a result of unobservable 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 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. Interest Rate Derivatives We previously entered into the following Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the CCH Credit Facility, which expired in May 2022: Notional Amounts December 31, 2022 December 31, 2021 Weighted Average Fixed Interest Rate Paid Variable Interest Rate Received CCH Interest Rate Derivatives $— $4.5 billion 2.30% One-month LIBOR The following table shows the effect and location of our Interest Rate Derivatives on our Consolidated Statements of Operations (in millions): Gain (Loss) Recognized in Consolidated Statements of Operations Consolidated Statements of Operations Location Year Ended December 31, 2022 2021 2020 CCH Interest Rate Derivatives Interest rate derivative gain (loss), net $ 2 $ (1) $ (138) CCH Interest Rate Forward Start Derivatives Interest rate derivative gain (loss), net — — (95) Liquefaction Supply Derivatives CCL holds Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. The terms of the Liquefaction Supply Derivatives range up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs. The forward notional amount for our Liquefaction Supply Derivatives was approximately 8,532 TBtu and 2,915 TBtu as of December 31, 2022 and 2021, respectively. The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations (in millions): Gain (Loss) Recognized in Consolidated Statements of Operations Consolidated Statements of Operations Location (1) Year Ended December 31, 2022 2021 2020 LNG revenues $ 1 $ 4 $ (1) Cost of sales (3,246) (1,244) (27) Cost of sales—related party (2) — 11 (1) (1) Does not include the value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument. (2) Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement during 2021 as discussed in Note 13—Related Party Transactions . Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets The following table shows the fair value and location of our derivative instruments on our Consolidated Balance Sheets (in millions): December 31, 2022 CCH Interest Rate Derivatives Liquefaction Supply Derivatives (1) Total Consolidated Balance Sheets Location Current derivative assets $ — $ 12 $ 12 Derivative assets — 7 7 Total derivative assets — 19 19 Current derivative liabilities — (1,374) (1,374) Derivative liabilities — (4,923) (4,923) Total derivative liabilities — (6,297) (6,297) Derivative liability, net $ — $ (6,278) $ (6,278) December 31, 2021 CCH Interest Rate Derivatives Liquefaction Supply Derivatives (1) Total Consolidated Balance Sheets Location Current derivative assets $ — $ 17 $ 17 Derivative assets — 37 37 Total derivative assets — 54 54 Current derivative liabilities (40) (628) (668) Derivative liabilities — (638) (638) Total derivative liabilities (40) (1,266) (1,306) Derivative liability, net $ (40) $ (1,212) $ (1,252) (1) Does not include collateral posted with counterparties by us of $76 million and $13 million as of December 31, 2022 and 2021, respectively, which are included in other current assets in our Consolidated Balance Sheets. Includes a natural gas supply contract that we had with a related party. This agreement ceased to be considered a related party agreement as of November 1, 2021. 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: CCH Interest Rate Derivatives Liquefaction Supply Derivatives As of December 31, 2022 Gross assets $ — $ 19 Offsetting amounts — — Net assets $ — $ 19 Gross liabilities $ — $ (6,622) Offsetting amounts — 325 Net liabilities $ — $ (6,297) As of December 31, 2021 Gross assets $ — $ 76 Offsetting amounts — (22) Net assets $ — $ 54 Gross liabilities $ (40) $ (1,295) Offsetting amounts — 29 Net liabilities $ (40) $ (1,266) |
Other Non-Current Assets, Net
Other Non-Current Assets, Net | 12 Months Ended |
Dec. 31, 2022 | |
Other Assets, Noncurrent [Abstract] | |
Other Non-Current Assets, Net | OTHER NON-CURRENT ASSETS, NET Other non-current assets, net consisted of the following (in millions): December 31, 2022 2021 Contract assets, net of current expected credit losses $ 142 $ 103 Advances and other asset conveyances to third parties to support LNG terminal 62 24 Operating lease assets 6 4 Information technology service prepayments 3 3 Tax-related payments and receivables 3 2 Other 9 9 Total other non-current assets, net $ 225 $ 145 |
Accrued Liabilities
Accrued Liabilities | 12 Months Ended |
Dec. 31, 2022 | |
Accrued Liabilities, Current [Abstract] | |
Accrued Liabilities | ACCRUED LIABILITIES Accrued liabilities consisted of the following (in millions): December 31, 2022 2021 Natural gas purchases $ 597 $ 531 Interest costs and related debt fees 150 7 Liquefaction Project costs 103 43 Other accrued liabilities 51 50 Total accrued liabilities $ 901 $ 631 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Debt | DEBT Debt consisted of the following (in millions): December 31, 2022 2021 Senior Secured Notes: 2024 CCH Senior Notes (1) $ 498 $ 1,250 5.875% due 2025 1,491 1,500 5.125% due 2027 (2) 1,271 1,500 3.700% due 2029 (2) 1,361 1,500 3.751% weighted average rate due 2039 (2) 2,633 2,721 Total Senior Secured Notes 7,254 8,471 CCH Credit Facility — 1,728 CCH Working Capital Facility (3) — 250 Total debt 7,254 10,449 Current portion of long-term debt (495) (117) Short-term debt — (250) Unamortized discount and debt issuance costs, net (61) (96) Total long-term debt, net of discount and debt issuance costs $ 6,698 $ 9,986 (1) In January 2023, we redeemed the remaining outstanding principal balance of the 2024 CCH Senior Notes with cash that was contributed to us from Cheniere prior to December 31, 2022. Therefore, the outstanding principal balance redeemed was classified as current portion of long-term debt as of December 31, 2022 net of discount and debt issuance costs of $3 million. (2) Subsequent to December 31, 2022 and through February 16, 2023, Cheniere executed bond repurchases totaling $322 million, inclusive of CCH’s Senior Secured Notes due 2027, 2029 and 2039 on the open market, which were immediately contributed to us from Cheniere and cancelled by us. (3) The CCH Working Capital Facility is classified as short-term debt. Senior Notes CCH Senior Secured Notes The senior secured notes due between 2024 and 2039, with a weighted average interest rate of 4.64% (“CCH Senior Secured Notes”), are jointly and severally guaranteed by our subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a “CCH Guarantor” and collectively, the “CCH Guarantors”). The CCH Senior Secured Notes are our senior secured obligations, ranking senior in right of payment to any and all of our future indebtedness that is subordinated to the CCH Senior Secured Notes and equal in right of payment with our other existing and future indebtedness that is senior and secured by the same collateral securing the CCH Senior Secured Notes. The CCH Senior Secured Notes are secured by a first-priority security interest in substantially all of our and the CCH Guarantors’ assets. We may, at any time, redeem all or part of the CCH Senior Secured Notes at specified prices set forth in the respective indentures governing the CCH Senior Secured Notes, plus accrued and unpaid interest, if any, to the date of redemption. Cancellation of CCH Senior Secured Notes Contributed from Cheniere During the year ended December 31, 2022, Cheniere repurchased a total of $1,217 million of our outstanding debt, consisting of $465 million of our Senior Secured Notes due 2025, 2027, 2029 and 2039 on the open market and $752 million of our Senior Secured Notes due 2024, with all of such repurchases immediately contributed to us from Cheniere for no consideration, and cancelled by us. It was determined that for accounting purposes, Cheniere repurchased the bonds on our behalf as a principal as opposed to as an agent, and thus the debt extinguishment was accounted for as an extinguishment directly with Cheniere. Additionally, we recorded a net contribution from Cheniere totaling $21 million from associated operating activities, inclusive of $30 million of interest due to the extinguishment of debt at the time of repayment offset by our write off of associated debt issuance costs and discount of $9 million. The total contribution from Cheniere of $1,238 million associated with the aforementioned activity is reflected within our Consolidated Statements of Member’s Equity. Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2022 (in millions): Years Ending December 31, Principal Payments 2023 $ 498 2024 — 2025 1,491 2026 — 2027 1,354 Thereafter 3,911 Total $ 7,254 Credit Facilities Below is a summary of our credit facilities outstanding as of December 31, 2022 (in millions): CCH Credit Facility (1) (2) CCH Working Capital Facility (2) (3) Total facility size $ 3,260 $ 1,500 Less: Outstanding balance — — Letters of credit issued — 178 Available commitment $ 3,260 $ 1,322 Priority ranking Senior secured Senior secured Interest rate on available balance (4) SOFR plus credit spread adjustment of 0.1%, plus margin of 1.5% or base rate plus 0.5% SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.5% or base rate plus 0.0% - 0.5% Commitment fees on undrawn balance (4) 0.525% 0.10% - 0.20% Maturity date (5) June 15, 2027 (1) Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and our subsidiaries and by a pledge by Cheniere CCH Holdco I of its limited liability company interests in us. (2) In June 2022, we amended and restated the CCH Credit Facility and the CCH Working Capital Facility resulting in $20 million of debt extinguishment and modification costs to, among other things, (1) provide incremental commitments of $3.7 billion and $300 million for the CCH Credit Facility and the CCH Working Capital Facility, respectively, in connection with the FID with respect to the Corpus Christi Stage 3 Project, (2) extend the maturity, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility. (3) Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the CCH Guarantors as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility. (4) The margin on the interest rate and the commitment fees are subject to change based on the applicable entity’s credit rating. (5) The CCH Credit Facility matures the earlier of June 15, 2029 or two years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project. 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. We are restricted from making distributions under agreements governing our 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 December 31, 2022, we were in compliance with all covenants related to our debt agreements. Interest Expense Total interest expense, net of capitalized interest consisted of the following (in millions): Year Ended December 31, 2022 2021 2020 Total interest cost $ 465 $ 473 $ 484 Capitalized interest, including amounts capitalized as an allowance for funds used during construction (33) (26) (119) Total interest expense, net of capitalized interest $ 432 $ 447 $ 365 Fair Value Disclosures The following table shows the carrying amount and estimated fair value of our debt (in millions): December 31, 2022 December 31, 2021 Carrying Estimated Carrying Estimated Senior notes — Level 2 (1) $ 5,283 $ 5,014 $ 6,500 $ 7,095 Senior notes — Level 3 (2) 1,971 1,738 1,971 2,227 (1) The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. (2) The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. 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. |
Revenues
Revenues | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
Revenues | REVENUES The following table represents a disaggregation of revenue earned (in millions): Year Ended December 31, 2022 2021 2020 Revenues from contracts with customers LNG revenues (1) $ 6,335 $ 3,903 $ 2,047 LNG revenues—affiliate 3,027 1,887 483 Total revenues from contracts with customers 9,362 5,790 2,530 Net derivative gain (loss) (2) 1 4 (1) Total revenues $ 9,363 $ 5,794 $ 2,529 (1) LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized during the year ended December 31, 2021 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2022 and 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied. (2) See Note 8 —Derivative Instruments for additional information about our derivatives. LNG Revenues We have entered into numerous SPAs with third party customers for the sale of LNG on a FOB (delivered to the customer at the Corpus Christi LNG Terminal) or DAT (delivered to the customer at their LNG receiving terminal) basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train; however, the term of each SPA generally commences upon the date of first commercial delivery of a specified Train. Additionally, we have agreements with Cheniere Marketing for which the related revenues are recorded as LNG revenues—affiliate. See Note 13—Related Party Transactions for additional information regarding these agreements. Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer, either at the Corpus Christi LNG Terminal or at the customer’s LNG receiving terminal, based on the terms of the contract, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. The stated contract price (including both fixed and variable fees) per MMBtu in each LNG sales arrangement is representative of the stand-alone selling price for LNG at the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price. Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use. Sales of natural gas where, in the delivery of the natural gas to the end customer, we have concluded that we acted as a principal are presented within revenues in our Consolidated Statements of Operations, and where we have concluded that we acted as an agent are netted within cost of sales in our Consolidated Statements of Operations. Contract Assets and Liabilities The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets and other non-current assets, net on our Consolidated Balance Sheets (in millions): December 31, 2022 2021 Contract assets, net of current expected credit losses $ 144 $ 104 Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the year ended December 31, 2022 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due. The following table reflects the changes in our contract liabilities, which we classify as other non-current liabilities on our Consolidated Balance Sheets (in millions): Year Ended December 31, 2022 Deferred revenue, beginning of period $ 35 Cash received but not yet recognized in revenue 76 Revenue recognized from prior period deferral (35) Deferred revenue, end of period $ 76 We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2022 and 2021 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs. 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: December 31, 2022 December 31, 2021 Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) LNG revenues $ 50.9 10 $ 31.7 9 LNG revenues—affiliate 1.2 8 1.1 10 Total revenues $ 52.1 $ 32.8 (1) The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price. We have elected the following exemptions which omit certain potential future sources of revenue from the table above: (1) We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less. (2) The table above excludes substantially all variable consideration under our SPAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of Henry Hub throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Additionally, we have excluded variable consideration related to contracts where there is uncertainty that one or both of the parties will achieve certain milestones. Approximately 70% and 58% of our LNG revenues from contracts included in the table above during the years ended December 31, 2022 and 2021, respectively, were related to variable consideration received from customers. Approximately 86% of our LNG revenues—affiliate from contracts included in the table above during the year ended December 31, 2022 were related to variable consideration received from customers. None of our LNG revenues—affiliates from the contract included in the table above were related to variable consideration received from customers during the year ended December 31, 2021. 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 considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2022 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | RELATED PARTY TRANSACTIONS Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations (in millions): Year Ended December 31, 2022 2021 2020 LNG revenues—affiliate Cheniere Marketing Agreements (1) $ 2,993 $ 1,837 $ 468 Contracts for Sale and Purchase of Natural Gas and LNG (2) 34 50 15 Total LNG revenues—affiliate 3,027 1,887 483 Cost of sales—affiliate Contracts for Sale and Purchase of Natural Gas and LNG (2) 103 19 30 Cheniere Marketing Agreements (1) (3) — 31 — Total cost of sales—affiliate 103 50 30 Cost of sales—related party Natural Gas Supply Agreement (4) — 146 114 Operating and maintenance expense—affiliate Services Agreements (5) 120 105 89 Land Agreements (6) 1 1 1 Total operating and maintenance expense—affiliate 121 106 90 Operating and maintenance expense—related party Natural Gas Transportation Agreements (7) 9 9 6 General and administrative expense—affiliate Services Agreements (5) 38 28 20 (1) CCL primarily sells LNG to Cheniere Marketing International LLP (“Cheniere Marketing”), a wholly owned subsidiary of Cheniere, under SPAs and a letter agreement at a price equal to 115% of Henry Hub plus a fixed fee, except for SPAs associated with IPM agreements for which pricing is linked to international natural gas prices. In addition, CCL has an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be the greater of: (a) 115% of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price. As of December 31, 2022 and 2021, CCL had $223 million and $314 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing. (2) CCL has an agreement with Sabine Pass Liquefaction, LLC that allows the parties to sell and purchase natural gas with each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. As of December 31, 2022 and 2021, CCL had $16 million and $1 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing. (3) CCL and Cheniere Marketing have entered into Shipping Services Agreements (“SSAs”) for the provision of certain shipping and transportation-related services associated with certain SPAs between CCL and third-party customers that are delivered to the customer at their specified LNG receiving terminal. Under the SSAs, CCL pays Cheniere Marketing a fee of 3% to 7% of Henry Hub plus a fixed fee for the shipping services provided. Deliveries under the SSAs will commence in 2023. (4) CCL was party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. The related party entity was acquired by a non-related party on November 1, 2021, therefore, as of such date, this agreement ceased to be considered a related party agreement. CCL also has an agreement with Midship Pipeline Company, LLC that allows them to sell and purchase natural gas with each other. (5) We do not have employees and thus 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. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements are primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of December 31, 2022 and 2021, we had $132 million and $128 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate. (6) CCL has agreements with Cheniere Land Holdings, LLC, a wholly owned subsidiary of Cheniere, to rent, obtain easements and license to enter the land owned by CLH for the Liquefaction Project. (7) CCL is party to natural gas transportation agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. CCL recorded accrued liabilities—related party of $1 million as of both December 31, 2022 and 2021 with this related party. We had $43 million and $35 million due to affiliates as of December 31, 2022 and 2021, respectively, under agreements with affiliates as described above. Disclosure of future consideration under revenue contracts with affiliates is included in Note 12— Revenue s . Additionally, disclosure of future contractual obligations with affiliates and related parties is included in Note 14 — Commitments and Contingencies . Other Agreements State Tax Sharing Agreements CCL and CCP each have a state tax sharing agreement with Cheniere. Under these agreements, Cheniere has agreed to prepare and file all state and local tax returns which each of the entities and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, each of the respective entities will pay to Cheniere an amount equal to the state and local tax that each of the entities would be required to pay if its state and local tax liability were calculated on a separate company basis. To date, there have been no state and local tax payments demanded by Cheniere under the tax sharing agreements. The agreements for both CCL and CCP were effective for tax returns due on or after May 2015. Equity Contribution Agreements We entered into equity contribution agreements with Cheniere and certain of its subsidiaries (the “Equity Contribution Agreements”) pursuant to which Cheniere agreed to contribute any of CCH’s Senior Secured Notes that Cheniere has repurchased to CCH. During the year ended December 31, 2022, Cheniere repurchased a total of $465 million of the outstanding principal amount of CCH’s Senior Secured Notes due 2025, 2027, 2029 and 2039 on the open market, which were immediately contributed under the Equity Contribution Agreements to us from Cheniere and cancelled by us. Arrangement with ADCC Pipeline, LLC In June 2022, Cheniere acquired a 30% equity interest in ADCC Pipeline, LLC and its wholly owned subsidiary (collectively, “ADCC Pipeline”) through its wholly owned subsidiary Cheniere ADCC Investments, LLC. ADCC Pipeline will develop, construct and operate an approximately 42-mile natural gas pipeline project (the “ADCC Pipeline Project”) connecting the Agua Dulce natural gas hub to the CCL Project. Cheniere currently has a future commitment of up to approximately $93 million to fund its equity interest, which commitment is subject to a condition precedent that has not yet been satisfied. CCL is party to a natural gas transportation agreement with ADCC Pipeline in the ordinary course of business for the operation of the CCL Project, with an initial term of 20 years with extension rights, which will commence upon the completion of the ADCC Pipeline Project. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES Commitments We have various commitments under executed contracts that include unconditional purchase obligations and other commitments which do not meet the definition of a liability as of December 31, 2022 and thus are not recognized as liabilities in our Consolidated Financial Statements. EPC Contract CCL has a lump sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for the engineering, procurement and construction of the Corpus Christi Stage 3 Project. The total contract price of the EPC contract is approximately $5.4 billion, reflecting amounts incurred under change orders through December 31, 2022. As of December 31, 2022, we had approximately $3.9 billion remaining under this contract. Natural Gas Supply, Transportation and Storage Service Agreements CCL has physical natural gas supply contracts to secure natural gas feedstock for the Liquefaction Project. The remaining terms of these contracts range up to 15 years. Additionally, CCL has natural gas transportation and storage service agreements for the Liquefaction Project. The initial terms of the natural gas transportation agreements range up 20 years, with renewal options for certain contracts, and commence upon the occurrence of conditions precedent. The initial term of the natural gas storage service agreements ranges up to five years. As of December 31, 2022, CCL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met or are currently expected to be met were as follows (in billions): Years Ending December 31, Payments Due to Third Parties (1) Payments Due to Related Party (1) 2023 $ 4.4 $ — 2024 4.1 — 2025 3.6 — 2026 3.2 0.1 2027 3.4 0.1 Thereafter 24.1 0.8 Total $ 42.8 $ 1.0 (1) Pricing of natural gas supply contracts is variable based on market commodity basis prices adjusted for basis spread, and pricing of IPM agreements is variable based on global gas market prices less fixed liquefaction fees and certain costs incurred by us . Amounts included are based on estimated forward prices and basis spreads as of December 31, 2022. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services. Services Agreements CCL and CCP have certain fixed commitments under services agreements, SSAs and other agreements of $0.2 billion with third parties and $7.5 billion with affiliates. See Note 1 3 —Related Party Transactions for additional information regarding such agreements. Environmental and Regulatory Matters The Liquefaction Project is subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows. Legal Proceedings We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. We recognize legal costs in connection with legal and regulatory matters as they are incurred. In the opinion of management, as of December 31, 2022, there were no pending legal matters that would reasonably be expected to have a material impact on our operating results, financial position or cash flows. |
Customer Concentration
Customer Concentration | 12 Months Ended |
Dec. 31, 2022 | |
Risks and Uncertainties [Abstract] | |
Customer Concentration | CUSTOMER CONCENTRATION The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively: Percentage of Total Revenues from External Customers Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers Year Ended December 31, December 31, 2022 2021 2020 2022 2021 Customer A 21% 21% 31% 17% * Customer B 14% 16% 16% * * Customer C 14% 15% 14% * * Customer D * * * 33% 31% Customer E * * —% * 11% Customer F 10% * —% * * * Less than 10% The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States. Revenues from External Customers Year Ended December 31, 2022 2021 2020 Spain $ 2,192 $ 1,432 $ 1,001 Singapore 1,248 694 134 France 940 423 136 Indonesia 889 618 336 Ireland 868 599 285 United States 199 141 154 Total $ 6,336 $ 3,907 $ 2,046 |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2022 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | SUPPLEMENTAL CASH FLOW INFORMATION The following table provides supplemental disclosure of cash flow information (in millions): Year Ended December 31, 2022 2021 2020 Cash paid during the period for interest on debt, net of amounts capitalized $ 280 $ 423 $ 345 Right-of-use assets obtained in exchange for new operating lease liabilities 3 — — Non-cash investing activity: Transfers of property, plant and equipment in exchange for other non-current assets 17 — 2 Contributions of assets from affiliates 7 — — Non-cash financing activity: Cancellation of CCH Senior Secured Notes contributed to us from Cheniere (see Note 11 ) 1,217 — — Contribution of CCL Stage III entity to us from Cheniere (see Note 3 ) (1,482) — — The balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) was $70 million, $20 million and $86 million as of December 31, 2022, 2021 and 2020, respectively. |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2022 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
Schedule II - Valuation and Qualifying Accounts Disclosure | Balance at beginning of period Charged to costs and expenses Charged to other accounts Deductions Balance at end of period Year Ended December 31, 2022 Current expected credit losses on receivables and contract assets $ 3 $ 1 $ — $ — $ 4 Year Ended December 31, 2021 Current expected credit losses on receivables and contract assets $ 2 $ 1 $ — $ — $ 3 Year Ended December 31, 2020 Current expected credit losses on receivables and contract assets $ — $ 2 $ — $ — $ 2 |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Basis of Presentation, Policy | Basis of Presentation Our Consolidated Financial Statements have been prepared in accordance with GAAP. Our Consolidated Financial Statements include the accounts of CCH and its subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. |
Use of Estimates, Policy | Use of Estimates The preparation of our 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. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments useful lives of property, plant and equipment and asset retirement obligations (“AROs”), as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. |
Fair Value Measurements, Policy | Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market. In determining fair value, we use observable market data when available, or models that incorporate observable market data. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We maximize the use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates. Recurring fair-value measurements are performed for derivative instruments as disclosed in Note 8—Derivative Instruments . The carrying amount of restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, contract assets, margin deposits, accounts payable and accrued liabilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Debt fair values, as disclosed in Note 11—Debt |
Revenue Recognition, Policy | Revenue Recognition We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 12—Revenues for further discussion of our revenue streams and accounting policies related to revenue recognition. |
Restricted Cash and Cash Equivalents, Policy | Restricted Cash and Cash Equivalents Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. |
Current Expected Credit Losses | Current Expected Credit Losses Trade and other receivables and contract assets are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status, and other risks or available financial assurances. Adjustments to current expected credit losses are recorded in general and administrative expense in our Consolidated Statements of Operations. As of both December 31, 2022 and 2021, we had current expected credit losses of zero on our trade and other receivables, and as of December 31, 2022 and 2021, we had current expected credit losses of $4 million and $3 million, respectively, on our non-current contract assets. |
Inventory, Policy | InventoryLNG and natural gas inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or, for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method. |
Property, Plant and Equipment, Policy | Property, Plant and Equipment Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred. Generally, we begin capitalizing the costs of our LNG terminal once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with preliminary front-end engineering and design work, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminal. Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets. We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction. We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives. Refer to Note 7—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses on disposal are recorded in other operating costs and expenses. Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value. We did not record any material impairments related to property, plant and equipment during the years ended December 31, 2022, 2021 and 2020. |
Interest Capitalization, Policy | Interest Capitalization We capitalize interest costs during the construction period of our LNG terminal and related assets as construction-in-process. Upon placing the underlying asset in service, these costs are transferred out of construction-in-process into the respective in-service asset category and depreciated over the estimated useful life of the corresponding assets, except for capitalized interest associated with land, which is not depreciated. |
Regulated Natural Gas Pipelines, Policy | Regulated Natural Gas Pipelines The Corpus Christi Pipeline is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are classified in our Consolidated Balance Sheets as other assets and other liabilities. Upon a triggering event, we evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to write off the associated regulatory assets and liabilities. Items that may influence our assessment are: • inability to recover cost increases due to rate caps and rate case moratoriums; • inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings; • excess capacity; • increased competition and discounting in the markets we serve; and • impacts of ongoing regulatory initiatives in the natural gas industry. Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipeline. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipeline is placed in service. |
Derivative Instruments, Policy | Derivative Instruments We use derivative instruments to hedge our exposure to cash flow variability from interest rate and commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities depending on the derivative position and the expected timing of settlement, unless they satisfy criteria for, and we elect, the normal purchases and sales exception, under which we account for the instrument under the accrual method of accounting, whereby revenues and expenses are recognized only upon delivery, receipt or realization of the underlying transaction. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis. For those derivative instruments measured at fair value, changes in the fair value of the instruments are recorded in earnings, unless we elect to apply hedge accounting and meet specified criteria. We did not have any derivative instruments designated as cash flow or fair value hedges during the years ended December 31, 2022, 2021 and 2020. See Note 8—Derivative Instruments |
Concentration of Credit Risk, Policy | Concentration of Credit Risk Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable related to our long-term SPAs, as discussed further below. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within margin deposits. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments. CCL has entered into fixed price long-term SPAs generally with terms of 20 years with 15 third parties and have entered into agreements with Cheniere Marketing International LLP (“Cheniere Marketing”). CCL is dependent on the respective customers’ creditworthiness and their willingness to perform under their respective SPAs. See Note 15—Customer Concentration for additional details about our customer concentration. Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. |
Debt, Policy | Debt Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors. Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees, printing costs and in certain cases, commitment fees. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method. Gains and losses on the extinguishment or modification of debt are recorded in loss on modification or extinguishment of debt on our Consolidated Statements of Operations. We classify debt on our Consolidated Balance Sheets based on contractual maturity, with the following exceptions: • We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt agreement. • We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date. |
Asset Retirement Obligations, Policy | Asset Retirement Obligations We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. We have not recorded an ARO associated with the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly. |
Income Taxes, Policy | Income Taxes We are a disregarded entity for federal and state income tax purposes. Our taxable income or loss, which may vary substantially from the net income or loss reported on our Consolidated Statements of Operations, is included in the consolidated federal income tax return of Cheniere. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Consolidated Financial Statements. |
Business Segment, Policy | Business Segment Our liquefaction and pipeline business at the Corpus Christi LNG Terminal represents a single reportable segment. Our |
Recent Accounting Standards | Recent Accounting Standards ASU 2020-04 In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting . This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing contracts expected to arise from the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard. We had interest rate swaps and various credit facilities indexed to LIBOR, as further described in Note 8 —Derivative Instruments and Note 11 —Debt , respectively. In June 2022, we amended our credit facilities to bear interest at a variable rate per annum based on SOFR as a result of the expected LIBOR transition. Since adoption of the standard, we elected to apply the optional expedients as applicable to certain modified facilities; however, the impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows. |
CCL Stage III Contribution an_2
CCL Stage III Contribution and Merger (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Business Combination and Asset Acquisition [Abstract] | |
Asset Acquisition | The net liabilities of CCL Stage III contributed to us and recognized on our Consolidated Balance Sheets on June 15, 2022 consisted of the following (in millions): June 15, 2022 ASSETS Property, plant and equipment, net of accumulated depreciation $ 441 Derivatives assets 112 Other non-current assets, net 19 Total assets $ 572 LIABILITIES Current liabilities Accounts payable $ 3 Due to affiliates 1 Total current liabilities 4 Derivative liabilities 2,050 Total net liabilities contributed $ (1,482) |
Trade and Other Receivables, _2
Trade and Other Receivables, Net of Current Expected Credit Losses (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Receivables [Abstract] | |
Schedule of Accounts and Other Receivables | Trade and other receivables, net of current expected credit losses consisted of the following (in millions): December 31, 2022 2021 Trade receivables $ 319 $ 256 Other receivables 29 24 Total trade and other receivables, net of current expected credit losses $ 348 $ 280 |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Inventory Disclosure [Abstract] | |
Schedule of Inventory | Inventory consisted of the following (in millions): December 31, 2022 2021 Materials $ 92 $ 88 LNG 53 45 Natural gas 31 21 Other 2 2 Total inventory $ 178 $ 156 |
Property, Plant and Equipment_2
Property, Plant and Equipment, Net of Accumulated Depreciation (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions): December 31, 2022 2021 LNG terminal Terminal and interconnecting pipeline facilities $ 13,299 $ 13,222 Site and related costs 302 294 Construction-in-process 1,486 66 Accumulated depreciation (1,421) (981) Total LNG terminal, net of accumulated depreciation 13,666 12,601 Fixed assets Fixed assets 26 23 Accumulated depreciation (19) (17) Total fixed assets, net of accumulated depreciation 7 6 Property, plant and equipment, net of accumulated depreciation $ 13,673 $ 12,607 |
Schedule of Depreciation and Offsets to LNG Terminal Costs | The following table shows depreciation expense and offsets to LNG terminal costs (in millions): Year Ended December 31, 2022 2021 2020 Depreciation expense $ 444 $ 419 $ 341 Offsets to LNG terminal costs (1) — 143 32 (1) We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction. |
Property Plant And Equipment Estimated Useful Lives Table | LNG terminal costs related to the Liquefaction Project are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Liquefaction Project have depreciable lives between 6 and 50 years, as follows: Components Useful life (years) LNG storage tanks 50 Natural gas pipeline facilities 40 Marine berth, electrical, facility and roads 35 Water pipelines 30 Liquefaction processing equipment 6-50 Other 15-30 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Fair Value of Derivative Assets and Liabilities | The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis (in millions): Fair Value Measurements as of December 31, 2022 December 31, 2021 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Interest Rate Derivatives liability $ — $ — $ — $ — $ — $ (40) $ — $ (40) Liquefaction Supply Derivatives asset (liability) (54) (19) (6,205) (6,278) 5 4 (1,221) (1,212) |
Fair Value Measurement Inputs and Valuation Techniques | The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of December 31, 2022: Net Fair Value Liability Valuation Approach Significant Unobservable Input Range of Significant Unobservable Inputs / Weighted Average (1) Liquefaction Supply Derivatives $(6,205) Market approach incorporating present value techniques Henry Hub basis spread $(1.049) - $0.160 / $(0.258) Option pricing model International LNG pricing spread, relative to Henry Hub (2) 73% - 532% / 157% (1) Unobservable inputs were weighted by the relative fair value of the instruments. |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation | The following table shows the changes in the fair value of our Level 3 Liquefaction Supply Derivatives (in millions): Year Ended December 31, 2022 2021 (1) 2020 Balance, beginning of period $ (1,221) $ 12 $ 35 Realized and change in fair value gains (losses) included in net income (2): Included in cost of sales, existing deals (3) (1,492) (1,276) 28 Included in cost of sales, new deals (4) (2,172) — — Purchases and settlements: Purchases (5) (1,938) 9 — Settlements (6) 618 34 (58) Transfers in and/or out of level 3 Transfers into level 3 (7) — — 7 Balance, end of period $ (6,205) $ (1,221) $ 12 Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period $ (3,664) $ (1,276) $ 28 (1) Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 13—Related Party Transactions . (2) 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. (3) Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period. (4) Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period. (5) Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period. For further discussion of IPM agreements that were novated to us during the period, see Note 3—CCL Stage III Contribution and Merger . (6) 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. (7) Transferred into level 3 as a result of unobservable market for the underlying natural gas purchase agreements. |
Fair Value of Derivative Instruments by Balance Sheet Location | The following table shows the fair value and location of our derivative instruments on our Consolidated Balance Sheets (in millions): December 31, 2022 CCH Interest Rate Derivatives Liquefaction Supply Derivatives (1) Total Consolidated Balance Sheets Location Current derivative assets $ — $ 12 $ 12 Derivative assets — 7 7 Total derivative assets — 19 19 Current derivative liabilities — (1,374) (1,374) Derivative liabilities — (4,923) (4,923) Total derivative liabilities — (6,297) (6,297) Derivative liability, net $ — $ (6,278) $ (6,278) December 31, 2021 CCH Interest Rate Derivatives Liquefaction Supply Derivatives (1) Total Consolidated Balance Sheets Location Current derivative assets $ — $ 17 $ 17 Derivative assets — 37 37 Total derivative assets — 54 54 Current derivative liabilities (40) (628) (668) Derivative liabilities — (638) (638) Total derivative liabilities (40) (1,266) (1,306) Derivative liability, net $ (40) $ (1,212) $ (1,252) (1) Does not include collateral posted with counterparties by us of $76 million and $13 million as of December 31, 2022 and 2021, respectively, which are included in other current assets in our Consolidated Balance Sheets. Includes a natural gas supply contract that we had with a related party. This agreement ceased to be considered a related party agreement as of November 1, 2021. |
Derivative Net Presentation on Consolidated Balance Sheets | 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: CCH Interest Rate Derivatives Liquefaction Supply Derivatives As of December 31, 2022 Gross assets $ — $ 19 Offsetting amounts — — Net assets $ — $ 19 Gross liabilities $ — $ (6,622) Offsetting amounts — 325 Net liabilities $ — $ (6,297) As of December 31, 2021 Gross assets $ — $ 76 Offsetting amounts — (22) Net assets $ — $ 54 Gross liabilities $ (40) $ (1,295) Offsetting amounts — 29 Net liabilities $ (40) $ (1,266) |
Interest Rate Derivatives [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | We previously entered into the following Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the CCH Credit Facility, which expired in May 2022: Notional Amounts December 31, 2022 December 31, 2021 Weighted Average Fixed Interest Rate Paid Variable Interest Rate Received CCH Interest Rate Derivatives $— $4.5 billion 2.30% One-month LIBOR |
Derivative Instruments, Gain (Loss) | The following table shows the effect and location of our Interest Rate Derivatives on our Consolidated Statements of Operations (in millions): Gain (Loss) Recognized in Consolidated Statements of Operations Consolidated Statements of Operations Location Year Ended December 31, 2022 2021 2020 CCH Interest Rate Derivatives Interest rate derivative gain (loss), net $ 2 $ (1) $ (138) CCH Interest Rate Forward Start Derivatives Interest rate derivative gain (loss), net — — (95) |
Liquefaction Supply Derivatives [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Derivative Instruments, Gain (Loss) | The following table shows the effect and location of our Liquefaction Supply Derivatives recorded on our Consolidated Statements of Operations (in millions): Gain (Loss) Recognized in Consolidated Statements of Operations Consolidated Statements of Operations Location (1) Year Ended December 31, 2022 2021 2020 LNG revenues $ 1 $ 4 $ (1) Cost of sales (3,246) (1,244) (27) Cost of sales—related party (2) — 11 (1) (1) Does not include the value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument. (2) Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement during 2021 as discussed in Note 13—Related Party Transactions . |
Other Non-Current Assets, Net (
Other Non-Current Assets, Net (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Other Assets, Noncurrent [Abstract] | |
Schedule of Other Non-Current Assets | Other non-current assets, net consisted of the following (in millions): December 31, 2022 2021 Contract assets, net of current expected credit losses $ 142 $ 103 Advances and other asset conveyances to third parties to support LNG terminal 62 24 Operating lease assets 6 4 Information technology service prepayments 3 3 Tax-related payments and receivables 3 2 Other 9 9 Total other non-current assets, net $ 225 $ 145 |
Accrued Liabilities (Tables)
Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Accrued Liabilities, Current [Abstract] | |
Schedule of Accrued Liabilities | Accrued liabilities consisted of the following (in millions): December 31, 2022 2021 Natural gas purchases $ 597 $ 531 Interest costs and related debt fees 150 7 Liquefaction Project costs 103 43 Other accrued liabilities 51 50 Total accrued liabilities $ 901 $ 631 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Schedule of Debt Instruments | Debt consisted of the following (in millions): December 31, 2022 2021 Senior Secured Notes: 2024 CCH Senior Notes (1) $ 498 $ 1,250 5.875% due 2025 1,491 1,500 5.125% due 2027 (2) 1,271 1,500 3.700% due 2029 (2) 1,361 1,500 3.751% weighted average rate due 2039 (2) 2,633 2,721 Total Senior Secured Notes 7,254 8,471 CCH Credit Facility — 1,728 CCH Working Capital Facility (3) — 250 Total debt 7,254 10,449 Current portion of long-term debt (495) (117) Short-term debt — (250) Unamortized discount and debt issuance costs, net (61) (96) Total long-term debt, net of discount and debt issuance costs $ 6,698 $ 9,986 (1) In January 2023, we redeemed the remaining outstanding principal balance of the 2024 CCH Senior Notes with cash that was contributed to us from Cheniere prior to December 31, 2022. Therefore, the outstanding principal balance redeemed was classified as current portion of long-term debt as of December 31, 2022 net of discount and debt issuance costs of $3 million. (2) Subsequent to December 31, 2022 and through February 16, 2023, Cheniere executed bond repurchases totaling $322 million, inclusive of CCH’s Senior Secured Notes due 2027, 2029 and 2039 on the open market, which were immediately contributed to us from Cheniere and cancelled by us. (3) The CCH Working Capital Facility is classified as short-term debt. |
Schedule of Maturities of Long-term Debt | Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2022 (in millions): Years Ending December 31, Principal Payments 2023 $ 498 2024 — 2025 1,491 2026 — 2027 1,354 Thereafter 3,911 Total $ 7,254 |
Schedule of Line of Credit Facilities | Below is a summary of our credit facilities outstanding as of December 31, 2022 (in millions): CCH Credit Facility (1) (2) CCH Working Capital Facility (2) (3) Total facility size $ 3,260 $ 1,500 Less: Outstanding balance — — Letters of credit issued — 178 Available commitment $ 3,260 $ 1,322 Priority ranking Senior secured Senior secured Interest rate on available balance (4) SOFR plus credit spread adjustment of 0.1%, plus margin of 1.5% or base rate plus 0.5% SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.5% or base rate plus 0.0% - 0.5% Commitment fees on undrawn balance (4) 0.525% 0.10% - 0.20% Maturity date (5) June 15, 2027 (1) Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and our subsidiaries and by a pledge by Cheniere CCH Holdco I of its limited liability company interests in us. (2) In June 2022, we amended and restated the CCH Credit Facility and the CCH Working Capital Facility resulting in $20 million of debt extinguishment and modification costs to, among other things, (1) provide incremental commitments of $3.7 billion and $300 million for the CCH Credit Facility and the CCH Working Capital Facility, respectively, in connection with the FID with respect to the Corpus Christi Stage 3 Project, (2) extend the maturity, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility. (3) Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the CCH Guarantors as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility. (4) The margin on the interest rate and the commitment fees are subject to change based on the applicable entity’s credit rating. (5) The CCH Credit Facility matures the earlier of June 15, 2029 or two years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project. |
Schedule of Interest Expense | Total interest expense, net of capitalized interest consisted of the following (in millions): Year Ended December 31, 2022 2021 2020 Total interest cost $ 465 $ 473 $ 484 Capitalized interest, including amounts capitalized as an allowance for funds used during construction (33) (26) (119) Total interest expense, net of capitalized interest $ 432 $ 447 $ 365 |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments | The following table shows the carrying amount and estimated fair value of our debt (in millions): December 31, 2022 December 31, 2021 Carrying Estimated Carrying Estimated Senior notes — Level 2 (1) $ 5,283 $ 5,014 $ 6,500 $ 7,095 Senior notes — Level 3 (2) 1,971 1,738 1,971 2,227 (1) The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments. |
Revenues (Tables)
Revenues (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table represents a disaggregation of revenue earned (in millions): Year Ended December 31, 2022 2021 2020 Revenues from contracts with customers LNG revenues (1) $ 6,335 $ 3,903 $ 2,047 LNG revenues—affiliate 3,027 1,887 483 Total revenues from contracts with customers 9,362 5,790 2,530 Net derivative gain (loss) (2) 1 4 (1) Total revenues $ 9,363 $ 5,794 $ 2,529 (1) LNG revenues include revenues for LNG cargoes in which our customers exercised their contractual right to not take delivery but remained obligated to pay fixed fees irrespective of such election. During the year ended December 31, 2020, we recognized $435 million in LNG revenues associated with LNG cargoes for which customers notified us that they would not take delivery, of which $38 million would have been recognized during the year ended December 31, 2021 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2022 and 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied. (2) See Note 8 —Derivative Instruments |
Contract with Customer, Asset | The following table shows our contract assets, net of current expected credit losses, which are classified as other current assets and other non-current assets, net on our Consolidated Balance Sheets (in millions): December 31, 2022 2021 Contract assets, net of current expected credit losses $ 144 $ 104 Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due. Changes in contract assets during the year ended December 31, 2022 were primarily attributable to revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due. |
Contract Balances Reconciliation | The following table reflects the changes in our contract liabilities, which we classify as other non-current liabilities on our Consolidated Balance Sheets (in millions): Year Ended December 31, 2022 Deferred revenue, beginning of period $ 35 Cash received but not yet recognized in revenue 76 Revenue recognized from prior period deferral (35) Deferred revenue, end of period $ 76 |
Transaction Price Allocated to Future Performance Obligations | The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied: December 31, 2022 December 31, 2021 Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) Unsatisfied Transaction Price (in billions) Weighted Average Recognition Timing (years) (1) LNG revenues $ 50.9 10 $ 31.7 9 LNG revenues—affiliate 1.2 8 1.1 10 Total revenues $ 52.1 $ 32.8 (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. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | Below is a summary of our related party transactions as reported on our Consolidated Statements of Operations (in millions): Year Ended December 31, 2022 2021 2020 LNG revenues—affiliate Cheniere Marketing Agreements (1) $ 2,993 $ 1,837 $ 468 Contracts for Sale and Purchase of Natural Gas and LNG (2) 34 50 15 Total LNG revenues—affiliate 3,027 1,887 483 Cost of sales—affiliate Contracts for Sale and Purchase of Natural Gas and LNG (2) 103 19 30 Cheniere Marketing Agreements (1) (3) — 31 — Total cost of sales—affiliate 103 50 30 Cost of sales—related party Natural Gas Supply Agreement (4) — 146 114 Operating and maintenance expense—affiliate Services Agreements (5) 120 105 89 Land Agreements (6) 1 1 1 Total operating and maintenance expense—affiliate 121 106 90 Operating and maintenance expense—related party Natural Gas Transportation Agreements (7) 9 9 6 General and administrative expense—affiliate Services Agreements (5) 38 28 20 (1) CCL primarily sells LNG to Cheniere Marketing International LLP (“Cheniere Marketing”), a wholly owned subsidiary of Cheniere, under SPAs and a letter agreement at a price equal to 115% of Henry Hub plus a fixed fee, except for SPAs associated with IPM agreements for which pricing is linked to international natural gas prices. In addition, CCL has an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be the greater of: (a) 115% of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price. As of December 31, 2022 and 2021, CCL had $223 million and $314 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing. (2) CCL has an agreement with Sabine Pass Liquefaction, LLC that allows the parties to sell and purchase natural gas with each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. As of December 31, 2022 and 2021, CCL had $16 million and $1 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing. (3) CCL and Cheniere Marketing have entered into Shipping Services Agreements (“SSAs”) for the provision of certain shipping and transportation-related services associated with certain SPAs between CCL and third-party customers that are delivered to the customer at their specified LNG receiving terminal. Under the SSAs, CCL pays Cheniere Marketing a fee of 3% to 7% of Henry Hub plus a fixed fee for the shipping services provided. Deliveries under the SSAs will commence in 2023. (4) CCL was party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. The related party entity was acquired by a non-related party on November 1, 2021, therefore, as of such date, this agreement ceased to be considered a related party agreement. CCL also has an agreement with Midship Pipeline Company, LLC that allows them to sell and purchase natural gas with each other. (5) We do not have employees and thus 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. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements are primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of December 31, 2022 and 2021, we had $132 million and $128 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate. (6) CCL has agreements with Cheniere Land Holdings, LLC, a wholly owned subsidiary of Cheniere, to rent, obtain easements and license to enter the land owned by CLH for the Liquefaction Project. (7) CCL is party to natural gas transportation agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. CCL recorded accrued liabilities—related party of $1 million as of both December 31, 2022 and 2021 with this related party. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
CCL [Member] | Natural Gas Supply, Transportation And Storage Service Agreements [Member] | |
Long-term Purchase Commitment [Line Items] | |
Contractual Obligation, Fiscal Year Maturity Schedule | As of December 31, 2022, CCL’s obligations under natural gas supply, transportation and storage service agreements for contracts in which conditions precedent were met or are currently expected to be met were as follows (in billions): Years Ending December 31, Payments Due to Third Parties (1) Payments Due to Related Party (1) 2023 $ 4.4 $ — 2024 4.1 — 2025 3.6 — 2026 3.2 0.1 2027 3.4 0.1 Thereafter 24.1 0.8 Total $ 42.8 $ 1.0 (1) Pricing of natural gas supply contracts is variable based on market commodity basis prices adjusted for basis spread, and pricing of IPM agreements is variable based on global gas market prices less fixed liquefaction fees and certain costs incurred by us . Amounts included are based on estimated forward prices and basis spreads as of December 31, 2022. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services. |
Customer Concentration (Tables)
Customer Concentration (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Risks and Uncertainties [Abstract] | |
Schedule of Revenue and Accounts Receivable by Major Customers | The following table shows external customers with revenues of 10% or greater of total revenues from external customers and external customers with trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses balances of 10% or greater of total trade and other receivables, net of current expected credit losses from external customers and contract assets, net of current expected credit losses from external customers, respectively: Percentage of Total Revenues from External Customers Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers Year Ended December 31, December 31, 2022 2021 2020 2022 2021 Customer A 21% 21% 31% 17% * Customer B 14% 16% 16% * * Customer C 14% 15% 14% * * Customer D * * * 33% 31% Customer E * * —% * 11% Customer F 10% * —% * * * Less than 10% |
Schedule of Revenue from External Customers by Country | The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business. Substantially all of our long-lived assets are located in the United States. Revenues from External Customers Year Ended December 31, 2022 2021 2020 Spain $ 2,192 $ 1,432 $ 1,001 Singapore 1,248 694 134 France 940 423 136 Indonesia 889 618 336 Ireland 868 599 285 United States 199 141 154 Total $ 6,336 $ 3,907 $ 2,046 |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures | The following table provides supplemental disclosure of cash flow information (in millions): Year Ended December 31, 2022 2021 2020 Cash paid during the period for interest on debt, net of amounts capitalized $ 280 $ 423 $ 345 Right-of-use assets obtained in exchange for new operating lease liabilities 3 — — Non-cash investing activity: Transfers of property, plant and equipment in exchange for other non-current assets 17 — 2 Contributions of assets from affiliates 7 — — Non-cash financing activity: Cancellation of CCH Senior Secured Notes contributed to us from Cheniere (see Note 11 ) 1,217 — — Contribution of CCL Stage III entity to us from Cheniere (see Note 3 ) (1,482) — — |
Organization and Nature of Op_2
Organization and Nature of Operations (Details) | 12 Months Ended |
Dec. 31, 2022 unit milliontonnes / yr item mi trains | |
Corpus Christi Pipeline [Member] | |
Organization and Nature of Operations [Line Items] | |
Length Of Natural Gas Pipeline | mi | 21.5 |
Corpus Christi LNG Terminal [Member] | |
Organization and Nature of Operations [Line Items] | |
Number of Liquefaction LNG Trains Operating | trains | 3 |
Total Production Capability | milliontonnes / yr | 15 |
Number of LNG Storage Tanks | unit | 3 |
Number of Marine Berths | item | 2 |
Corpus Christi LNG Terminal Expansion | |
Organization and Nature of Operations [Line Items] | |
Total Production Capability | milliontonnes / yr | 3 |
Number of Liquefaction LNG Trains | trains | 2 |
Corpus Christi Stage 3 Project | Maximum [Member] | |
Organization and Nature of Operations [Line Items] | |
Number of Liquefaction LNG Trains | trains | 7 |
Corpus Christi Stage 3 Project | Minimum [Member] | |
Organization and Nature of Operations [Line Items] | |
Total Production Capability | milliontonnes / yr | 10 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Details) | 12 Months Ended | ||
Dec. 31, 2022 USD ($) customer | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Accounts Receivable, Allowance for Credit Loss, Current | $ 0 | $ 0 | |
Contract with Customer, Asset, Allowance for Credit Loss, Noncurrent | 4,000,000 | 3,000,000 | |
Impairment expense related to property, plant and equipment | 0 | 0 | $ 0 |
Derivative instruments designated as cash flow hedges | 0 | 0 | 0 |
Income Tax Expense (Benefit) | $ 0 | $ 0 | $ 0 |
Number of Reportable Segments | customer | 1 | ||
Corpus Christi Pipeline [Member] | |||
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Asset Retirement Obligation | $ 0 | ||
CCL [Member] | Customer Concentration Risk [Member] | SPA Customers [Member] | |||
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
SPA, Term of Agreement | 20 years | ||
Concentration Risk, Number of Significant Customers | customer | 15 |
CCL Stage III Contribution an_3
CCL Stage III Contribution and Merger (Details) - USD ($) $ in Millions | 12 Months Ended | ||||||
Dec. 31, 2022 | Jun. 30, 2022 | Jun. 15, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |||
Asset Acquisition [Line Items] | |||||||
Property, plant and equipment, net of accumulated depreciation | $ 13,673 | $ 12,607 | |||||
Derivative assets | 7 | 37 | |||||
Other non-current assets, net | 225 | 145 | |||||
Total assets | 15,687 | 13,764 | |||||
Accounts payable | 85 | 119 | |||||
Due to affiliates | 43 | 35 | |||||
Total current liabilities | 2,900 | 1,821 | |||||
Derivative liabilities | 4,923 | 638 | |||||
Asset Acquisition, Net Liability Acquired | (1,482) | $ 0 | $ 0 | ||||
Cheniere Corpus Christi Liquefaction Stage III, LLC [Member] | |||||||
Asset Acquisition [Line Items] | |||||||
Property, plant and equipment, net of accumulated depreciation | $ 441 | ||||||
Derivative assets | 112 | ||||||
Other non-current assets, net | 19 | ||||||
Total assets | 572 | ||||||
Accounts payable | 3 | ||||||
Due to affiliates | 1 | ||||||
Total current liabilities | 4 | ||||||
Derivative liabilities | 2,050 | ||||||
Asset Acquisition, Net Liability Acquired | $ (1,482) | ||||||
CCH Credit Facility [Member] | |||||||
Asset Acquisition [Line Items] | |||||||
Total facility size | $ 3,260 | [1],[2] | $ 4,000 | ||||
CCH Credit Facility [Member] | Maximum [Member] | |||||||
Asset Acquisition [Line Items] | |||||||
Maturity Date | Jun. 15, 2029 | ||||||
CCH Working Capital Facility [Member] | |||||||
Asset Acquisition [Line Items] | |||||||
Total facility size | $ 1,500 | [1],[3] | $ 1,500 | ||||
Maturity Date | [1],[3] | Jun. 15, 2027 | |||||
[1]In June 2022, we amended and restated the CCH Credit Facility and the CCH Working Capital Facility resulting in $20 million of debt extinguishment and modification costs to, among other things, (1) provide incremental commitments of $3.7 billion and $300 million for the CCH Credit Facility and the CCH Working Capital Facility, respectively, in connection with the FID with respect to the Corpus Christi Stage 3 Project, (2) extend the maturity, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility.[2]Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and our subsidiaries and by a pledge by Cheniere CCH Holdco I of its limited liability company interests in us.[3] Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the CCH Guarantors as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility. |
Restricted Cash and Cash Equi_2
Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Restricted Cash and Cash Equivalents Items [Line Items] | ||
Restricted cash and cash equivalents | $ 738 | $ 44 |
Cash Contributed from Parent for Subsequent Repayment of Debt | ||
Restricted Cash and Cash Equivalents Items [Line Items] | ||
Restricted cash and cash equivalents | $ 498 | |
2024 CCH Senior Notes [Member] | ||
Restricted Cash and Cash Equivalents Items [Line Items] | ||
Debt Instrument, Interest Rate, Stated Percentage | 7% | |
CCL Project [Member] | ||
Restricted Cash and Cash Equivalents Items [Line Items] | ||
Restricted cash and cash equivalents | $ 738 | $ 44 |
Trade and Other Receivables, _3
Trade and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Receivables [Abstract] | ||
Trade receivables | $ 319 | $ 256 |
Other receivables | 29 | 24 |
Total trade and other receivables, net of current expected credit losses | $ 348 | $ 280 |
Inventory (Details)
Inventory (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Inventory [Line Items] | ||
Inventory | $ 178 | $ 156 |
Materials [Member] | ||
Inventory [Line Items] | ||
Inventory | 92 | 88 |
LNG [Member] | ||
Inventory [Line Items] | ||
Inventory | 53 | 45 |
Natural gas [Member] | ||
Inventory [Line Items] | ||
Inventory | 31 | 21 |
Other [Member] | ||
Inventory [Line Items] | ||
Inventory | $ 2 | $ 2 |
Property, Plant and Equipment_3
Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, net of accumulated depreciation | $ 13,673 | $ 12,607 |
LNG terminal costs [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Accumulated depreciation | (1,421) | (981) |
Property, plant and equipment, net of accumulated depreciation | 13,666 | 12,601 |
Terminal and interconnecting pipeline facilities [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 13,299 | 13,222 |
Site and related costs [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 302 | 294 |
Construction-in-process [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 1,486 | 66 |
Fixed assets [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 26 | 23 |
Accumulated depreciation | (19) | (17) |
Property, plant and equipment, net of accumulated depreciation | $ 7 | $ 6 |
Property, Plant and Equipment_4
Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Depreciation and Offsets to LNG Terminal Costs (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Property, Plant and Equipment [Abstract] | ||||
Depreciation expense | $ 444 | $ 419 | $ 341 | |
Offsets to LNG terminal costs | [1] | $ 0 | $ 143 | $ 32 |
[1]We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Project during the testing phase for its construction. |
Property, Plant and Equipment_5
Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Useful Lives (Details) | 12 Months Ended |
Dec. 31, 2022 | |
Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 6 years |
Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 50 years |
LNG storage tanks | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 50 years |
Natural gas pipeline facilities [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 40 years |
Marine berth, electrical, facility and roads | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 35 years |
Water pipelines [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 30 years |
Liquefaction processing equipment [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 6 years |
Liquefaction processing equipment [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 50 years |
Other [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 15 years |
Other [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Property, Plant and Equipment, Useful Life | 30 years |
Derivative Instruments - Narrat
Derivative Instruments - Narrative (Details) - CCL [Member] - tbtu | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Physical Liquefaction Supply Derivatives [Member] | Maximum [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, Term of Contract | 15 years | |
Liquefaction Supply Derivatives [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 8,532 | 2,915 |
Derivative Instruments - Fair V
Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Interest Rate Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | $ 0 | $ (40) |
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 |
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | (40) |
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 |
Liquefaction Supply Derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | (6,278) | (1,212) |
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | (54) | 5 |
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | (19) | 4 |
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets (Liabilities), at Fair Value, Net | $ (6,205) | $ (1,221) |
Derivative Instruments - Fair_2
Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Physical Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member] | 12 Months Ended | |
Dec. 31, 2022 USD ($) | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Net Fair Value Liability | $ (6,205,000,000) | |
Valuation, Market Approach [Member] | Minimum [Member] | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Fair Value Inputs Basis Spread | (1.049) | [1] |
Valuation, Market Approach [Member] | Maximum [Member] | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Fair Value Inputs Basis Spread | 0.160 | [1] |
Valuation, Market Approach [Member] | Weighted Average [Member] | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Fair Value Inputs Basis Spread | $ (0.258) | [1] |
Valuation Technique, Option Pricing Model [Member] | Minimum [Member] | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Fair Value Inputs Basis Spread Percentage | 73% | [1],[2] |
Valuation Technique, Option Pricing Model [Member] | Maximum [Member] | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Fair Value Inputs Basis Spread Percentage | 532% | [1],[2] |
Valuation Technique, Option Pricing Model [Member] | Weighted Average [Member] | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Fair Value Inputs Basis Spread Percentage | 157% | [1],[2] |
[1]Unobservable inputs were weighted by the relative fair value of the instruments.[2]Spread contemplates U.S. dollar-denominated pricing. |
Derivative Instruments - Schedu
Derivative Instruments - Schedule of Level 3 Activity (Details) - Physical Liquefaction Supply Derivatives [Member] - USD ($) $ in Millions | 12 Months Ended | ||||||
Dec. 31, 2022 | Dec. 31, 2021 | [1] | Dec. 31, 2020 | ||||
Fair Value, Assets (Liabilities) Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |||||||
Balance, beginning of period | $ (1,221) | [1] | $ 12 | $ 35 | |||
Realized and change in fair value gains (losses) included in net income: | |||||||
Included in cost of sales, existing deals | [2],[3] | (1,492) | (1,276) | 28 | |||
Included in cost of sales, new deals | [2],[4] | (2,172) | 0 | 0 | |||
Purchases and settlements: | |||||||
Purchases | [5] | (1,938) | 9 | 0 | |||
Settlements | [6] | 618 | 34 | (58) | |||
Transfers in and/or out of level 3 | |||||||
Transfers into level 3 | [7] | 0 | 0 | 7 | |||
Balance, end of period | (6,205) | (1,221) | 12 | [1] | |||
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period | $ (3,664) | $ (1,276) | $ 28 | ||||
[1] Includes amounts recorded related to natural gas supply contracts that CCL had with a related party. The agreement ceased to be considered a related party agreement during 2021, as discussed in Note 13—Related Party Transactions . Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period. For further discussion of IPM agreements that were novated to us during the period, see Note 3—CCL Stage III Contribution and Merger . |
Derivative Instruments - Sche_2
Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) - CCH Interest Rate Derivatives [Member] - USD ($) $ in Billions | Dec. 31, 2022 | Dec. 31, 2021 |
Derivative [Line Items] | ||
Derivative, Notional Amount | $ 0 | $ 4.5 |
Weighted Average Fixed Interest Rate Paid | 2.30% |
Derivative Instruments - Deriva
Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
CCH Interest Rate Derivatives [Member] | Interest rate derivative loss, net [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative gain (loss), net | $ 2 | $ (1) | $ (138) | |
CCH Interest Rate Forward Start Derivatives [Member] | Interest rate derivative loss, net [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative gain (loss), net | 0 | 0 | (95) | |
Liquefaction Supply Derivatives [Member] | LNG Revenues [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative gain (loss), net | [1] | 1 | 4 | (1) |
Liquefaction Supply Derivatives [Member] | Cost of Sales [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative gain (loss), net | [1] | (3,246) | (1,244) | (27) |
Liquefaction Supply Derivatives [Member] | Cost of sales—related party [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative gain (loss), net | [1],[2] | $ 0 | $ 11 | $ (1) |
[1]Does not include the value associated with derivative instruments that settle through physical delivery. Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.[2] Includes amounts recorded related to natural gas supply contracts that we had with a related party. This agreement ceased to be considered a related party agreement during 2021 as discussed in Note 13—Related Party Transactions . |
Derivative Instruments - Fair_3
Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | |
Derivatives, Fair Value [Line Items] | |||
Current derivative assets | $ 12 | $ 17 | |
Derivative assets | 7 | 37 | |
Total derivative assets | 19 | 54 | |
Current derivative liabilities | (1,374) | (668) | |
Derivative liabilities | (4,923) | (638) | |
Total derivative liabilities | (6,297) | (1,306) | |
Derivative liability, net | (6,278) | (1,252) | |
Current derivative assets | |||
Derivatives, Fair Value [Line Items] | |||
Current derivative assets | 12 | 17 | |
Derivative assets | |||
Derivatives, Fair Value [Line Items] | |||
Derivative assets | 7 | 37 | |
Current derivative liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Current derivative liabilities | (1,374) | (668) | |
Derivative liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Derivative liabilities | (4,923) | (638) | |
CCH Interest Rate Derivatives [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Total derivative assets | 0 | 0 | |
Total derivative liabilities | 0 | (40) | |
Derivative liability, net | 0 | (40) | |
CCH Interest Rate Derivatives [Member] | Current derivative assets | |||
Derivatives, Fair Value [Line Items] | |||
Current derivative assets | 0 | 0 | |
CCH Interest Rate Derivatives [Member] | Derivative assets | |||
Derivatives, Fair Value [Line Items] | |||
Derivative assets | 0 | 0 | |
CCH Interest Rate Derivatives [Member] | Current derivative liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Current derivative liabilities | 0 | (40) | |
CCH Interest Rate Derivatives [Member] | Derivative liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Derivative liabilities | 0 | 0 | |
Liquefaction Supply Derivatives [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Total derivative assets | [1] | 19 | 54 |
Total derivative liabilities | [1] | (6,297) | (1,266) |
Derivative liability, net | [1] | (6,278) | (1,212) |
Derivative, collateral posted by us | 76 | 13 | |
Liquefaction Supply Derivatives [Member] | Current derivative assets | |||
Derivatives, Fair Value [Line Items] | |||
Current derivative assets | [1] | 12 | 17 |
Liquefaction Supply Derivatives [Member] | Derivative assets | |||
Derivatives, Fair Value [Line Items] | |||
Derivative assets | [1] | 7 | 37 |
Liquefaction Supply Derivatives [Member] | Current derivative liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Current derivative liabilities | [1] | (1,374) | (628) |
Liquefaction Supply Derivatives [Member] | Derivative liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Derivative liabilities | [1] | $ (4,923) | $ (638) |
[1]Does not include collateral posted with counterparties by us of $76 million and $13 million as of December 31, 2022 and 2021, respectively, which are included in other current assets in our Consolidated Balance Sheets. Includes a natural gas supply contract that we had with a related party. This agreement ceased to be considered a related party agreement as of November 1, 2021. |
Derivative Instruments - Deri_2
Derivative Instruments - Derivative Net Presentation on Consolidated Balance Sheets (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
CCH Interest Rate Derivative Asset | ||
Derivative [Line Items] | ||
Derivative Asset, Gross Amounts Recognized | $ 0 | $ 0 |
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets | 0 | 0 |
Derivative Assets (Liabilities), at Fair Value, Net | 0 | 0 |
CCH Interest Rate Derivative Liability [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Gross Amounts Recognized | 0 | (40) |
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets | 0 | 0 |
Derivative Assets (Liabilities), at Fair Value, Net | 0 | (40) |
Liquefaction Supply Derivative Asset [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Gross Amounts Recognized | 19 | 76 |
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets | 0 | (22) |
Derivative Assets (Liabilities), at Fair Value, Net | 19 | 54 |
Liquefaction Supply Derivative Liability [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Gross Amounts Recognized | (6,622) | (1,295) |
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets | 325 | 29 |
Derivative Assets (Liabilities), at Fair Value, Net | $ (6,297) | $ (1,266) |
Other Non-Current Assets, Net_2
Other Non-Current Assets, Net (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Other Assets, Noncurrent [Abstract] | ||
Contract assets, net of current expected credit losses | $ 142 | $ 103 |
Advances and other asset conveyances to third parties to support LNG terminal | 62 | 24 |
Operating lease assets | 6 | 4 |
Information technology service prepayments | 3 | 3 |
Tax-related payments and receivables | 3 | 2 |
Other | 9 | 9 |
Total other non-current assets, net | $ 225 | $ 145 |
Accrued Liabilities (Details)
Accrued Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Accrued Liabilities, Current [Abstract] | ||
Natural gas purchases | $ 597 | $ 531 |
Interest costs and related debt fees | 150 | 7 |
Liquefaction Project costs | 103 | 43 |
Other accrued liabilities | 51 | 50 |
Total accrued liabilities | $ 901 | $ 631 |
Debt - Schedule of Debt Instrum
Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions | 2 Months Ended | |||
Feb. 16, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Debt Instrument [Line Items] | ||||
Debt, Long-term and Short-term, Combined Amount | $ 7,254 | $ 10,449 | ||
Current portion of long-term debt | (495) | (117) | ||
Short-term debt | 0 | (250) | ||
Unamortized discount and debt issuance costs, net | (61) | (96) | ||
Total long-term debt, net of discount and debt issuance costs | 6,698 | 9,986 | ||
CCH Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Long-term and Short-term, Combined Amount | $ 7,254 | 8,471 | ||
CCH Senior Notes [Member] | Subsequent Event [Member] | Cheniere [Member] | ||||
Debt Instrument [Line Items] | ||||
Repayments of Long-term Debt | $ 322 | |||
CCH Senior Notes [Member] | Weighted Average [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 4.64% | |||
2024 CCH Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Long-term and Short-term, Combined Amount | [1] | $ 498 | 1,250 | |
Debt Issuance Costs, Net | $ 3 | |||
Debt Instrument, Interest Rate, Stated Percentage | 7% | |||
2025 CCH Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Long-term and Short-term, Combined Amount | $ 1,491 | 1,500 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.875% | |||
2027 CCH Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Long-term and Short-term, Combined Amount | [2] | $ 1,271 | 1,500 | |
Debt Instrument, Interest Rate, Stated Percentage | 5.125% | |||
2029 CCH Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Long-term and Short-term, Combined Amount | [2] | $ 1,361 | 1,500 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.70% | |||
2039 CCH Senior Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Long-term and Short-term, Combined Amount | [2] | $ 2,633 | 2,721 | |
2039 CCH Senior Notes [Member] | Weighted Average [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 3.751% | |||
CCH Credit Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Long-term and Short-term, Combined Amount | $ 0 | 1,728 | ||
CCH Working Capital Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Long-term and Short-term, Combined Amount | [3] | 0 | $ 250 | |
Short-term debt | [4],[5] | $ 0 | ||
[1]In January 2023, we redeemed the remaining outstanding principal balance of the 2024 CCH Senior Notes with cash that was contributed to us from Cheniere prior to December 31, 2022. Therefore, the outstanding principal balance redeemed was classified as current portion of long-term debt as of December 31, 2022 net of discount and debt issuance costs of $3 million.[2]Subsequent to December 31, 2022 and through February 16, 2023, Cheniere executed bond repurchases totaling $322 million, inclusive of CCH’s Senior Secured Notes due 2027, 2029 and 2039 on the open market, which were immediately contributed to us from Cheniere and cancelled by us.[3]The CCH Working Capital Facility is classified as short-term debt.[4] Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the CCH Guarantors as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility. |
Debt - Senior Notes (Details)
Debt - Senior Notes (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2020 | |
Debt Instrument [Line Items] | ||
Contributions | $ 2,182 | $ 145 |
CCH Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Interest Paid at Time of Repayment of Debt | 30 | |
Write off of debt issuance costs and discount | $ 9 | |
CCH Senior Notes [Member] | Weighted Average [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.64% | |
2024 CCH Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Interest Rate, Stated Percentage | 7% | |
Cheniere [Member] | Debt Repurchase Related Activities | ||
Debt Instrument [Line Items] | ||
Contributions | $ 1,238 | |
Cheniere [Member] | Repurchase of Debt | ||
Debt Instrument [Line Items] | ||
Contributions | 1,217 | |
Cheniere [Member] | Interest Due | ||
Debt Instrument [Line Items] | ||
Contributions | 21 | |
Cheniere [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Repurchased Face Amount | 1,217 | |
Cheniere [Member] | 2024 CCH Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Repurchased Face Amount | 752 | |
Cheniere [Member] | Corpus Christi Holdings Senior Notes due 2025, 2027, 2029 and 2039 | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Repurchased Face Amount | $ 465 |
Debt - Schedule of Maturities (
Debt - Schedule of Maturities (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Long-term Debt, Fiscal Year Maturity [Abstract] | |
2023 | $ 498 |
2024 | 0 |
2025 | 1,491 |
2026 | 0 |
2027 | 1,354 |
Thereafter | 3,911 |
Total | $ 7,254 |
Debt - Credit Facilities Table
Debt - Credit Facilities Table (Details) $ in Millions | 12 Months Ended | |||||
Jun. 30, 2022 USD ($) | Dec. 31, 2022 USD ($) unit Rate | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |||
Line of Credit Facility [Line Items] | ||||||
Outstanding balance - current | $ 0 | $ 250 | ||||
Loss on modification or extinguishment of debt | $ (37) | $ (9) | $ (9) | |||
Debt, Minimum Historical Debt Service Coverage Ratio And Projected Debt Service Coverage Ratio | unit | 1.25 | |||||
CCH Credit Facility and CCH Working Capital Facility | ||||||
Line of Credit Facility [Line Items] | ||||||
Loss on modification or extinguishment of debt | $ 20 | |||||
CCH Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Total facility size | 4,000 | $ 3,260 | [1],[2] | |||
Outstanding balance | [1],[2] | 0 | ||||
Letters of credit issued | [1],[2] | 0 | ||||
Available commitment | [1],[2] | $ 3,260 | ||||
Debt Instrument, Description of Variable Rate Basis | SOFR or the base rate | |||||
Line of Credit Facility, Commitment Fee Percentage | Rate | [1],[2],[3] | 0.525% | ||||
Incremental commitments | 3,700 | |||||
CCH Credit Facility [Member] | Maximum [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Maturity Date | Jun. 15, 2029 | |||||
CCH Credit Facility [Member] | Base Rate [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | [1],[2],[3] | 0.50% | ||||
CCH Credit Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Credit Spread Adjustment On Variable Rate | Rate | [1],[2],[3] | 0.10% | ||||
Debt Instrument, Basis Spread on Variable Rate | Rate | [1],[2],[3] | 1.50% | ||||
CCH Working Capital Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Total facility size | 1,500 | $ 1,500 | [1],[4] | |||
Outstanding balance - current | [1],[4] | 0 | ||||
Letters of credit issued | [1],[4] | 178 | ||||
Available commitment | [1],[4] | $ 1,322 | ||||
Debt Instrument, Description of Variable Rate Basis | SOFR or the base rate | |||||
Maturity Date | [1],[4] | Jun. 15, 2027 | ||||
Incremental commitments | $ 300 | |||||
CCH Working Capital Facility [Member] | Minimum [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Commitment Fee Percentage | Rate | [1],[3],[4] | 0.10% | ||||
CCH Working Capital Facility [Member] | Maximum [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Line of Credit Facility, Commitment Fee Percentage | Rate | [1],[3],[4] | 0.20% | ||||
CCH Working Capital Facility [Member] | Base Rate [Member] | Minimum [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | Rate | [1],[3],[4] | 0% | ||||
CCH Working Capital Facility [Member] | Base Rate [Member] | Maximum [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | Rate | [1],[3],[4] | 0.50% | ||||
CCH Working Capital Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Credit Spread Adjustment On Variable Rate | Rate | [1],[3],[4] | 0.10% | ||||
CCH Working Capital Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Minimum [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | Rate | [1],[3],[4] | 1% | ||||
CCH Working Capital Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Maximum [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | Rate | [1],[3],[4] | 1.50% | ||||
[1]In June 2022, we amended and restated the CCH Credit Facility and the CCH Working Capital Facility resulting in $20 million of debt extinguishment and modification costs to, among other things, (1) provide incremental commitments of $3.7 billion and $300 million for the CCH Credit Facility and the CCH Working Capital Facility, respectively, in connection with the FID with respect to the Corpus Christi Stage 3 Project, (2) extend the maturity, (3) update the indexed interest rate to SOFR and (4) make certain other changes to the terms and conditions of each existing facility.[2]Our obligations under the CCH Credit Facility are secured by a first priority lien on substantially all of our assets and our subsidiaries and by a pledge by Cheniere CCH Holdco I of its limited liability company interests in us.[3]The margin on the interest rate and the commitment fees are subject to change based on the applicable entity’s credit rating.[4] Our obligations under the CCH Working Capital Facility are secured by substantially all of our assets and the CCH Guarantors as well as all of the membership interests in us and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility. |
Debt - Interest Expense (Detail
Debt - Interest Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Debt Disclosure [Abstract] | |||
Total interest cost | $ 465 | $ 473 | $ 484 |
Capitalized interest, including amounts capitalized as an Allowance for Funds Used During Construction | (33) | (26) | (119) |
Total interest expense, net of capitalized interest | $ 432 | $ 447 | $ 365 |
Debt - Schedule of Carrying Val
Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt, Carrying Value | $ 7,254 | $ 10,449 | |
Senior notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt, Carrying Value | [1] | 5,283 | 6,500 |
Senior notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Debt, Carrying Value | [2] | 1,971 | 1,971 |
Senior notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Notes Payable, Fair Value Disclosure | [1] | 5,014 | 7,095 |
Senior notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Notes Payable, Fair Value Disclosure | [2] | $ 1,738 | $ 2,227 |
[1]The Level 2 estimated fair value was based on quotes obtained from broker-dealers or market makers of these senior notes and other similar instruments.[2]The Level 3 estimated fair value was calculated based on inputs that are observable in the market or that could be derived from, or corroborated with, observable market data, including interest rates based on debt issued by parties with comparable credit ratings to us and inputs that are not observable in the market. |
Revenues - Narrative (Details)
Revenues - Narrative (Details) | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
LNG Volume, Purchase Price Percentage of Henry Hub | 115% |
Revenues - Schedule of Disaggre
Revenues - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | $ 9,362 | $ 5,790 | $ 2,530 | |
Net derivative gain (loss) | [1] | 1 | 4 | (1) |
Revenues | 9,363 | 5,794 | 2,529 | |
LNG [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | [2] | 6,335 | 3,903 | 2,047 |
Revenues | 6,336 | 3,907 | 2,046 | |
Suspension Fees and LNG Cover Damages Revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 0 | 0 | 435 | |
Suspension Fees and LNG Cover Damages Revenue | Subsequent Period | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 38 | |||
LNG—affiliate [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | $ 3,027 | $ 1,887 | $ 483 | |
[1] See Note 8 —Derivative Instruments 2021 had the cargoes been lifted pursuant to the delivery schedules with the customers. We did not have revenues associated with LNG cargoes for which customers notified us that they would not take delivery during the years ended December 31, 2022 and 2021. Revenue is generally recognized upon receipt of irrevocable notice that a customer will not take delivery because our customers have no contractual right to take delivery of such LNG cargo in future periods and our performance obligations with respect to such LNG cargo have been satisfied. |
Revenues - Contract Assets and
Revenues - Contract Assets and Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | ||
Contract assets, net of current expected credit losses | $ 144 | $ 104 |
Change in Contract with Customer, Liability [Roll Forward] | ||
Deferred revenue, beginning of period | 35 | |
Cash received but not yet recognized in revenue | 76 | |
Revenue recognized from prior period deferral | (35) | |
Deferred revenue, end of period | $ 76 |
Revenues - Schedule of Transact
Revenues - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Unsatisfied Transaction Price | $ 32.8 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Unsatisfied Transaction Price | $ 52.1 | ||
LNG [Member] | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Revenue, Variable Consideration Received From Customers, Percentage | 70% | 58% | |
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Unsatisfied Transaction Price | $ 31.7 | ||
Weighted Average Recognition Timing | [1] | 9 years | |
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Unsatisfied Transaction Price | $ 50.9 | ||
Weighted Average Recognition Timing | [1] | 10 years | |
LNG—affiliate [Member] | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Revenue, Variable Consideration Received From Customers, Percentage | 86% | 0% | |
LNG—affiliate [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Unsatisfied Transaction Price | $ 1.1 | ||
Weighted Average Recognition Timing | [1] | 10 years | |
LNG—affiliate [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Unsatisfied Transaction Price | $ 1.2 | ||
Weighted Average Recognition Timing | [1] | 8 years | |
[1]The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price. |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Related Party Transaction [Line Items] | ||||
LNG revenues—affiliate | $ 9,362 | $ 5,790 | $ 2,530 | |
Cost of sales—affiliate | 103 | 50 | 30 | |
Cost of sales—related party | 0 | 146 | 114 | |
Operating and maintenance expense—affiliate | 121 | 106 | 90 | |
Operating and maintenance expense—related party | 9 | 9 | 6 | |
General and administrative expense—affiliate | 38 | 28 | 20 | |
LNG—affiliate [Member] | ||||
Related Party Transaction [Line Items] | ||||
LNG revenues—affiliate | 3,027 | 1,887 | 483 | |
Cheniere Marketing Agreements [Member] | ||||
Related Party Transaction [Line Items] | ||||
Cost of sales—affiliate | [1],[2] | 0 | 31 | 0 |
Cheniere Marketing Agreements [Member] | LNG—affiliate [Member] | ||||
Related Party Transaction [Line Items] | ||||
LNG revenues—affiliate | [2] | 2,993 | 1,837 | 468 |
Contracts for Sale and Purchase of Natural Gas And LNG [Member] | ||||
Related Party Transaction [Line Items] | ||||
Cost of sales—affiliate | [3] | 103 | 19 | 30 |
Contracts for Sale and Purchase of Natural Gas And LNG [Member] | LNG—affiliate [Member] | ||||
Related Party Transaction [Line Items] | ||||
LNG revenues—affiliate | [3] | 34 | 50 | 15 |
Natural Gas Supply Agreement [Member] | ||||
Related Party Transaction [Line Items] | ||||
Cost of sales—related party | [4] | 0 | 146 | 114 |
Service Agreements [Member] | ||||
Related Party Transaction [Line Items] | ||||
Operating and maintenance expense—affiliate | [5] | 120 | 105 | 89 |
General and administrative expense—affiliate | [5] | 38 | 28 | 20 |
Land Agreements [Member] | ||||
Related Party Transaction [Line Items] | ||||
Operating and maintenance expense—affiliate | [6] | 1 | 1 | 1 |
Natural Gas Transportation Agreement [Member] | ||||
Related Party Transaction [Line Items] | ||||
Operating and maintenance expense—related party | [7] | $ 9 | $ 9 | $ 6 |
[1]CCL and Cheniere Marketing have entered into Shipping Services Agreements (“SSAs”) for the provision of certain shipping and transportation-related services associated with certain SPAs between CCL and third-party customers that are delivered to the customer at their specified LNG receiving terminal. Under the SSAs, CCL pays Cheniere Marketing a fee of 3% to 7% of Henry Hub plus a fixed fee for the shipping services provided. Deliveries under the SSAs will commence in 2023.[2]CCL primarily sells LNG to Cheniere Marketing International LLP (“Cheniere Marketing”), a wholly owned subsidiary of Cheniere, under SPAs and a letter agreement at a price equal to 115% of Henry Hub plus a fixed fee, except for SPAs associated with IPM agreements for which pricing is linked to international natural gas prices. In addition, CCL has an arrangement with subsidiaries of Cheniere to provide the ability, in limited circumstances, to potentially fulfill commitments to LNG buyers in the event operational conditions impact operations at either the Sabine Pass or Corpus Christi liquefaction facilities. The purchase price for such cargoes would be the greater of: (a) 115% of the applicable natural gas feedstock purchase price or (b) an FOB U.S. Gulf Coast LNG market price. As of December 31, 2022 and 2021, CCL had $223 million and $314 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing.[3]CCL has an agreement with Sabine Pass Liquefaction, LLC that allows the parties to sell and purchase natural gas with each other. Natural gas purchased under this agreement is initially recorded as inventory and then to cost of sales—affiliate upon its sale, except for purchases related to commissioning activities which are capitalized as LNG terminal construction-in-process. As of December 31, 2022 and 2021, CCL had $16 million and $1 million of accounts receivable—affiliate, respectively, under these agreements with Cheniere Marketing.[4]CCL was party to a natural gas supply agreement with a related party in the ordinary course of business, to obtain a fixed minimum daily volume of feed gas for the operation of the Liquefaction Project. The related party entity was acquired by a non-related party on November 1, 2021, therefore, as of such date, this agreement ceased to be considered a related party agreement. CCL also has an agreement with Midship Pipeline Company, LLC that allows them to sell and purchase natural gas with each other.[5]We do not have employees and thus 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. Prior to the substantial completion of each Train of the Liquefaction Project, our payments under the services agreements are primarily based on a cost reimbursement structure, and following the completion of each Train, our payments include a fixed monthly fee (indexed for inflation) per mtpa in addition to the reimbursement of costs. As of December 31, 2022 and 2021, we had $132 million and $128 million of advances to affiliates, respectively, under the services agreements. The non-reimbursement amounts incurred under these agreements are recorded in general and administrative expense—affiliate.[6]CCL has agreements with Cheniere Land Holdings, LLC, a wholly owned subsidiary of Cheniere, to rent, obtain easements and license to enter the land owned by CLH for the Liquefaction Project.[7]CCL is party to natural gas transportation agreements with a related party in the ordinary course of business for the operation of the Liquefaction Project. CCL recorded accrued liabilities—related party of $1 million as of both December 31, 2022 and 2021 with this related party. |
Related Party Transactions - Ta
Related Party Transactions - Table Footnotes (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Related Party Transaction [Line Items] | ||
LNG Volume, Purchase Price Percentage of Henry Hub | 115% | |
Accounts receivable—affiliate | $ 240 | $ 315 |
Advances to affiliate | 132 | 128 |
Accrued liabilities—related party | 1 | 1 |
Due to affiliates | 43 | 35 |
CCL [Member] | Natural Gas Transportation Agreement [Member] | ||
Related Party Transaction [Line Items] | ||
Accrued liabilities—related party | $ 1 | 1 |
CCL [Member] | Affiliated Entity [Member] | Facility Swap Agreement [Member] | ||
Related Party Transaction [Line Items] | ||
LNG Volume, Purchase Price Percentage of Henry Hub | 115% | |
CCL [Member] | Cheniere Marketing [Member] | Cheniere Marketing Agreements [Member] | ||
Related Party Transaction [Line Items] | ||
LNG Volume, Purchase Price Percentage of Henry Hub | 115% | |
Accounts receivable—affiliate | $ 223 | 314 |
CCL [Member] | Cheniere Marketing [Member] | Shipping Services Agreements [Member] | Minimum [Member] | ||
Related Party Transaction [Line Items] | ||
Shipping Fee, Variable Price, Percentage of Henry Hub | 3% | |
CCL [Member] | Cheniere Marketing [Member] | Shipping Services Agreements [Member] | Maximum [Member] | ||
Related Party Transaction [Line Items] | ||
Shipping Fee, Variable Price, Percentage of Henry Hub | 7% | |
CCL [Member] | SPL | Contracts for Sale and Purchase of Natural Gas And LNG [Member] | ||
Related Party Transaction [Line Items] | ||
Accounts receivable—affiliate | $ 16 | $ 1 |
Related Party Transactions - Ot
Related Party Transactions - Other Agreements (Details) | 12 Months Ended |
Dec. 31, 2022 USD ($) mi | |
ADCC Pipeline | |
Related Party Transaction [Line Items] | |
Length Of Natural Gas Pipeline | mi | 42 |
CCL [Member] | Cheniere [Member] | Tax Sharing Agreement [Member] | |
Related Party Transaction [Line Items] | |
Income Taxes Paid, Net | $ 0 |
CCL [Member] | ADCC Pipeline, LLC | Natural Gas Transportation Agreement [Member] | |
Related Party Transaction [Line Items] | |
Long-term Purchase Commitment, Period | 20 years |
CCP [Member] | Cheniere [Member] | Tax Sharing Agreement [Member] | |
Related Party Transaction [Line Items] | |
Income Taxes Paid, Net | $ 0 |
Cheniere [Member] | |
Related Party Transaction [Line Items] | |
Debt Instrument, Repurchased Face Amount | 1,217,000,000 |
Cheniere [Member] | Corpus Christi Holdings Senior Notes due 2025, 2027, 2029 and 2039 | |
Related Party Transaction [Line Items] | |
Debt Instrument, Repurchased Face Amount | $ 465,000,000 |
Cheniere [Member] | ADCC Pipeline, LLC | |
Related Party Transaction [Line Items] | |
Equity Method Investment, Ownership Percentage | 30% |
Cheniere [Member] | ADCC Pipeline, LLC | Maximum [Member] | |
Related Party Transaction [Line Items] | |
Funding Commitment | $ 93,000,000 |
Commitments and Contingencies -
Commitments and Contingencies - Narrative (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2022 USD ($) item | |
Commitments and Contingencies [Line Items] | |
Loss Contingency, Pending Claims, Number | item | 0 |
Natural Gas Supply Agreements [Member] | CCL [Member] | Maximum [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Period | 15 years |
Natural Gas Transportation Agreements [Member] | CCL [Member] | Maximum [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Period | 20 years |
Storage Service Agreements [Member] | CCL [Member] | Maximum [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Period | 5 years |
Service Agreements, Shipping Services Agreements, and Other Agreements | Third Party | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Amount | $ 200 |
Service Agreements, Shipping Services Agreements, and Other Agreements | Affiliated Entity [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Amount | 7,500 |
Bechtel EPC Contract Corpus Christi Stage 3 | CCL [Member] | |
Commitments and Contingencies [Line Items] | |
Long-term Purchase Commitment, Amount | 5,400 |
Purchase Commitment, Remaining Minimum Amount Committed | $ 3,900 |
Commitments and Contingencies_2
Commitments and Contingencies - Purchase Obligation Table (Details) - CCL [Member] - Natural Gas Supply, Transportation And Storage Service Agreements [Member] $ in Billions | Dec. 31, 2022 USD ($) | [1] |
Third Party | ||
Long-term Purchase Commitment [Line Items] | ||
2023 | $ 4.4 | |
2024 | 4.1 | |
2025 | 3.6 | |
2026 | 3.2 | |
2027 | 3.4 | |
Thereafter | 24.1 | |
Total | 42.8 | |
Related Party | ||
Long-term Purchase Commitment [Line Items] | ||
2023 | 0 | |
2024 | 0 | |
2025 | 0 | |
2026 | 0.1 | |
2027 | 0.1 | |
Thereafter | 0.8 | |
Total | $ 1 | |
[1] Pricing of natural gas supply contracts is variable based on market commodity basis prices adjusted for basis spread, and pricing of IPM agreements is variable based on global gas market prices less fixed liquefaction fees and certain costs incurred by us . Amounts included are based on estimated forward prices and basis spreads as of December 31, 2022. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services. |
Customer Concentration - Schedu
Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member] | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Customer A [Member] | Total Revenues from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 21% | 21% | 31% |
Customer A [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 17% | ||
Customer B [Member] | Total Revenues from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 14% | 16% | 16% |
Customer C [Member] | Total Revenues from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 14% | 15% | 14% |
Customer D [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 33% | 31% | |
Customer E [Member] | Total Revenues from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 0% | ||
Customer E [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 11% | ||
Customer F [Member] | Total Revenues from External Customers [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 10% | 0% |
Customer Concentration - Sche_2
Customer Concentration - Schedule of Revenue from External Customers by Country (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Concentration Risk [Line Items] | |||
Revenues from External Customers | $ 9,363 | $ 5,794 | $ 2,529 |
LNG [Member] | |||
Concentration Risk [Line Items] | |||
Revenues from External Customers | 6,336 | 3,907 | 2,046 |
Geographic Concentration Risk [Member] | Spain | |||
Concentration Risk [Line Items] | |||
Revenues from External Customers | 2,192 | 1,432 | 1,001 |
Geographic Concentration Risk [Member] | Singapore | |||
Concentration Risk [Line Items] | |||
Revenues from External Customers | 1,248 | 694 | 134 |
Geographic Concentration Risk [Member] | France | |||
Concentration Risk [Line Items] | |||
Revenues from External Customers | 940 | 423 | 136 |
Geographic Concentration Risk [Member] | Indonesia | |||
Concentration Risk [Line Items] | |||
Revenues from External Customers | 889 | 618 | 336 |
Geographic Concentration Risk [Member] | Ireland | |||
Concentration Risk [Line Items] | |||
Revenues from External Customers | 868 | 599 | 285 |
Geographic Concentration Risk [Member] | United States | |||
Concentration Risk [Line Items] | |||
Revenues from External Customers | $ 199 | $ 141 | $ 154 |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Supplemental Cash Flow Information [Abstract] | |||
Cash paid during the period for interest on debt, net of amounts capitalized | $ 280 | $ 423 | $ 345 |
Right-of-use assets obtained in exchange for new operating lease liabilities | 3 | 0 | 0 |
Transfers of property, plant and equipment in exchange for other non-current assets | 17 | 0 | 2 |
Non-cash contributions from affiliates for conveyance of assets | 7 | 0 | 0 |
Debt Instrument, Repurchased Face Amount, Contributed from Affiliate | 1,217 | 0 | 0 |
Contribution of CCL Stage III entity to us from Cheniere | (1,482) | 0 | 0 |
Balance in property, plant and equipment, net of accumulated depreciation funded with accounts payable and accrued liabilities (including affiliate) | $ 70 | $ 20 | $ 86 |
Schedule II - Valuation and Q_2
Schedule II - Valuation and Qualifying Accounts (Details) - Current expected credit losses on receivables and contract assets - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items] | |||
Balance at beginning of period | $ 3 | $ 2 | $ 0 |
Charged to costs and expenses | 1 | 1 | 2 |
Charged to other accounts | 0 | 0 | 0 |
Deductions | 0 | 0 | 0 |
Balance at end of period | $ 4 | $ 3 | $ 2 |