Cover Page Cover Page
Cover Page Cover Page - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Feb. 11, 2022 | Jun. 30, 2021 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2021 | ||
Document Transition Report | false | ||
Entity File Number | 1-32740 | ||
Entity Registrant Name | ENERGY TRANSFER LP | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 30-0108820 | ||
Entity Address, Address Line One | 8111 Westchester Drive | ||
Entity Address, Address Line Two | Suite 600 | ||
Entity Address, City or Town | Dallas | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 75225 | ||
City Area Code | 214 | ||
Local Phone Number | 981-0700 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 28,650 | ||
Entity Common Stock, Shares Outstanding | 3,082,828,515 | ||
Documents Incorporated by Reference | None | ||
Entity Central Index Key | 0001276187 | ||
Document Fiscal Year Focus | 2021 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
ICFR Auditor Attestation Flag | true | ||
Document Information [Line Items] | |||
Document Transition Report | false | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2021 | ||
Current Fiscal Year End Date | --12-31 | ||
Auditor Firm ID | 248 | ||
Auditor Location | Dallas, Texas | ||
Auditor Name | GRANT THORNTON LLP | ||
Common Stock | |||
Cover [Abstract] | |||
Title of 12(b) Security | Common Units | ||
Trading Symbol | ET | ||
Security Exchange Name | NYSE | ||
Document Information [Line Items] | |||
Title of 12(b) Security | Common Units | ||
Trading Symbol | ET | ||
Security Exchange Name | NYSE | ||
ETprC | |||
Cover [Abstract] | |||
Title of 12(b) Security | 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Trading Symbol | ETprC | ||
Security Exchange Name | NYSE | ||
Document Information [Line Items] | |||
Title of 12(b) Security | 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Trading Symbol | ETprC | ||
Security Exchange Name | NYSE | ||
ETprD | |||
Cover [Abstract] | |||
Title of 12(b) Security | 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Trading Symbol | ETprD | ||
Security Exchange Name | NYSE | ||
Document Information [Line Items] | |||
Title of 12(b) Security | 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Trading Symbol | ETprD | ||
Security Exchange Name | NYSE | ||
ETprE | |||
Cover [Abstract] | |||
Title of 12(b) Security | 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Trading Symbol | ETprE | ||
Security Exchange Name | NYSE | ||
Document Information [Line Items] | |||
Title of 12(b) Security | 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Trading Symbol | ETprE | ||
Security Exchange Name | NYSE |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
ASSETS | ||
Cash and cash equivalents | $ 336 | $ 367 |
Accounts receivable, net | 7,654 | 3,875 |
Accounts receivable from related companies | 54 | 79 |
Inventories | 2,014 | 1,739 |
Income taxes receivable | 32 | 35 |
Derivative assets | 10 | 9 |
Other current assets | 437 | 213 |
Total current assets | 10,537 | 6,317 |
Property, plant and equipment | 103,991 | 94,115 |
Accumulated depreciation and depletion | (22,384) | (19,008) |
Property, Plant and Equipment, Net | 81,607 | 75,107 |
Investments in unconsolidated affiliates | 2,947 | 3,060 |
Lease right-of-use assets, net | 838 | 866 |
Other non-current assets, net | 1,645 | 1,657 |
Intangible assets, net | 5,856 | 5,746 |
Goodwill | 2,533 | 2,391 |
Total assets | 105,963 | 95,144 |
LIABILITIES AND EQUITY | ||
Accounts payable | 6,834 | 2,809 |
Accounts payable to related companies | 0 | 27 |
Derivative liabilities | 203 | 238 |
Operating lease current liabilities | 47 | 53 |
Accrued and other current liabilities | 3,071 | 2,775 |
Current maturities of long-term debt | 680 | 21 |
Total current liabilities | 10,835 | 5,923 |
Long-term debt, less current maturities | 49,022 | 51,417 |
Non-current derivative liabilities | 193 | 237 |
Non-current operating lease liabilities | 814 | 837 |
Deferred income taxes | 3,648 | 3,428 |
Other non-current liabilities | 1,323 | 1,152 |
Commitments and contingencies | ||
Redeemable noncontrolling interests | 783 | 762 |
Limited Partners: | ||
Preferred Unitholders (72,184,780 units authorized, issued and outstanding as of December 31, 2021) | 6,051 | 0 |
Common Unitholders (3,082,517,494 and 2,702,372,154 units authorized, issued and outstanding as of December 31, 2021 and 2020, respectively) | 25,230 | 18,531 |
General Partner | (4) | (8) |
Accumulated other comprehensive income | 23 | 6 |
Total partners’ capital | 31,300 | 18,529 |
Noncontrolling interests | 8,045 | 12,859 |
Total equity | 39,345 | 31,388 |
Total liabilities and equity | $ 105,963 | $ 95,144 |
Consolidated Balance Sheets Bal
Consolidated Balance Sheets Balance Sheet (Paranthetical) - shares | Dec. 31, 2021 | Dec. 31, 2020 |
Class of Stock [Line Items] | ||
Authorized | 3,082,497,494 | 2,702,352,154 |
Issued | 3,082,497,494 | 2,702,352,154 |
Outstanding | 3,082,497,494 | 2,702,352,154 |
Preferred Units, Authorized | 72,184,780 | 0 |
Preferred Units, Issued | 72,184,780 | 0 |
Preferred Units, Outstanding | 72,184,780 | 0 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
REVENUES: | |||
Total revenues | $ 67,417 | $ 38,954 | $ 54,213 |
COSTS AND EXPENSES: | |||
Cost of products sold | 50,395 | 25,487 | 39,801 |
Operating expenses | 3,574 | 3,218 | 3,294 |
Depreciation, depletion and amortization | 3,817 | 3,678 | 3,147 |
Selling, general and administrative | 818 | 711 | 694 |
Impairment losses | 21 | 2,880 | 74 |
Total costs and expenses | 58,625 | 35,974 | 47,010 |
OPERATING INCOME | 8,792 | 2,980 | 7,203 |
OTHER INCOME (EXPENSE): | |||
Interest expense, net of interest capitalized | (2,267) | (2,327) | (2,331) |
Equity in earnings of unconsolidated affiliates | 246 | 119 | 302 |
Impairment of investments in unconsolidated affiliates | 0 | (129) | 0 |
Losses on extinguishments of debt | (38) | (75) | (18) |
Gains (losses) on interest rate derivatives | 61 | (203) | (241) |
Other, net | 77 | 12 | 105 |
Income before income tax expense | 6,871 | 377 | 5,020 |
Income tax expense | 184 | 237 | 195 |
NET INCOME | 6,687 | 140 | 4,825 |
Less: Net income attributable to noncontrolling interests | 1,167 | 739 | 1,256 |
Less: Net income attributable to redeemable noncontrolling interests | 50 | 49 | 51 |
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS | 5,470 | (648) | 3,518 |
General Partner’s interest in net income (loss) | 6 | (1) | 4 |
Preferred Unitholders’ interest in net income | 285 | 0 | 0 |
Limited Partners’ interest in net income | $ 5,179 | $ (647) | $ 3,514 |
NET INCOME (LOSS) PER LIMITED PARTNER UNIT: | |||
Basic | $ 1.89 | $ (0.24) | $ 1.34 |
Diluted | $ 1.89 | $ (0.24) | $ 1.33 |
Refined product sales | |||
REVENUES: | |||
REVENUES: | $ 17,766 | $ 10,514 | $ 16,752 |
Crude sales | |||
REVENUES: | |||
REVENUES: | 15,299 | 9,442 | 15,917 |
Natural gas sales | |||
REVENUES: | |||
REVENUES: | 9,159 | 2,633 | 3,295 |
Gathering, transportation and other fees | |||
REVENUES: | |||
REVENUES: | 9,229 | 8,982 | 9,086 |
NGL sales | |||
REVENUES: | |||
REVENUES: | 15,243 | 6,797 | 8,290 |
Other | |||
REVENUES: | |||
REVENUES: | $ 721 | $ 586 | $ 873 |
Consolidated Statements Of Comp
Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Statement of Comprehensive Income [Abstract] | |||
NET INCOME | $ 6,687 | $ 140 | $ 4,825 |
Other comprehensive income (loss), net of tax: | |||
Change in value of available-for-sale securities | 1 | 5 | 11 |
Actuarial gain relating to pension and other postretirement benefits | 12 | 18 | 24 |
Foreign currency translation adjustment | 4 | 5 | 6 |
Change in other comprehensive income from unconsolidated affiliates | 3 | (13) | (10) |
Other comprehensive income (loss), net of tax, total | 20 | 15 | 31 |
Comprehensive income | 6,707 | 155 | 4,856 |
Less: Comprehensive income attributable to noncontrolling interests | 1,170 | 738 | 1,256 |
Less: Comprehensive income attributable to redeemable noncontrolling interests | 50 | 49 | 51 |
Comprehensive income (loss) attributable to partners | $ 5,487 | $ (632) | $ 3,549 |
Consolidated Statement Of Equit
Consolidated Statement Of Equity - USD ($) $ in Thousands | Total | General Partner | Accumulated Other Comprehensive Income (Loss) | Common Unitholders | Non- controlling Interests | Preferred Unitholders | Enable | EnableGeneral Partner | EnableAccumulated Other Comprehensive Income (Loss) | EnableCommon Unitholders | EnableNon- controlling Interests | EnablePreferred Unitholders | Rollup Mergers | Rollup MergersGeneral Partner | Rollup MergersAccumulated Other Comprehensive Income (Loss) | Rollup MergersCommon Unitholders | Rollup MergersNon- controlling Interests | Rollup MergersPreferred Unitholders |
Balance at Dec. 31, 2018 | $ 31,017,000 | $ (5,000) | $ (42,000) | $ 20,773,000 | $ 10,291,000 | $ 0 | ||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||
Distributions to partners | (3,054,000) | (3,000) | 0 | (3,051,000) | 0 | 0 | ||||||||||||
Distributions to noncontrolling interests | (1,597,000) | 0 | 0 | 0 | (1,597,000) | 0 | ||||||||||||
Common units repurchased under buyback program | (25,000) | 0 | 0 | (25,000) | 0 | 0 | ||||||||||||
Subsidiary unit transactions | 780,000 | 0 | 0 | 0 | 780,000 | 0 | ||||||||||||
Capital contributions from noncontrolling interests | 348,000 | 0 | 0 | 0 | 348,000 | 0 | ||||||||||||
Other, net | 100,000 | 0 | 0 | 72,000 | 28,000 | 0 | ||||||||||||
Acquisition and disposition of noncontrolling interest | (93,000) | 0 | 0 | 0 | (93,000) | 0 | ||||||||||||
Partners' Capital Account, Acquisitions | 1,471,000 | 0 | 0 | 652,000 | 819,000 | 0 | ||||||||||||
Other comprehensive income, net of tax | 31,000 | 0 | 31,000 | 0 | 0 | 0 | ||||||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest | 4,774,000 | 4,000 | 0 | 3,514,000 | 1,256,000 | 0 | ||||||||||||
Balance at Dec. 31, 2019 | 33,938,000 | (4,000) | (11,000) | 21,935,000 | 12,018,000 | 0 | ||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||
Distributions to partners | (2,802,000) | (3,000) | 0 | (2,799,000) | 0 | 0 | ||||||||||||
Distributions to noncontrolling interests | (1,651,000) | 0 | 0 | 0 | (1,651,000) | 0 | ||||||||||||
Common units repurchased under buyback program | 0 | |||||||||||||||||
Subsidiary unit transactions | 1,580,000 | 0 | 0 | 0 | 1,580,000 | 0 | ||||||||||||
Capital contributions from noncontrolling interests | 222,000 | 0 | 0 | 0 | 222,000 | 0 | ||||||||||||
Other, net | (5,000) | 0 | 1,000 | 42,000 | (48,000) | 0 | ||||||||||||
Other comprehensive income, net of tax | 15,000 | 0 | 16,000 | 0 | (1,000) | 0 | ||||||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest | 91,000 | (1,000) | 0 | (647,000) | 739,000 | 0 | ||||||||||||
Balance at Dec. 31, 2020 | 31,388,000 | (8,000) | 6,000 | 18,531,000 | 12,859,000 | 0 | ||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||
Distributions to partners | (1,898,000) | (2,000) | 0 | (1,616,000) | 0 | (280,000) | ||||||||||||
Distributions to noncontrolling interests | (1,487,000) | 0 | 0 | 0 | (1,487,000) | 0 | ||||||||||||
Common units repurchased | (31,000) | 0 | 0 | (31,000) | 0 | 0 | ||||||||||||
Common units repurchased under buyback program | (31,000) | |||||||||||||||||
Units issued | 889,000 | 0 | 0 | 0 | 0 | 889,000 | ||||||||||||
Capital contributions from noncontrolling interests | 226,000 | 0 | 0 | 0 | 226,000 | 0 | ||||||||||||
Other, net | 58,000 | 0 | 0 | 50,000 | 11,000 | (3,000) | ||||||||||||
Partners' Capital Account, Acquisitions | $ 3,543,000 | $ 0 | $ 0 | $ 3,117,000 | $ 34,000 | $ 392,000 | $ 0 | $ 0 | $ 0 | $ 0 | $ (4,768,000) | $ 4,768,000 | ||||||
Other comprehensive income, net of tax | 20,000 | 0 | 17,000 | 0 | 3,000 | 0 | ||||||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest, Excluding Portion Attributable to Redeemable Noncontrolling Interest | 6,637,000 | 6,000 | 0 | 5,179,000 | 1,167,000 | 285,000 | ||||||||||||
Balance at Dec. 31, 2021 | $ 39,345,000 | $ (4,000) | $ 23,000 | $ 25,230,000 | $ 8,045,000 | $ 6,051,000 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
NET INCOME | $ 6,687 | $ 140 | $ 4,825 |
Reconciliation of net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 3,817 | 3,678 | 3,147 |
Deferred income taxes | (141) | (210) | (217) |
Inventory valuation adjustments | (190) | 82 | (79) |
Non-cash compensation expense | 111 | 121 | 113 |
Impairment losses | 21 | 2,880 | 74 |
Impairment of investment in unconsolidated affiliates | 0 | 129 | 0 |
Losses on extinguishments of debt | 38 | 75 | 18 |
Distributions on unvested awards | 47 | 41 | 38 |
Distributions from unconsolidated affiliates | 212 | 220 | 290 |
Equity in earnings of unconsolidated affiliates | (246) | (119) | (302) |
Other non-cash | (103) | 61 | (182) |
Net change in operating assets and liabilities, net of effects of acquisitions | 515 | 47 | (391) |
Net cash provided by operating activities | 11,162 | 7,361 | 8,056 |
INVESTING ACTIVITIES: | |||
Cash Acquired from Acquisition | 51 | 0 | 0 |
Cash received for sale of noncontrolling interest | 0 | 0 | 93 |
Cash paid for acquisitions, net of cash received | (256) | 0 | (7) |
Capital expenditures, excluding allowance for equity funds used during construction | (2,822) | (5,130) | (5,960) |
Contributions in aid of construction costs | 43 | 67 | 80 |
Contributions to unconsolidated affiliates | (4) | (38) | (523) |
Distributions from unconsolidated affiliates in excess of cumulative earnings | 167 | 187 | 98 |
Proceeds from sales of other assets | 45 | 19 | 54 |
Other | 1 | (3) | 18 |
Net cash used in investing activities | (2,775) | (4,898) | (6,934) |
FINANCING ACTIVITIES: | |||
Proceeds from borrowings | 21,267 | 24,440 | 22,583 |
Repayments of debt | (27,318) | (24,133) | (20,101) |
Preferred units issued for cash | 889 | 0 | 0 |
Subsidiary units issued for cash | 0 | 1,580 | 780 |
Distributions to partners | (1,898) | (2,802) | (3,054) |
Distributions to noncontrolling interests | (1,487) | (1,651) | (1,597) |
Distributions to redeemable noncontrolling interests | 49 | 49 | 53 |
Common units repurchased under buyback program | (31) | 0 | (25) |
Debt issuance costs | (14) | (59) | (117) |
Capital contributions from noncontrolling interests | 226 | 222 | 348 |
Other, net | (3) | 65 | (14) |
Net cash used in financing activities | (8,418) | (2,387) | (1,250) |
Increase (decrease) in cash and cash equivalents | (31) | 76 | (128) |
Cash and cash equivalents, beginning of period | 367 | 291 | 419 |
Cash and cash equivalents, end of period | 336 | 367 | 291 |
SemGroup [Member] | |||
INVESTING ACTIVITIES: | |||
Cash paid for acquisitions, net of cash received | $ 0 | $ 0 | $ (787) |
Operations And Organization
Operations And Organization | 12 Months Ended |
Dec. 31, 2021 | |
Operations And Organization [Abstract] | |
Operations And Organization | OPERATIONS AND BASIS OF PRESENTATION : The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “Energy Transfer”). On April 1, 2021, Energy Transfer, ETO and certain of ETO’s subsidiaries consummated several internal reorganization transactions (the “Rollup Mergers”). In connection with the Rollup Mergers, ETO merged with and into Energy Transfer, with Energy Transfer surviving. The impacts of the Rollup Mergers also included the following: • All of ETO’s long-term debt was assumed by Energy Transfer, as more fully described in Note 6. • Each issued and outstanding ETO preferred unit was converted into the right to receive one newly created Energy Transfer preferred unit. A description of the Energy Transfer Preferred Units is included in Note 8. • Each of ETO’s issued and outstanding Class K, Class L, Class M and Class N units were converted into an aggregate 675,625,000 newly created Class B Units representing limited partner interests in Energy Transfer. All of the Class B Units are held by ETP Holdco, a wholly-owned subsidiary of Energy Transfer. Our financial statements reflect the following reportable segments: • intrastate transportation and storage; • interstate transportation and storage; • midstream; • NGL and refined products transportation and services; • crude oil transportation and services; • investment in Sunoco LP; • investment in USAC; and • all other. The Partnership owns and operates intrastate natural gas pipeline systems and storage facilities that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Oklahoma, Louisiana, New Mexico and West Virginia. The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States. The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Granite Wash, SCOOP, STACK, Woodford, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales. The Partnership owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products. The Partnership owns a controlling interest in Sunoco LP which is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites. As of December 31, 2021, our interest in Sunoco LP consisted of 100% of the general partner and IDRs, as well as 28.5 million common units. The Partnership owns a controlling interest in USAC which provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. As of December 31, 2021, our interest in USAC consisted of 100% of the general partner and 46.1 million common units. Basis of Presentation. The consolidated financial statements of Energy Transfer LP presented herein for the years ended December 31, 2021, 2020 and 2019, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. The consolidated financial statements of Energy Transfer presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC. |
Estimates, Significant Accounti
Estimates, Significant Accounting Policies and Balance Sheet Detail | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Estimates, Significant Accounting Policies and Balance Sheet Detail | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL : Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities, in accordance with Accounting Standards Codification (“ASC”) Topic 980. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment under ASC Topic 980 for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the NGA and NGPA, Panhandle does not currently apply ASC Topic 980 in its GAAP-basis consolidated financial statements, primarily due to the level of discounting from tariff rates and its inability to recover specific costs. Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2021 2020 2019 Accounts receivable $ (3,356) $ 1,163 $ (473) Accounts receivable from related companies 38 (290) (69) Inventories (19) (271) (19) Other current assets (216) 172 117 Other non-current assets, net 1 (7) (102) Accounts payable 3,834 (1,327) 146 Accounts payable to related companies (34) 367 (32) Accrued and other current liabilities 238 163 (44) Other non-current liabilities 117 8 (133) Derivative assets and liabilities, net (88) 69 218 Net change in operating assets and liabilities, net of effects of acquisitions $ 515 $ 47 $ (391) Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2021 2020 2019 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 464 $ 604 $ 1,334 Units issued in connection with the Enable Acquisition (1) 3,509 — — Lease assets obtained in exchange for new lease liabilities 18 42 68 Acquisition of interest in unconsolidated affiliate 49 — — SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 2,188 $ 2,092 $ 1,932 Cash paid for income taxes (net of refunds) 41 (64) 31 (1) See Note 3 for additional information. Accounts Receivable Our operations deal with a variety of counterparties across the energy sector. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for credit losses on trade receivables based on the expected ultimate recovery of these receivables and consider many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Changes in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due. Inventories Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method. Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2021 and 2020, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $121 million and $311 million, respectively. The fuel inventory balance is not materially different than its replacement cost at the respective dates. For the years ended December 31, 2021, 2020 and 2019, the Partnership’s consolidated statements of operations and comprehensive income did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the years ended December 31, 2021 and 2019, Sunoco LP’s cost of sales included favorable inventory adjustments of $190 million and $79 million, respectively, and for the year ended December 31, 2020, Sunoco LP’s cost of sales included a write-down of fuel inventory of $82 million. The Partnership’s inventories consisted of the following: December 31, 2021 2020 Natural gas, NGLs and refined products $ 1,259 $ 1,013 Crude oil 328 287 Spare parts and other 427 439 Total inventories $ 2,014 $ 1,739 We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations. Other Current Assets Other current assets consisted of the following: December 31, 2021 2020 Deposits paid to vendors $ 215 $ 75 Prepaid expenses and other 222 138 Total other current assets $ 437 $ 213 Property, Plant and Equipment Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC-mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment is retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2021, USAC recognized a $5 million fixed asset impairment related to its compression equipment as a result of its evaluation of the future deployment of idle fleet. In 2020, the Partnership recognized a $58 million fixed asset impairment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. USAC recorded an $8 million impairment of compression equipment as a result of its evaluations of the future deployment of its idle fleet. In 2019, USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets. Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds. Components and useful lives of property, plant and equipment were as follows: December 31, 2021 2020 Land and improvements $ 1,369 $ 1,233 Buildings and improvements (1 to 45 years) 4,598 4,236 Pipelines and equipment (5 to 83 years) 77,112 69,120 Product storage and related facilities (2 to 83 years) 7,410 6,393 Right of way (20 to 83 years) 5,021 5,099 Other (1 to 48 years) 2,816 2,263 Construction work-in-process 5,665 5,771 103,991 94,115 Less – Accumulated depreciation and depletion (22,384) (19,008) Property, plant and equipment, net $ 81,607 $ 75,107 We recognized the following amounts for the periods presented: Years Ended December 31, 2021 2020 2019 Depreciation, depletion and amortization expense $ 3,465 $ 3,275 $ 2,839 Capitalized interest 135 189 166 Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. During the year ended December 31, 2020, the Partnership recorded an impairment of its investment in White Cliffs of $129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition in December 2019. Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2021 2020 Crude pipeline linefill and tank bottoms $ 498 $ 517 Regulatory assets 42 41 Pension assets 140 103 Deferred charges 177 188 Restricted funds 164 179 Other 624 629 Total other non-current assets, net $ 1,645 $ 1,657 Restricted funds include an immaterial amount of restricted cash primarily held in our wholly-owned captive insurance companies. Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: December 31, 2021 December 31, 2020 Gross Carrying Accumulated Gross Carrying Accumulated Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 7,982 $ (2,464) $ 7,513 $ (2,117) Patents (10 years) 48 (44) 48 (40) Trade names (20 years) 66 (38) 66 (35) Other (5 to 20 years) 19 (20) 19 (15) Total amortizable intangible assets 8,115 (2,566) 7,646 (2,207) Non-amortizable intangible assets: Trademarks 295 — 295 — Other 12 — 12 — Total non-amortizable intangible assets 307 — 307 — Total intangible assets $ 8,422 $ (2,566) $ 7,953 $ (2,207) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2021 2020 2019 Reported in depreciation, depletion and amortization expense $ 352 $ 403 $ 308 Estimated aggregate amortization of intangible assets for the next five years is as follows: Years Ending December 31: 2022 $ 379 2023 362 2024 348 2025 335 2026 331 We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test was performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Intrastate Interstate Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total Balance, December 31, 2019 $ 10 $ 226 $ 483 $ 693 $ 1,397 $ 1,555 $ 619 $ 184 $ 5,167 Acquired — — — — — 9 — — 9 Impaired (10) (226) (483) — (1,279) — (619) (198) (2,815) Other — — — — (66) — — 96 30 Balance, December 31, 2020 — — — 693 52 1,564 — 82 2,391 Acquired — — — — 138 4 — — 142 Balance, December 31, 2021 $ — $ — $ — $ 693 $ 190 $ 1,568 $ — $ 82 $ 2,533 As of December 31, 2021, the all other segment includes $72 million of goodwill allocated to a reporting unit that had a negative carrying value. During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. The Partnership performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized goodwill impairments of $483 million related to our Ark-La-Tex and South Texas operations within the midstream segment, $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations. During the third quarter of 2020, the Partnership performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $1.28 billion related to our crude operations, $132 million related to our Energy Transfer Canada operations within the all other segment and $43 million related to our interstate operations primarily due to decreases in projected future cash flow as a result of the overall market demand decline. During the fourth quarter of 2020, the Partnership performed annual impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $10 million related to our intrastate operations, $11 million related to our PEI operations and $15 million related to our Natural Resources operations within the all other segment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. No other impairments of the Partnership’s goodwill were identified. Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the fourth quarter of 2019, $265 million of goodwill was recorded in conjunction with the acquisition of SemGroup. During the fourth quarter of 2021, $138 million of goodwill was recorded in conjunction with the acquisition of Enable. In addition, Sunoco LP recorded $4 million of goodwill in conjunction with its acquisition of eight refined product terminals. During the third quarter of 2019, the Partnership recognized a goodwill impairment of $12 million related to the Southwest Gas operations within the interstate segment primarily due to decreases in projected future revenues and cash flows. During the fourth quarter of 2019, the Partnership recognized a goodwill impairment of $9 million related to our North Central operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows. The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. The fair value estimates used in the long-lived asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy. Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an ARO in the periods in which management can reasonably estimate the settlement dates. As of December 31, 2021 and 2020, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $369 million and $280 million, respectively. For the years ended December 31, 2021, 2020 and 2019 aggregate accretion expense related to AROs was $12 million, $16 million and $5 million, respectively. Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2021 and 2020, in most cases because the settlement dates were indeterminable. Although a number of onshore assets in our systems are subject to agreements or regulations that give rise to an ARO upon discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Our subsidiaries also have legal obligations for several other assets at previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, our subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks. Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely. As of December 31, 2021 and 2020, other non-current assets on the Partnership’s consolidated balance sheets included $39 million and $34 million, respectively, of funds that were legally restricted for the purpose of settling AROs. Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: December 31, 2021 2020 Interest payable $ 561 $ 600 Customer advances and deposits 188 161 Accrued capital expenditures 461 604 Accrued wages and benefits 297 109 Taxes payable other than income taxes 384 446 Exchanges payable 155 127 Deferred revenue 158 112 Other 867 616 Total accrued and other current liabilities $ 3,071 $ 2,775 Customer advances and deposits are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may be required when customers exceed their credit limits or do not qualify for open credit. Redeemable Noncontrolling Interests Our redeemable noncontrolling interests relate to certain preferred unitholders of one of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in one of our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 7 for further information. Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued. Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2021, no transfers were made between any levels within the fair value hierarchy. The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2021 and 2020 based on inputs used to derive their fair values: Fair Value Total Fair Value Measurements at December 31, 2021 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 7 $ 7 $ — Swing Swaps IFERC 38 38 — Fixed Swaps/Futures 26 26 — Forward Physical Contracts 7 — 7 Power: Forwards 17 — 17 Futures 6 6 — NGLs – Forwards/Swaps 152 152 — Refined Products – Futures 3 3 — Crude – Forwards/Swaps 16 16 — Total commodity derivatives 272 248 24 Other non-current assets 39 26 13 Total assets $ 311 $ 274 $ 37 Liabilities: Interest rate derivatives $ (387) $ — $ (387) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (10) (10) — Swing Swaps IFERC (6) (6) — Fixed Swaps/Futures (9) (9) — Forward Physical Contracts (6) — (6) Power: Forwards (15) — (15) Futures (4) (4) — NGLs – Forwards/Swaps (140) (140) — Refined Products – Futures (18) (18) — Crude – Forwards/Swaps (3) (3) — Total commodity derivatives (211) (190) (21) Total liabilities $ (598) $ (190) $ (408) Fair Value Total Fair Value Measurements at December 31, 2020 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 12 $ 12 $ — Swing Swaps IFERC 1 — 1 Fixed Swaps/Futures 13 13 — Forward Physical Contracts 5 — 5 Power: Power – Forwards 4 — 4 Futures 2 2 — Options – Calls 1 1 — NGLs – Forwards/Swaps 127 127 — Refined Products – Futures 3 3 — Total commodity derivatives 168 158 10 Other non-current assets 34 22 12 Total assets $ 202 $ 180 $ 22 Liabilities: Interest rate derivatives $ (448) $ — $ (448) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (11) (11) — Swing Swaps IFERC (3) — (3) Fixed Swaps/Futures (13) (13) — Forward Physical Contracts (1) — (1) Power: Futures (3) (3) — NGLs – Forwards/Swaps (227) (227) — Refined Products – Futures (11) (11) — Total commodity derivatives (269) (265) (4) Total liabilities $ (717) $ (265) $ (452) Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2021 was $54.97 billion and $49.70 billion, respectively. As of December 31, 2020, the aggregate fair value and carrying amount of our debt obligations was $56.21 billion and $51.44 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. Contributions in Aid of Construction Costs On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received. Shipping and Handling Costs Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses. Costs and Expenses Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of app |
Acquisitions and Related Transa
Acquisitions and Related Transactions | 12 Months Ended |
Dec. 31, 2021 | |
Acquisitions and Dispositions [Abstract] | |
Acquisitions and Related Transactions | ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS : Enable Acquisition On December 2, 2021, the Partnership completed the previously announced merger with Enable (the “Enable Acquisition”). Under the terms of the merger agreement, Enable’s common unitholders received 0.8595 of an Energy Transfer common unit in exchange for each Enable common unit. In addition, each outstanding Enable Series A preferred unit was exchanged for 0.0265 of an Energy Transfer Series G Preferred Unit. A total of 384,780 Series G Preferred Units were issued in connection with the Enable Acquisition. The total fair value of Energy Transfer common units and Series G Preferred Units issued was approximately $3.5 billion at the closing date. Energy Transfer also made a $10 million cash payment for Enable’s general partner and assumed $3.18 billion aggregate principal amount of Enable senior notes. In addition, Enable’s $800 million term loan and $35 million revolving credit facility were repaid and terminated in December 2021, immediately subsequent to the close of the Enable Acquisition. The Enable Acquisition was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions. Acquired assets were valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods. The purchase price allocation below is preliminary, as management is currently evaluating certain assumptions and may adjust the allocation in the subsequent period. The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed: At December 2, 2021 Total current assets $ 593 Property, plant and equipment, net 7,076 Investments in unconsolidated affiliates 40 Other non-current assets 39 Intangible assets, net 440 Goodwill 138 Total assets 8,326 Total current liabilities 488 Long-term debt, less current maturities (1) 4,267 Other non-current liabilities 18 Total liabilities 4,773 Noncontrolling interests 34 Total consideration 3,519 Cash received 61 Total consideration $ 3,458 (1) Long-term debt at December 2, 2021 includes Enable senior notes with an aggregate principal amount of $3.18 billion in senior notes and a fair value of $3.43 billion. It also includes $800 million outstanding on the Enable 2019 Term Loan Agreement and $35 million outstanding on the Enable Five-Year Revolving Credit Facility, both of which were repaid and terminated in December 2021, immediately subsequent to the close of the Enable Acquisition. SemGroup Acquisition and Energy Transfer Contribution of SemGroup Assets to ETO On December 5, 2019, Energy Transfer completed the acquisition of SemGroup pursuant to the terms of the Agreement and Plan of Merger, dated as of September 15, 2019 (the “SemGroup Merger Agreement”). Under the terms of the SemGroup Merger Agreement, a wholly owned subsidiary of Energy Transfer merged with and into SemGroup (the “SemGroup Transaction”), with SemGroup surviving the merger. At the effective time of the SemGroup Transaction on December 5, 2019, each share of class A common stock, par value $0.01 per share, of SemGroup issued and outstanding immediately prior to the effective time was converted into the right to receive (i) $6.80 in cash, without interest, and (ii) 0.7275 Energy Transfer Common Units representing limited partner interests in Energy Transfer. Each share of Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share, of SemGroup that was issued and outstanding as of immediately prior to the effective time was redeemed by SemGroup for cash at a price per share equal to 101% of the liquidation preference. During the first and second quarters of 2020, Energy Transfer contributed former SemGroup assets to ETO through sale and contribution transactions. The following table represents the fair value, as of December 5, 2019, of the SemGroup assets and liabilities transferred from Energy Transfer to ETO: At December 5, 2019 Total current assets $ 794 Property, plant and equipment 3,891 Other non-current assets 617 Goodwill 295 Intangible assets 460 Total assets $ 6,057 Total current liabilities $ 629 Long-term debt, less current maturities (1) 2,576 Other non-current liabilities 197 Energy Transfer Canada Preferred shares 241 Total liabilities 3,643 Noncontrolling interest 822 Partners’ capital 1,592 Total liabilities and partners’ capital $ 6,057 (1) Long-term debt at December 5, 2019 includes SemGroup senior notes with an aggregate principal amount of $1.375 billion and SemGroup subsidiary debt of $593 million, all of which was redeemed in December 2019, subsequent to the close of the SemGroup Transaction. During 2020, the Partnership has recorded impairments on certain of the contributed SemGroup assets. Those impairments include a $244 million impairment of goodwill and a $129 million impairment of other non-current assets. |
Advances to and Investments in
Advances to and Investments in Unconsolidated Affiliates | 12 Months Ended |
Dec. 31, 2021 | |
Investment In Affiliates [Abstract] | |
Investments In Affiliates | INVESTMENTS IN UNCONSOLIDATED AFFILIATES : Citrus CrossCountry Energy, LLC, a wholly-owned subsidiary of Energy Transfer, owns a 50% interest in Citrus. Citrus owns 100% of FGT, an approximately 5,362-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment. FEP Energy Transfer has a 50% interest in FEP which owns the Fayetteville Express Pipeline, an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline in Panola County, Mississippi. Energy Transfer’s investment in FEP is reflected in the interstate transportation and storage segment. MEP Energy Transfer owns a 50% interest in MEP, which owns the Midcontinent Express Pipeline, an approximately 500-miles natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Energy Transfer’s investment in MEP is reflected in the interstate transportation and storage segment. White Cliffs We own a 51% interest in White Cliffs, which was acquired by Energy Transfer in the SemGroup acquisition. White Cliffs consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline. These pipelines transport crude and NGLs from Platteville, Colorado to Cushing, Oklahoma. The Partnership recorded an impairment of its investment in White Cliffs of $129 million during the year ended December 31, 2020 due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition and related purchase price allocation in December 2019. The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2021 and 2020 were as follows: December 31, 2021 2020 Citrus $ 1,792 $ 1,867 FEP — 4 MEP 378 406 White Cliffs 245 274 Other 532 509 Total $ 2,947 $ 3,060 The following table presents equity in earnings (losses) of unconsolidated affiliates: Years Ended December 31, 2021 2020 2019 Citrus $ 157 $ 162 $ 148 FEP (1) — (139) 59 MEP (17) (6) 15 White Cliffs — 20 4 Other 106 82 76 Total equity in earnings of unconsolidated affiliates $ 246 $ 119 $ 302 (1) For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million. Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP, and White Cliffs (on a 100% basis) for all periods presented: December 31, 2021 2020 Current assets $ 242 $ 227 Property, plant and equipment, net 7,239 7,339 Other assets 77 58 Total assets $ 7,558 $ 7,624 Current liabilities $ 500 $ 600 Non-current liabilities 3,602 3,298 Equity 3,456 3,726 Total liabilities and equity $ 7,558 $ 7,624 Years Ended December 31, 2021 2020 2019 Revenue $ 1,003 $ 1,243 $ 1,192 Operating income 459 6 683 Net income (loss) 282 (199) 443 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements. |
Net Income Per Limited Partner
Net Income Per Limited Partner Unit | 12 Months Ended |
Dec. 31, 2021 | |
Earnings Per Share [Abstract] | |
Net Income Per Limited Partner Unit | NET INCOME PER LIMITED PARTNER UNIT : Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from Energy Transfer’s limited partner unit ownership in Sunoco LP that would have resulted assuming the incremental units related to Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method. A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows: Years Ended December 31, 2021 2020 2019 Net income $ 6,687 $ 140 $ 4,825 Less: Net income attributable to redeemable noncontrolling interests 50 49 51 Less: Net income attributable to noncontrolling interests 1,167 739 1,256 Net income (loss), net of noncontrolling interests 5,470 (648) 3,518 Less: General Partner’s interest in income (loss) 6 (1) 4 Less: Preferred Unitholders’ interest in income 285 — — Income (loss) available to Limited Partners $ 5,179 $ (647) $ 3,514 Basic Income (Loss) per Limited Partner Unit: Weighted average limited partner units 2,734.4 2,695.6 2,628.0 Basic income (loss) per Limited Partner unit $ 1.89 $ (0.24) $ 1.34 Diluted Income (Loss) per Limited Partner Unit: Income (loss) available to Limited Partners $ 5,179 $ (647) $ 3,514 Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units (2) — (1) Diluted income (loss) available to Limited Partners $ 5,177 $ (647) $ 3,513 Weighted average limited partner units 2,734.4 2,695.6 2,628.0 Dilutive effect of unvested unit awards 5.1 — 9.6 Weighted average limited partner units, assuming dilutive effect of unvested unit awards 2,739.5 2,695.6 2,637.6 Diluted income (loss) per Limited Partner unit $ 1.89 $ (0.24) $ 1.33 |
Debt Obligations
Debt Obligations | 12 Months Ended |
Dec. 31, 2021 | |
Debt Obligations [Abstract] | |
Debt Disclosure [Text Block] | DEBT OBLIGATIONS: In connection with the Rollup Mergers on April 1, 2021, as discussed in Note 1, Energy Transfer entered into various supplemental indentures and assumed all the obligations of ETO under the respective indentures and credit agreements. In connection with the Enable Acquisition on December 2, 2021, as discussed in Note 3, Energy Transfer repaid $800 million outstanding on the Enable 2019 Term Loan Agreement and $35 million outstanding on the Enable Five-Year Revolving Credit Facility, and both facilities were terminated. In addition, the Partnership assumed $3.18 billion aggregate principal amount of Enable senior notes. Our debt obligations consist of the following: December 31, 2021 2020 Energy Transfer Indebtedness 4.40% Senior Notes due April 1, 2021 (1) $ — $ 600 4.65% Senior Notes due June 1, 2021 (1) — 800 5.20% Senior Notes due February 1, 2022 (1) — 1,000 4.65% Senior Notes due February 15, 2022 (2) 300 300 5.875% Senior Notes due March 1, 2022 (1) — 900 5.00% Senior Notes due October 1, 2022 (2) 700 700 3.45% Senior Notes due January 15, 2023 350 350 3.60% Senior Notes due February 1, 2023 800 800 4.25% Senior Notes due March 15, 2023 5 5 4.25% Senior Notes due March 15, 2023 995 995 4.20% Senior Notes due September 15, 2023 500 500 4.50% Senior Notes due November 1, 2023 600 600 5.875% Senior Notes due January 15, 2024 23 23 5.875% Senior Notes due January 15, 2024 1,127 1,127 4.90% Senior Notes due February 1, 2024 350 350 7.60% Senior Notes due February 1, 2024 277 277 4.25% Senior Notes due April 1, 2024 500 500 4.50% Senior Notes due April 15, 2024 750 750 3.90% Senior Notes due May 15, 2024 (3) 600 — 9.00% Debentures due November 1, 2024 65 65 4.05% Senior Notes due March 15, 2025 1,000 1,000 2.90% Senior Notes due May 15, 2025 1,000 1,000 5.95% Senior Notes due December 1, 2025 400 400 4.75% Senior Notes due January 15, 2026 1,000 1,000 3.90% Senior Notes due July 15, 2026 550 550 4.40% Senior Notes due March 15, 2027 (3) 700 — 4.20% Senior Notes due April 15, 2027 600 600 5.50% Senior Notes due June 1, 2027 44 44 5.50% Senior Notes due June 1, 2027 956 956 4.00% Senior Notes due October 1, 2027 750 750 4.95% Senior Notes due May 15, 2028 (3) 800 — 4.95% Senior Notes due June 15, 2028 1,000 1,000 5.25% Senior Notes due April 15, 2029 1,500 1,500 4.15% Senior Notes due September 15, 2029 (3) 547 — 8.25% Senior Notes due November 15, 2029 267 267 3.75% Senior Note due May 15, 2030 1,500 1,500 4.90% Senior Notes due March 15, 2035 500 500 6.625% Senior Notes due October 15, 2036 400 400 5.80% Senior Notes due June 15, 2038 500 500 7.50% Senior Notes due July 1, 2038 550 550 6.85% Senior Notes due February 15, 2040 250 250 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.30% Senior Notes due April 1, 2044 700 700 5.00% Senior Notes due May 15, 2044 (3) 531 — 5.15% Senior Notes due March 15, 2045 1,000 1,000 5.35% Senior Notes due May 15, 2045 800 800 6.125% Senior Notes due December 15, 2045 1,000 1,000 5.30% Senior Notes due April 15, 2047 900 900 5.40% Senior Notes due October 1, 2047 1,500 1,500 6.00% Senior Notes due June 15, 2048 1,000 1,000 6.25% Senior Notes due April 15, 2049 1,750 1,750 5.00% Senior Notes due May 15, 2050 2,000 2,000 Floating Rate Junior Subordinated Notes due November 1, 2066 546 546 Term Loan — 2,000 Five-Year Credit Facility 2,937 3,103 Unamortized premiums, discounts and fair value adjustments, net 233 (17) Deferred debt issuance costs (186) (215) 40,717 42,726 Subsidiary Indebtedness Transwestern Debt 5.89% Senior Notes due May 24, 2022 (2) 150 150 5.66% Senior Notes due December 9, 2024 175 175 6.16% Senior Notes due May 24, 2037 75 75 400 400 Panhandle Debt 7.60% Senior Notes due February 1, 2024 82 82 7.00% Senior Notes due July 15, 2029 66 66 8.25% Senior Notes due November 15, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 8 10 243 245 Bakken Project Debt 3.625% Senior Notes due April 1, 2022 650 650 3.90% Senior Notes due April 1, 2024 1,000 1,000 4.625% Senior Notes due April 1, 2029 850 850 Unamortized premiums, discounts and fair value adjustments, net (2) (3) Deferred debt issuance costs (9) (13) 2,489 2,484 Sunoco LP Debt 4.875% Senior Notes Due January 15, 2023 — 436 5.50% Senior Notes Due February 15, 2026 — 800 6.00% Senior Notes Due April 15, 2027 600 600 5.875% Senior Notes Due March 15, 2028 400 400 4.50% Senior Notes due May 15, 2029 800 800 4.50% Senior Notes due April 30, 2030 800 — Sunoco LP $1.50 billion Revolving Credit Facility due July 2023 581 — Lease-related obligations 100 103 Deferred debt issuance costs (26) (27) 3,255 3,112 USAC Debt 6.875% Senior Notes due April 1, 2026 725 725 6.875% Senior Notes due September 1, 2027 750 750 USAC $1.60 billion Revolving Credit Facility due December 2026 516 474 Deferred debt issuance costs (18) (22) 1,973 1,927 HFOTCO Debt HFOTCO Tax Exempt Notes due 2050 225 225 Unamortized premiums, discounts and fair value adjustments, net (1) (2) 224 223 Energy Transfer Canada Debt Energy Transfer Canada Revolving Credit Facility 7 57 Energy Transfer Canada Term Loan A 249 261 Energy Transfer Canada KAPS Facility 142 — 398 318 Other 3 3 Total debt 49,702 51,438 Less: Current maturities of long-term debt 680 21 Long-term debt, less current maturities $ 49,022 $ 51,417 (1) These notes were redeemed in 2021. (2) As of December 31, 2021, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The $300 million principal amount of 4.65% Senior Notes were redeemed in February 2022 using proceeds from Energy Transfer’s Five-Year Credit Facility. (3) These notes were assumed by Energy Transfer in connection with the Enable Acquisition. The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $1 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: 2022 $ 1,827 2023 3,859 2024 8,250 2025 2,407 2026 2,799 Thereafter 30,561 Total $ 49,703 Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap. Notes and Debentures Senior Notes As discussed in Note 1, beginning on April 1, 2021 as a result of the Rollup Mergers, Energy Transfer assumed the obligations of the ETO senior notes. The ETO senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETO senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETO senior notes. The balance is payable upon maturity. Interest on the ETO senior notes is paid semi-annually. The Energy Transfer Senior Notes are the Partnership’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. Energy Transfer’s obligations under the Energy Transfer Senior Notes previously were secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the Energy Transfer Term Loan Facility, by a lien on substantially all of Energy Transfer’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. Subsequent to the termination of the Revolver Credit Agreement and the Energy Transfer Term Loan Facility, the collateral securing the Energy Transfer Senior Notes was released. The Energy Transfer Senior Notes are not guaranteed by any of its subsidiaries. The covenants related to the Energy Transfer Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Partnership’s assets. Transwestern Senior Notes The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually. Sunoco LP Senior Notes On October 20, 2021, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.50% senior notes due 2030 (the “2030 Notes”). Sunoco LP used the proceeds from the private offering to fund a tender offer and repurchase all of its senior notes due 2026. On November 9, 2020, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.50% senior notes due 2029. Sunoco LP used the proceeds to fund the tender offer on its 4.875% $1 billion senior notes due 2023. Approximately 56% of the 2023 senior notes were tendered. On January 15, 2021, Sunoco LP repurchased the remaining outstanding portion of its 2023 senior notes. Term Loans, Credit Facilities and Commercial Paper Term Loan As a result of the Rollup Mergers, on April 1, 2021, Energy Transfer assumed all of ETO’s obligations in respect of its term loan credit agreement, and the facility was subsequently repaid and terminated. Five-Year Credit Facility As a result of the Rollup Mergers, on April 1, 2021, Energy Transfer assumed all of ETO’s obligations in respect of its revolving credit facility (the “Five-Year Credit Facility”). The Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2024. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions. As of December 31, 2021, the Five-Year Credit Facility had $2.94 billion of outstanding borrowings, of which $1.19 billion consisted of commercial paper. The amount available for future borrowings was $2.03 billion, after accounting for outstanding letters of credit in the amount of $33 million. The weighted average interest rate on the total amount outstanding as of December 31, 2021 was 1.13%. 364-Day Facility As a result of the Rollup Mergers, on April 1, 2021, Energy Transfer assumed all of ETO’s obligations in respect of its 364-day revolving credit facility, and the facility was subsequently terminated. Sunoco LP Credit Facility Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”). As of December 31, 2021, the Sunoco LP Credit Facility had $581 million outstanding borrowings and $6 million in standby letters of credit and matures in July 2023. The amount available for future borrowings was $913 million at December 31, 2021. The weighted average interest rate on the total amount outstanding as of December 31, 2021 was 2.10%. USAC Credit Facility USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”), which, as amended in December 2021, matures on December 8, 2026, except that if any portion of USAC’s senior notes due 2026 are outstanding on December 31, 2025, the USAC Credit Facility will mature on December 31, 2025. The USAC Credit Facility also permits up to $200 million of future increases in borrowing capacity. As of December 31, 2021, USAC had $516 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2021, USAC had $1.1 billion of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $262 million. The weighted average interest rate on the total amount outstanding as of December 31, 2021 was 2.68%. Energy Transfer Canada Credit Facilities Energy Transfer Canada is party to a credit agreement providing for a C$350 million (US$276 million at the December 31, 2021 exchange rate) senior secured term loan facility (the “Energy Transfer Canada Term Loan A”), a C$525 million (US$414 million at the December 31, 2021 exchange rate) senior secured revolving credit facility (the “Energy Transfer Canada Revolving Credit Facility”), and a C$300 million (US$237 million at the December 31, 2021 exchange rate) senior secured construction loan facility (the “Energy Transfer Canada KAPS Facility”). The Energy Transfer Canada Term Loan A and the Energy Transfer Canada Revolving Credit Facility mature on February 25, 2024. The Energy Transfer Canada KAPS Facility matures on June 13, 2024. Energy Transfer Canada may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$197 million at the December 31, 2021 exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders. As of December 31, 2021 , the Energy Transfer Canada Term Loan A and the Energy Transfer Canada Revolving Credit Facility had outstanding borrowings of C$315 million and C$9 million, respectively (US$249 million and US$7 million, respectively, at the December 31, 2021 exchange rate). As of December 31, 2021 , the KAPS Facility had outstanding borrowings of C$179 million (US$142 million at the December 31, 2021 exchange rate). Covenants Related to Our Credit Agreements The agreements relating to the Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions. The Five-Year Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things: • incur indebtedness; • grant liens; • enter into mergers; • dispose of assets; • make certain investments; • make Distributions (as defined in the Five-Year Credit Facility) during certain Defaults (as defined in the Five-Year Credit Facility) and during any Event of Default (as defined in the Five-Year Credit Facility); • engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries; • engage in transactions with affiliates; and • enter into restrictive agreements. The applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the Five-Year Credit Facility ranges from 0.125% to 0.300%. The Five-Year Credit Facility contains various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The Five-Year Credit Facility also limits us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreement, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 3.07 to 1 at December 31, 2021, as calculated in accordance with the credit agreement. Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders. Covenants Related to Transwestern The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio. Covenants Related to Panhandle Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Panhandle’s restrictive covenants include restrictions on liens securing debt and guarantees and restrictions on mergers and on the sales of assets. A breach of any of these covenants could result in acceleration of Panhandle’s debt. Covenants Related to Sunoco LP The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in certain specified acquisitions of not less than $50 million (as permitted under Sunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility also requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the Sunoco LP’s Credit Facility agreement) of not less than 2.25 to 1. Covenants Related to USAC The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things: • grant liens; • make certain loans or investments; • incur additional indebtedness or guarantee other indebtedness; • enter into transactions with affiliates; • merge or consolidate; • sell our assets; and • make certain acquisitions. The credit facility is also subject to the following financial covenants, including covenants requiring USAC to maintain: • a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter, with EBITDA and interest expense annualized for the fiscal quarter most recently ended; • a ratio of total secured indebtedness to EBITDA not greater than 3.0 to 1.0 or less than 0.0 to 1.0, determined as of the last day of each fiscal quarter, with EBITDA annualized for the fiscal quarter most recently ended; and • a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter with EBITDA annualized for the fiscal quarter most recently ended, (i) 5.75 to 1 through the second fiscal quarter of 2022, (ii) 5.5 to 1 from the third quarter of 2022 through the third quarter of 2023, and (iii) 5.25 to 1 thereafter. In addition, USAC may increase the applicable ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum ratio exceed 5.5 to 1.0 for any fiscal quarter as a result of such increase. Covenants Related to the HFOTCO Tax Exempt Notes The indentures covering HFOTCO’s tax exempt notes due 2050 (“IKE Bonds”) include customary representations and warranties and affirmative and negative covenants. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the bondholders, taking actions to remove the trustee, making certain amendments to the bond documents, and taking actions or omitting to take actions that adversely impact the tax exempt status of the IKE Bonds. Compliance with our Covenants Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions. We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2021. |
Redeemable Noncontrolling Inter
Redeemable Noncontrolling Interest | 12 Months Ended |
Dec. 31, 2021 | |
Preferred Units, Preferred Partners' Capital Account [Abstract] | |
Redeemable Noncontrolling Interest [Text Block] | REDEEMABLE NONCONTROLLING INTERESTS: Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of December 31, 2021 included a balance of $477 million related to the USAC Preferred Units described below and a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. In addition, redeemable noncontrolling interests includes a balance of $291 million of Energy Transfer Canada preferred shares. USAC Series A Preferred Units As of December 31, 2021, USAC had 500,000 preferred units issued and outstanding. The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units are convertible into USAC common units at the election of the holders. To the extent the holders of the USAC Preferred Units have not elected to convert their preferred units by the fifth anniversary of the issue date, USAC will have the option to redeem all or any portion of the USAC Preferred Units for cash. In addition, beginning April 2028, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and the Partnership may elect to pay up to 50% of such redemption amount in USAC common units. Energy Transfer Canada Redeemable Preferred Stock Energy Transfer Canada has 300,000 shares of cumulative preferred stock issued and outstanding. The preferred stock is redeemable at Energy Transfer Canada’s option subsequent to January 3, 2021 at a redemption price of C$1,100 (US$868 at the December 31, 2021 exchange rate) per share. The preferred stock is redeemable by the holder contingent upon a change of control or liquidation of Energy Transfer Canada. The preferred stock is convertible to Energy Transfer Canada common shares in the event of an initial public offering by Energy Transfer Canada. Dividends on the preferred stock are payable in-kind through the quarter ending June 30, 2021. The dividends paid-in-kind increased the liquidation preference such that as of December 31, 2021, the preferred stock was convertible into 367,521 shares. For the quarter ended December 31, 2021, Energy Transfer Canada declared cash dividends of C$8 million (US$6 million at the December 31, 2021 exchange rate) on the preferred stock that will be paid in the first quarter of 2022. |
Equity
Equity | 12 Months Ended |
Dec. 31, 2020 | |
Partners' Capital Notes [Abstract] | |
Equity | EQUITY: Limited Partner Units Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.” As of December 31, 2021, there were issued and outstanding 3.08 billion Common Units representing an aggregate 99.9% limited partner interest in the Partnership. Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures. Common Units The change in Energy Transfer Common Units during the years ended December 31, 2021, 2020 and 2019 was as follows: Years Ended December 31, 2021 2020 2019 Number of Common Units, beginning of period 2,702.4 2,689.6 2,619.4 Common Units issued in mergers and acquisitions (1) 374.6 — 57.6 Common Units repurchased (4.2) — (1.9) Issuance of Common Units (2) 9.7 12.8 14.5 Number of Common Units, end of period 3,082.5 2,702.4 2,689.6 (1) In December 2019, Energy Transfer issued 57.6 million Energy Transfer Common Units in connection with the SemGroup acquisition. In December 2021, Energy Transfer issued 374.6 million Energy Transfer Common Units in connection with the Enable Acquisition. (2) Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings. Energy Transfer Class A Units As of February 11, 2022, the Partnership had outstanding 763,021,449 Class A units (“Energy Transfer Class A Units”) representing limited partner interests in the Partnership to the General Partner. The Energy Transfer Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, Energy Transfer’s partnership agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of Energy Transfer Class A Units additional Energy Transfer Class A Units such that the holder maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance. The Energy Transfer Class A Units are not entitled to distributions and otherwise have no economic attributes. Energy Transfer Repurchase Program In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of Energy Transfer Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 4.2 million Energy Transfer Common Units under this program in 2021 and zero in 2020. As of December 31, 2021, $880 million remained available to repurchase under the current program. Energy Transfer Distribution Reinvestment Program During the year ended December 31, 2021, distributions of $33 million were reinvested under the distribution reinvestment program. As of December 31, 2021, a total of 17 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment program. Sale of Common Units by Subsidiaries Energy Transfer on a stand-alone basis (the “Parent Company”) accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented. Energy Transfer Preferred Units Conversion of ETO Preferred Units to Energy Transfer Preferred Units In connection with the Rollup Mergers on April 1, 2021, as discussed in Note 1, all of ETO’s previously outstanding preferred units were converted to Energy Transfer Preferred Units with identical distribution and redemption rights, as described under “Description of Energy Transfer Preferred Units” below. As of and prior to March 31, 2021, the Energy Transfer Preferred Units were reflected as noncontrolling interests on the Partnership’s consolidated financial statements. Beginning April 1, 2021, the Energy Transfer Preferred Units are reflected as limited partner interests in the Partnership’s consolidated financial statements. As of December 31, 2021, Energy Transfer’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units, 32,000,000 Series E Preferred Units, 500,000 Series F Preferred Units, 1,484,780 Series G Preferred Units and 900,000 Series H Preferred Units. The following table summarizes changes in the Energy Transfer Preferred Units: Preferred Unitholders Series A Series B Series C Series D Series E Series F Series G Series H Total Balance, December 31, 2020 $ — $ — $ — $ — $ — $ — $ — $ — $ — Preferred units conversion 943 547 440 434 786 504 1,114 — 4,768 Units issued for cash — — — — — — — 889 889 Distributions to partners (30) (18) (25) (25) (45) (34) (79) (24) (280) Units issued in Enable Acquisition — — — — — — 392 — 392 Other, net — — — — — — — (3) (3) Net income 45 27 25 25 45 26 61 31 285 Balance, December 31, 2021 $ 958 $ 556 $ 440 $ 434 $ 786 $ 496 $ 1,488 $ 893 $ 6,051 Energy Transfer Series A Preferred Units Distributions on the Energy Transfer Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the Energy Transfer Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The Energy Transfer Series A Preferred Units are redeemable at Energy Transfer’s option on or after February 15, 2023 at a redemption price of $1,000 per Energy Transfer Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Energy Transfer Series B Preferred Units Distributions on the Energy Transfer Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Energy Transfer Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The Energy Transfer Series B Preferred Units are redeemable at Energy Transfer’s option on or after February 15, 2028 at a redemption price of $1,000 per Energy Transfer Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Energy Transfer Series C Preferred Units Distributions on the Energy Transfer Series C Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Energy Transfer Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. The Energy Transfer Series C Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2023 at a redemption price of $25 per Energy Transfer Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Energy Transfer Series D Preferred Units Distributions on the Energy Transfer Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Energy Transfer Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.738% per annum. The Energy Transfer Series D Preferred Units are redeemable at Energy Transfer’s option on or after August 15, 2023 at a redemption price of $25 per Energy Transfer Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Energy Transfer Series E Preferred Units Distributions on the Energy Transfer Series E Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2024, at a rate of 7.600% per annum of the stated liquidation preference of $25. On and after May 15, 2024, distributions on the Energy Transfer Series E Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 5.161% per annum. The Energy Transfer Series E Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2024 at a redemption price of $25 per Energy Transfer Series E Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Energy Transfer Series F Preferred Units Distributions on the Series F Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2025, at a rate equal to 6.750% per annum of the $1,000 liquidation preference. On and after May 15, 2025, the distribution rate on the Energy Transfer Series F Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.134% per annum. The Energy Transfer Series F Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2025 at a redemption price of $1,000 per Energy Transfer Series F Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Energy Transfer Series G Preferred Units Distributions on the Energy Transfer Series G Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a rate equal to 7.125% per annum of the $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the Energy Transfer Series G Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.306% per annum. The Energy Transfer Series G Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2030 at a redemption price of $1,000 per Energy Transfer Series G Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. On December 2, 2021, Energy Transfer issued 384,780 Energy Transfer Series G Preferred Units in connection with the Enable Acquisition, as discussed in Note 3. Energy Transfer Series H Preferred Units On June 15, 2021, Energy Transfer issued 900,000 of its 6.500% Series H Preferred Units at a price to the public of $1,000 per unit. Distributions on the Series H Preferred Units will accrue and be cumulative to, but excluding, November 15, 2026, at a rate equal to 6.500% per annum of the $1,000 liquidation preference. On and after November 15, 2026 and each fifth anniversary thereafter, the distribution rate on the Series H Preferred Units will reset to be a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.694% per annum. Distributions on the Series H Preferred Units will be payable semi-annually in arrears on the 15th day of May and November of each year. The Series H Preferred Units are redeemable at Energy Transfer’s option during the three-month period prior to, and including, each distribution reset date at a redemption price of $1,000 per Series H Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Subsidiary Equity Transactions Sunoco LP’s Equity Distribution Program Sunoco LP is party to an equity distribution agreement for an at-the-market (“ATM”) offering pursuant to which Sunoco LP may sell its common units from time to time. For the years ended December 31, 2021, 2020 and 2019, Sunoco LP issued no units under its ATM program. As of December 31, 2021, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement. USAC’s Distribution Reinvestment Program During the year ended December 31, 2021 and 2020, distributions of $1.8 million and $1.9 million, respectively, were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 118,399 and 188,695 USAC common units, respectively. USAC’s Warrant Private Placement On April 2, 2018, USAC issued two tranches of warrants to purchase USAC common units (the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The USAC Warrants may be exercised by the holders thereof at any time beginning on the one year anniversary of the closing date and before the tenth anniversary of the closing date. Upon exercise of the USAC Warrants, USAC may, at its option, elect to settle the USAC Warrants in common units on a net basis. USAC’s Class B Units The USAC Class B Units, all of which were previously owned by ETO, were a new class of partnership interests of USAC that had substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units did not participate in distributions for the first four quarters following the closing date of the USAC Transaction on April 2, 2018. Each USAC Class B Unit automatically was converted into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019. On July 30, 2019, the 6,397,965 USAC Class B units held by the Partnership converted into 6,397,965 common units representing limited partner interests in USAC. These common units participate in distributions declared by USAC. Quarterly Distributions of Available Cash Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. Our distributions declared and paid with respect to our common units were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2018 February 8, 2019 February 19, 2019 $ 0.3050 March 31, 2019 May 7, 2019 May 20, 2019 0.3050 June 30, 2019 August 6, 2019 August 19, 2019 0.3050 September 30, 2019 November 5, 2019 November 19, 2019 0.3050 December 31, 2019 February 7, 2020 February 19, 2020 0.3050 March 31, 2020 May 7, 2020 May 19, 2020 0.3050 June 30, 2020 August 7, 2020 August 19, 2020 0.3050 September 30, 2020 November 6, 2020 November 19, 2020 0.1525 December 31, 2020 February 8, 2021 February 19, 2021 0.1525 March 31, 2021 May 11, 2021 May 19, 2021 0.1525 June 30, 2021 August 6, 2021 August 19, 2021 0.1525 September 30, 2021 November 5, 2021 November 19, 2021 0.1525 December 31, 2021 February 8, 2022 February 18, 2022 0.1750 Energy Transfer Preferred Unit Distributions Distributions on Energy Transfer’s Series A, Series B, Series C, Series D, Series E, Series F, Series G and Series H preferred units declared and/or paid by Energy Transfer were as follows: Period Ended Record Date Payment Date Series A (1) Series B (1) Series C Series D Series E Series F (1) Series G (1) Series H (1) March 31, 2021 May 3, 2021 May 17, 2021 $— $— $0.4609 $0.4766 $0.4750 $33.7500 $35.63 $— June 30, 2021 August 2, 2021 August 16, 2021 31.25 33.13 0.4609 0.4766 0.4750 — — — September 30, 2021 November 1, 2021 November 15, 2021 — — 0.4609 0.4766 0.4750 33.7500 35.63 27.08 * December 31, 2021 February 1, 2022 February 15, 2022 31.25 33.13 0.4609 0.4766 0.4750 — — — * Represents prorated initial distribution. (1) Series A, Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis. Sunoco LP Cash Distributions The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Marginal Percentage Interest in Distributions Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs Minimum Quarterly Distribution $0.4375 100% —% First Target Distribution $0.4375 to $0.503125 100% —% Second Target Distribution $0.503125 to $0.546875 85% 15% Third Target Distribution $0.546875 to $0.656250 75% 25% Thereafter Above $0.656250 50% 50% Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2018 February 6, 2019 February 14, 2019 $ 0.8255 March 31, 2019 May 7, 2019 May 15, 2019 0.8255 June 30, 2019 August 6, 2019 August 14, 2019 0.8255 September 30, 2019 November 5, 2019 November 19, 2019 0.8255 December 31, 2019 February 7, 2020 February 19, 2020 0.8255 March 31, 2020 May 7, 2020 May 19, 2020 0.8255 June 30, 2020 August 7, 2020 August 19, 2020 0.8255 September 30, 2020 November 6, 2020 November 19, 2020 0.8255 December 31, 2020 February 8, 2021 February 19, 2021 0.8255 March 31, 2021 May 11, 2021 May 19, 2021 0.8255 June 30, 2021 August 6, 2021 August 19, 2021 0.8255 September 30, 2021 November 5, 2021 November 19, 2021 0.8255 December 31, 2021 February 8, 2022 February 18, 2022 0.8255 USAC Cash Distributions Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2021, USAC had approximately 97.3 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs. Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2018 January 28, 2019 February 8, 2019 $ 0.5250 March 31, 2019 April 29, 2019 May 10, 2019 0.5250 June 30, 2019 July 29, 2019 August 9, 2019 0.5250 September 30, 2019 October 28, 2019 November 8, 2019 0.5250 December 31, 2019 January 27, 2020 February 7, 2020 0.5250 March 31, 2020 April 27, 2020 May 8, 2020 0.5250 June 30, 2020 July 31, 2020 August 10, 2020 0.5250 September 30, 2020 October 26, 2020 November 6, 2020 0.5250 December 31, 2020 January 25, 2021 February 5, 2021 0.5250 March 31, 2021 April 26, 2021 May 7, 2021 0.5250 June 30, 2021 July 26, 2021 August 6, 2021 0.5250 September 30, 2021 October 25, 2021 November 5, 2021 0.5250 December 31, 2021 January 24, 2022 February 4, 2022 0.5250 Accumulated Other Comprehensive Income The following table presents the components of AOCI, net of tax: December 31, 2021 2020 Available-for-sale securities $ 19 $ 18 Foreign currency translation adjustment 13 7 Actuarial gain (loss) related to pensions and other postretirement benefits 5 (7) Investments in unconsolidated affiliates, net (11) (14) Total AOCI, net of tax 26 4 Amounts attributable to noncontrolling interests (3) 2 Total AOCI included in partners’ capital, net of tax $ 23 $ 6 The table below sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 2021 2020 Available-for-sale securities $ (1) $ (1) Foreign currency translation adjustment 6 8 Actuarial loss relating to pension and other postretirement benefits 1 3 Total $ 6 $ 10 |
Unit-Based Compensation Plans
Unit-Based Compensation Plans | 12 Months Ended |
Dec. 31, 2021 | |
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Abstract] | |
Unit-Based Compensation Plans | EQUITY INCENTIVE PLANS: We, Sunoco LP and USAC, have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other equity-based compensation awards. As of December 31, 2021, an aggregate total of 12.7 million Energy Transfer Common Units remain available to be awarded under our equity incentive plans. Energy Transfer Long-Term Incentive Plan We have granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, Energy Transfer Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five-year service vesting requirement. The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2020 29.4 $ 11.26 Replacement awards issued in the Enable Acquisition 2.7 8.32 Awards granted 11.9 8.46 Awards vested (6.4) 15.10 Awards forfeited (1.5) 11.23 Unvested awards as of December 31, 2021 36.1 $ 9.49 During the years ended December 31, 2021, 2020, and 2019, the weighted average grant-date fair value per unit award granted was $8.46, $6.29 and $12.51, respectively, and the total fair value of awards vested was $52 million, $51 million, and $47 million, respectively, based on the market price of the respective Common Units as of the vesting date. As of December 31, 2021, a total of 36.1 million unit awards remain unvested, for which Energy Transfer expects to recognize a total of $208 million in compensation expense over a weighted average period of 2.9 years. Cash Restricted Units. The Partnership has also granted cash restricted units, which vest through three years of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one Energy Transfer Common Unit upon vesting. For the years ended December 31, 2021 and 2020, the Partnership granted a total of 3.9 million and 7.7 million cash restricted units, respectively. As of December 31, 2021, a total of 8.6 million cash restricted units were unvested. As of December 31, 2021, the Partnership’s consolidated balance sheet reflected aggregate liabilities of $3.1 million related to cash restricted units. Subsidiary Long-Term Incentive Plans Each of Sunoco LP and USAC has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards”) to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a three or five-year period, that entitles the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding. The following table summarizes the activity of the Subsidiary Unit Awards: Sunoco LP USAC Number of Weighted Average Number of Weighted Average Unvested awards as of December 31, 2020 2.1 $ 28.63 2.1 $ 14.88 Awards granted 0.5 37.72 0.6 14.92 Awards vested (0.5) 27.06 (0.4) 15.13 Awards forfeited (0.1) 28.57 (0.1) 14.50 Unvested awards as of December 31, 2021 2.0 $ 30.92 2.2 $ 13.57 The following table summarizes the weighted average grant-date fair value per unit award granted: Years Ended December 31, 2021 2020 2019 Sunoco LP $ 37.72 $ 28.63 $ 30.70 USAC 14.92 12.55 15.88 The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2021, 2020 and 2019 was $24 million, $16 million, and $17 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date. As of December 31, 2021, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $56 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.4 years. |
Income Taxes Income Taxes (Note
Income Taxes Income Taxes (Notes) | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | INCOME TAXES: As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows: Years Ended December 31, 2021 2020 2019 Current expense (benefit): Federal $ 19 $ (6) $ (20) State 24 32 (2) Foreign — 1 — Total 43 27 (22) Deferred expense (benefit): Federal 246 176 174 State (106) 41 43 Foreign 1 (7) — Total 141 210 217 Total income tax expense $ 184 $ 237 $ 195 Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2021, 2020 and 2019 is as follows: Years Ended December 31, 2021 2020 2019 Income tax expense at United States statutory rate $ 1,443 $ 79 $ 1,054 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax (1,211) 88 (866) Noncontrolling interests — 16 — State tax, net of federal tax benefit 85 58 12 Statutory rate change (46) — — Valuation allowance (63) — — Uncertain tax positions (34) — — Dividend received deduction (4) — (3) Foreign taxes 1 (7) — Other 13 3 (2) Income tax expense $ 184 $ 237 $ 195 Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2021 2020 Deferred income tax assets: Net operating losses and other carryforwards $ 803 $ 1,047 Pension and other postretirement benefits — — Other 35 34 Total deferred income tax assets 838 1,081 Valuation allowance (34) (134) Net deferred income tax assets 804 947 Deferred income tax liabilities: Property, plant and equipment (314) (298) Investments in affiliates (4,042) (3,994) Trademarks (79) (77) Other (17) (6) Total deferred income tax liabilities (4,452) (4,375) Net deferred income taxes $ (3,648) $ (3,428) As of December 31, 2021, ETP Holdco had a federal net operating loss carryforward of $3.1 billion, of which $1.1 billion will expire in 2031 through 2037 while the remaining can be carried forward indefinitely. A total of $338 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. As of December 31, 2021, Sunoco Retail LLC (formerly Sunoco Property Company LLC), a corporate subsidiary of Sunoco LP, had a state net operating loss carryforward of $114 million, which we expect to fully utilize. Sunoco Retail LLC has no federal net operating loss carryforward. Our corporate subsidiaries have state net operating loss carryforward benefits of $116 million, net of federal tax, some of which expire between 2022 and 2040, while others are carried forward indefinitely. Our corporate subsidiaries have Canadian net operating losses of $6 million that will begin to expire in 2033. Our corporate subsidiaries have cumulative excess business interest expense of $79 million available for carryforward indefinitely. A valuation allowance of $9 million is attributable to state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $25 million is attributable to foreign tax credits. The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2021 2020 2019 Balance at beginning of year $ 90 $ 94 $ 624 Additions attributable to tax positions taken in prior years — — 11 Reduction attributable to tax positions taken in prior years (34) — (541) Lapse of statute — (4) — Balance at end of year $ 56 $ 90 $ 94 As of December 31, 2021, we had $56 million ($51 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2021, we recognized interest and penalties of less than $7 million. At December 31, 2021, we have interest and penalties accrued of $17 million, net of tax. We appealed the adverse Court of Federal Claims decision against ETC Sunoco regarding the IRS’ denial of ethanol blending credits claims under Section 6426 to the Federal Circuit. The Federal Circuit affirmed the CFC’s denial on November 1, 2018. ETC Sunoco filed a petition for certiorari with the Supreme Court on May 24, 2019 to review the Federal Circuit’s affirmation of the CFC’s ruling, and the Court denied Sunoco’s petition on October 7, 2019. Due to the uncertainty surrounding the litigation, a reserve of $530 million was previously established for the full amount of the pending refund claims, and the receivable and reserve for this issue were netted in the consolidated balance sheet. Subsequent to the Supreme Court’s denial of the petition in October 2019, the receivable and reserve have been reversed, with no impact to the Partnership’s financial position and results of operations. In November 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact. Nextel subsequently filed a petition for writ of certiorari with the United States Supreme Court, and this was denied on June 11, 2018. Certain Pennsylvania taxpayers have subsequently undertaken litigation in Pennsylvania state courts on issues not addressed by the Pennsylvania Supreme Court in Nextel, specifically, whether the Due Process and Equal Protection Clauses of the United States Constitution and the Remedies Clause of the Pennsylvania Constitution require a court to grant the taxpayer relief. On December 22, 2021, the Pennsylvania Supreme Court found in General Motors Corporation v. Commonwealth (“GM”) that the taxpayer was entitled to meaningful backwards looking relief under the Due Process Clause, meaning the Commonwealth must equalize the taxpayer’s position with taxpayers who were not affected by the NOL cap in place for the year at issue. The Court therefore held the taxpayer was entitled to a refund by calculating its tax for that year with an uncapped NOL deduction. We believe the Pennsylvania Supreme Court’s ruling in GM will more likely than not be upheld if challenged by the Commonwealth. ETC Sunoco previously recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. In addition, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, ETC Sunoco previously reserved $34 million ($27 million after federal income tax benefits) against the receivable. Subsequent to the Pennsylvania Supreme Court’s decision in GM, the reserve has been reversed and the entire tax benefit of $34 million ($27 million after federal income tax benefit) has been recognized by the Partnership. In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2016 and prior tax years. USAC is currently under examination by the IRS for years 2019 and 2020. Energy Transfer and its other subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations. |
Regulatory Matters, Commitments
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | 12 Months Ended |
Dec. 31, 2021 | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
Commitments Contingencies and Guarantees | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: Winter Storm Impacts Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s consolidated net income and also affected the results of operations in certain segments. The recognition of the impacts of Winter Storm Uri during the year ended December 31, 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership’s financial condition and results of operations in future periods. FERC Proceedings In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in their submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021 and a surreply on September 15, 2021. FERC issued an order on January 20, 2022 setting the matter for hearing before an administrative law judge. On January 25, 2022, the chief judge assigned an administrative law judge and set a timeline for a prehearing conference. On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the United States District Court for the Northern District of Texas seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before an administrative law judge). Also on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the outcome of the federal district court case. Energy Transfer and Rover intend to vigorously defend this claim. In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigation. Enforcement Staff has provided Rover with a notice pursuant to Section 1b.19 of the Commission’s regulations that Enforcement Staff intends to recommend that the Commission pursue an enforcement action against Rover and the Partnership. The company disagrees with Enforcement Staff’s findings and intends to vigorously defend against any potential penalty. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN17-4-000), ordering Rover to show cause why it should not be found to have violated Section 7(e) of the Natural Gas Act, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million. Rover filed an answer responding to this Order on December 22, 2021. The primary contractor (and one of the subcontractors) responsible for the HDD operations of the Tuscarawas River site have agreed to indemnify Rover and the Partnership for any and all losses, including any fines and penalties from government agencies, resulting from their actions in conducting such HDD operations. Given the stage of the proceedings, and the non-public nature of the investigation, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by Enforcement Staff. By the Order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. The initial decision by the administrative law judge was issued on March 26, 2021. On April 26, 2021, Panhandle filed its brief on exceptions to the initial decision. On May 17, 2021, Panhandle filed its brief opposing exceptions in this proceeding. This matter remains pending before the FERC. In May 2021, the FERC commenced an audit of SPLP for the period from January 1, 2018 to present to evaluate SPLP’s compliance with its FERC oil tariffs, the accounting requirements of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s Form No. 6, including Page 700, reporting requirements. The audit is ongoing. Commitments In the normal course of business, Energy Transfer purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. Energy Transfer believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations. Our joint venture agreements require that we fund our proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. We have certain non-cancelable rights-of-way (“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The table below reflects ROW expense included in operating expenses in the accompanying statements of operations: Years Ended December 31, 2021 2020 2019 ROW expense $ 48 $ 47 $ 45 Litigation and Contingencies We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period. As of December 31, 2021 and 2020, accruals of approximately $144 million and $101 million, respectively, were reflected on our consolidated balance sheets related to contingent obligations that met both the probable and reasonably estimable criteria. In addition, we may recognize additional contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii) losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the range of additional losses is estimated to be up to approximately $550 million. The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Dakota Access Pipeline On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) challenging permits issued by the United States Army Corps of Engineers (“USACE”) that allowed Dakota Access to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that allowed the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the District Court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the United States Court of Appeals for the District of Columbia (“Court of Appeals”) which granted an administrative stay of the District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 5, 2020, the Court of Appeals 1) granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, 2) denied a motion to stay the March 25 order pending a decision on the merits by the Court of Appeals as to whether the USACE would be required to prepare an EIS, and 3) denied a motion to stay the District Court’s order to vacate the easement during this appeal process. The August 5 order also states that the Court of Appeals expected the USACE to clarify its position with respect to whether USACE intended to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary. On August 10, 2020, the District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its decision-making process with respect to the continued operation of the pipeline. On August 31, 2020, the USACE submitted a status report that indicated that it considered the presence of the pipeline at the Lake Oahe crossing without an easement to constitute an encroachment on federal land, and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. The Tribes subsequently filed a motion seeking an injunction to stop the operation of the pipeline and both USACE and Dakota Access filed briefs in opposition of the motion for injunction. The motion for injunction was fully briefed as of January 8, 2021. On January 26, 2021, the Court of Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the easement. In this same January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline shut down and be emptied of oil. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General (December 17, 2021) and the Tribes (December 16, 2021). Dakota Access filed their reply on January 4, 2022. The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. The USACE also advised the District Court that it expected that the EIS will be completed by March 2022. On May 21, 2021, the District Court denied the Plaintiffs’ request for an injunction. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. The pipeline continues to operate pending completion of the EIS. The USACE now estimates that the EIS will be complete by the end of 2022. Energy Transfer cannot determine when or how future lawsuits will be resolved or the impact they may have on the Dakota Access pipelines; however, Energy Transfer expects after the law and complete record are fully considered, any such proceeding will be resolved in a manner that will allow the pipeline to continue to operate. In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations. Mont Belvieu Incident On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL LLC’s (“Lone Star”), now known as Energy Transfer GC NGLs LLC, facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage wells at the North Terminal that has not been returned to service. Lone Star has obtained payment for most of the losses it has submitted to the adjacent operator. Lone Star continues to quantify and seek reimbursement for outstanding losses. MTBE Litigation ETC Sunoco and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees. As of December 31, 2021, Sunoco Defendants are defendants in five cases, including one case each initiated by the States of Maryland and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco, and Sunoco Partners Marketing & Terminals L.P. (“SPMT”). It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position. Regency Merger Litigation On June 10, 2015, Adrian Dieckman (“Plaintiff”), a purported Regency unitholder, filed a class action complaint related to the Regency-ETO merger (the “Regency Merger”) in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP LP, Regency GP LLC, Energy Transfer, ETO, Energy Transfer Partners GP, L.P., and the members of Regency’s board of directors. The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement. On March 29, 2016, the Delaware Court of Chancery granted the defendants’ motion to dismiss the lawsuit in its entirety. Plaintiff appealed, and the Delaware Supreme Court reversed the judgment of the Court of Chancery. Plaintiff then filed an Amended Verified Class Action Complaint, which defendants moved to dismiss. The Court of Chancery granted in part and denied in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP LP and Regency GP LLC (the “Regency Defendants”). The Court of Chancery later granted Plaintiff’s unopposed motion for class certification. Trial was held on December 10-16, 2019, and a post-trial hearing was held on May 6, 2020. On February 15, 2021, the Court of Chancery ruled in favor of the Regency Defendants on all claims at issue in this litigation, determined that the Regency Merger was fair and reasonable to Regency, and denied Plaintiff any relief. On November 3, 2021, the Delaware Supreme Court affirmed the Court of Chancery’s judgment in favor of Regency Defendants, bringing this matter to a conclusion. Litigation Filed By or Against Williams In April and May 2016, The William Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against Energy Transfer, LE GP, LLC, and, in one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, “Energy Transfer Defendants”), alleging that Energy Transfer Defendants breached their obligations under the Energy Transfer-Williams merger agreement (the “Merger Agreement”). In general, Williams alleges that Energy Transfer Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) issuing the Partnership’s Series A convertible preferred units (the “Issuance”), and (c) making allegedly untrue representations and warranties in the Merger Agreement. After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of Energy Transfer Defendants and issued a declaratory judgment that Energy Transfer could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court did not reach a decision regarding Williams’ claims related to the Issuance nor the alleged untrue representations and warranties. On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June 2016 trial. In September 2016, the parties filed amended pleadings. Williams filed an amended complaint seeking a $410 million termination fee (the “Termination Fee”) based on the alleged breaches of the Merger Agreement listed above. Energy Transfer Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger Agreement by, among other things, (a) failing to use its reasonable best efforts to consummate the merger, (b) failing to provide material information to Energy Transfer for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, and (d) breaching the Merger Agreement’s forum-selection clause. Trial was held regarding the parties’ amended claims on May 10-17, 2021, and on December 29, 2021, the Court ruled in favor of Williams and awarded it the Termination Fee plus certain fees and expenses, holding that the Issuance breached the Merger Agreement and that Williams had not materially breached the Merger Agreement, though the Court awarded sanctions against Williams due to its CEO’s intentional spoliation of evidence. The Court did not reach a decision on Williams’ tax-related claims. A final judgment has not yet been entered. Energy Transfer Defendants’ deadline to file an appeal to the Delaware Supreme Court has not yet been set. Energy Transfer Defendants cannot predict the ultimate outcome of the Williams Litigation nor can the Energy Transfer Defendants predict the amount of time and expense that will be required to resolve the Williams Litigation. Rover On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants seeking to recover civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court, which the defendants opposed in briefs filed in February 2020. On April 22, 2020, the Ohio Supreme Court granted the Ohio EPA’s request for review. Briefing has concluded and oral argument was held on January 26, 2021. The parties are awaiting a decision. Revolution On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries. The Pennsylvania Office of Attorney General has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time. Chester County, Pennsylvania Investigation In December 2018, the former Chester County District Attorney (the “Chester County DA”) sent a letter to the Partnership stating that his office was investigating the Partnership and related entities for “potential crimes” related to the Mariner East pipelines. Subsequently, the matter was submitted to an Investigating Grand Jury in Chester County, Pennsylvania, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the Chester County DA sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the prescribed time period. In December 2019, the Chester County DA announced charges against a current employee related to the provision of security services. On June 25, 2020, a preliminary hearing was held on the charges against the employee, and the judge dismissed all charges. On April 22, 2021, the Chester County DA filed a Complaint and Consent Decree in the Court of Common Pleas of Chester County, Pennsylvania constituting a settlement agreement between the Chester County DA and the Partnership. A status conference was held on May 10, 2021, and an Amended Consent Decree was filed on June 16, 2021, which was approved and entered by the Court on December 20, 2021. Delaware County, Pennsylvania Investigation On March 11, 2019, the Delaware County District Attorney’s Office (the “Delaware County DA”) announced that the Delaware County DA and the Pennsylvania Attorney General’s Office (the “AG”), at the request of the Delaware County DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. On March 16, 2020, the AG served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. The Partnership has complied with the subpoena. On October 5, 2021, the AG held a press conference related to the Mariner East pipelines, released a Grand Jury Presentment and subsequently filed a criminal complaint against Energy Transfer in the Magisterial District Court No. 12-2-02 in Dauphin County, Pennsylvania with respect to 47 misdemeanor charges related to the discharge of industrial waste and pollution and one felony charge related to the failure to report information related to the discharges. The Partnership will defend itself vigorously against these charges. On October 13, 2021, the AG announced that he is running for Governor of Pennsylvania. Shareholder Litigation Regarding Pennsylvania Pipeline Construction Four purported unitholders of Energy Transfer filed derivative actions against various past and current members of Energy Transfer’s Board of Directors, LE GP, LLC, and Energy Transfer, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of Energy Transfer’s limited partnership agreement, tortious interference, abuse of control, and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania. They also seek damages and changes to Energy Transfer’s corporate governance structure. See Bettiol v. LE GP , Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren , Case No. 2:20-cv-00364-GAM (E.D. Pa.); and King v. LE GP , Case No. 3:20-cv-00719-X (N.D. Tex.). Another purported unitholder of Energy Transfer, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all others similarly situated, filed a suit under the federal securities laws purportedly on behalf of a class, against Energy Transfer and three of Energy Transfer’s directors, Kelcy L. Warren, John W. McReynolds, and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP , Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants Energy Transfer directors Marshall McCrea and Matthew Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed a motion to dismiss ACERS’ amended complaint. On April 6, 2021, the court granted in part and denied in part the defendants’ motion to dismiss. The court held that ACERS could proceed with its claims regarding certain statements put at issue by the amended complaint while also dismissing claims based on other statements. The court also dismissed without prejudice the claims against defendants McReynolds, McGinn, and Hennigan. Fact discovery is ongoing. The defendants cannot predict the outcome of these lawsuits or any lawsuits that might be filed subsequent to the date of this filing; nor can the defendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are without merit and intend to vigorously contest them. Cline Class Action Lawsuit On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco (R&M), LLC (now known as Energy Transfer R&M) and SPMT that alleged SPMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012 and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments, and pass through payments, as well as governmental agencies and publicly traded oil and gas companies. After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees. On August 27, 2020, SPMT filed its Notice of Appeal with the 10th Circuit and appealed the entirety of the Order. The matter was fully briefed, and oral argument was set for November 15, 2021. However, on November 1, 2021, the 10th Circuit dismissed the appeal due to jurisdictional concerns with finality of the Order. En banc rehearing of this decision was denied on November 29, 2021. On December 1, 2021, SPMT filed a Petition for Writ of Mandamus to the 10th Circuit to correct the jurisdictional problems and secure final judgment. On February 2, 2022, the 10th Circuit denied the Petition for Writ of Mandamus, citing that there are other avenues for SPMT to obtain adequate relief. SPMT cannot predict the outcome of the case, nor can SPMT predict the amount of time and expense that will be required to resolve the appeal but intends to vigorously appeal the entirety of the Order, including re-urging the district court to modify the Order and appealing the dismissal of SPMT’s appeal to the United States Supreme Court. Environmental Matters Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operatio |
Revenue (Notes)
Revenue (Notes) | 12 Months Ended |
Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer [Text Block] | REVENUE: Disaggregation of revenue The major types of revenue within our reportable segments, are as follows: • intrastate transportation and storage; • interstate transportation and storage; • midstream; • NGL and refined products transportation and services; • crude oil transportation and services; • investment in Sunoco LP; • fuel distribution and marketing; • all other; • investment in USAC; • contract operations; • retail parts and services; and • all other. Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Royal Dutch Shell plc (“Shell”). Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed. The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal. The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below: • In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed. • Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers. NGL and refined products transportation and services revenue Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Crude oil transportation and services revenue Our crude oil transportation and services segment revenues are primarily derived from providing transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed. Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Sunoco LP’s fuel distribution and marketing revenue Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin, and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. Under the new standard, to determine when control transfers to the customer, the shipping terms of the contract are assessed as shipping terms are considered a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized. Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer. Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor are recognized ratably over the term of the underlying lease. Sunoco LP’s all other revenue Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided). USAC’s contract operations revenue USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years, however USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract. Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower. USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin. The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date. There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration. USAC’s retail parts and services revenue USAC’s retail parts and service revenue is earned primarily on freight and crane charges that are directly reimbursable by USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration. All other revenue Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. Contract Balances with Customers The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability. The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services. The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed minimum fee, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license. The following table summarizes the consolidated activity of our contract liabilities: Contract Liabilities Balance, December 31, 2019 $ 367 Additions 788 Revenue recognized (846) Balance, December 31, 2020 309 Additions 849 Revenue recognized (699) Balance, December 31, 2021 $ 459 The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2021 and 2020 were as follows: December 31, 2021 2020 Contract Balances Contract asset $ 157 $ 121 Accounts receivable from contracts with customers 463 256 Costs to Obtain or Fulfill a Contract Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g. sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in future and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for the years ended December 31, 2021, 2020 and 2019 was $21 million, $18 million and $17 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less. Performance Obligations At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contracts, only the fixed component of the contracts are included in the table below. Sunoco LP distributes fuel under long-term contracts to branded distributors, branded and unbranded third-party dealers, and branded and unbranded retail fuel outlets. Sunoco LP branded supply contracts with distributors generally have both time and volume commitments that establish contract duration. These contracts have an initial term of approximately nine years, with an estimated, volume-weighted term remaining of approximately four years. As part of the asset purchase agreement with 7-Eleven, Sunoco LP and 7-Eleven and SEI Fuel (collectively, the “Distributor”) have entered into a 15-year take-or-pay fuel supply agreement in which the Distributor is required to purchase a volume of fuel that provides Sunoco LP a minimum amount of gross profit annually. Sunoco LP expects to recognize this revenue in accordance with the contract as Sunoco LP transfers control of the product to the customer. However, in case of annual shortfall Sunoco LP will recognize the amount payable by the Distributor at the sooner of the time at which the Distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price of the contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate the amount of variable consideration allocated to wholly unsatisfied performance obligations. In some contractual arrangements, Sunoco LP grants dealers a franchise license to operate Sunoco LP’s retail stores over the life of a franchise agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to Sunoco LP plus sales based royalties payable to Sunoco LP at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement. As of December 31, 2021, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $38.76 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below: Years Ending December 31, 2022 2023 2024 Thereafter Total Revenue expected to be recognized on contracts with customers existing as of December 31, 2021 $ 6,189 $ 5,594 $ 4,775 $ 22,198 $ 38,756 Practical Expedients Utilized by the Partnership The Partnership elected the following practical expedients in accordance with Topic 606: • Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers. • Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less. • Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components. • Incremental costs of obtaining a contract: The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would h |
Lease Accounting (Notes)
Lease Accounting (Notes) | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Lessee, Operating Leases [Text Block] | LEASE ACCOUNTING: Lessee Accounting The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives. Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance. For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded. The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of December 31, 2021 and 2020 were as follows: December 31, 2021 2020 Operating leases: Lease right-of-use assets, net $ 826 $ 863 Operating lease current liabilities 47 53 Accrued and other current liabilities 1 1 Non-current operating lease liabilities 814 837 Finance leases: Property, plant and equipment, net $ 1 $ 1 Lease right-of-use assets, net 12 3 Accrued and other current liabilities 1 1 Current maturities of long-term debt 3 1 Long-term debt, less current maturities 9 6 Other non-current liabilities 1 1 The components of lease expense for the years ended December 31, 2021 and 2020 were as follows: Year Ended December 31, Income Statement Location 2021 2020 Operating lease costs: Operating lease cost Cost of goods sold $ 10 $ 14 Operating lease cost Operating expenses 78 75 Operating lease cost Selling, general and administrative 17 17 Total operating lease costs 105 106 Finance lease costs: Amortization of lease assets Depreciation, depletion and amortization 1 3 Interest on lease liabilities Interest expense, net of capitalized interest 1 1 Total finance lease costs 2 4 Short-term lease cost Operating expenses 40 31 Variable lease cost Operating expenses 9 16 Lease costs, gross 156 157 Less: Sublease income Other revenue 45 48 Lease costs, net $ 111 $ 109 The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2021 and 2020 were as follows: December 31, 2021 2020 Weighted-average remaining lease term (years): Operating leases 19 22 Finance leases 29 9 Weighted-average discount rate (%): Operating leases 5 % 5 % Finance leases 4 % 8 % Cash flows and non-cash activity related to leases for the years ended December 31, 2021 and 2020 were as follows: Year Ended December 31, 2021 2020 Operating cash flows from operating leases $ (147) $ (117) Lease assets obtained in exchange for new finance lease liabilities 9 — Lease assets obtained in exchange for new operating lease liabilities 9 42 Maturities of lease liabilities as of December 31, 2021 are as follows: Operating leases Finance leases Total 2022 $ 90 $ 4 $ 94 2023 86 1 87 2024 82 — 82 2025 78 — 78 2026 75 — 75 Thereafter 1,064 15 1,079 Total lease payments 1,475 20 1,495 Less: present value discount 613 6 619 Present value of lease liabilities $ 862 $ 14 $ 876 Lessor Accounting Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement. Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2021 are as follows: Lease Payments 2022 $ 84 2023 47 2024 3 2025 2 2026 1 Thereafter 5 Total undiscounted cash flows $ 142 |
Derivative Assets And Liabiliti
Derivative Assets And Liabilities | 12 Months Ended |
Dec. 31, 2021 | |
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |
Derivative Assets And Liabilities | DERIVATIVE ASSETS AND LIABILITIES: Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes. We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy. The following table details our outstanding commodity-related derivatives: December 31, 2021 December 31, 2020 Notional Maturity Notional Maturity Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures 585 2022-2023 1,603 2021-2022 Basis Swaps IFERC/NYMEX (1) (66,665) 2022 (44,225) 2021-2022 Power (Megawatt): Forwards 653,000 2023-2029 1,392,400 2021-2029 Futures (604,920) 2022-2023 18,706 2021-2022 Options – Puts (7,859) 2022 519,071 2021 Options – Calls (30,932) 2022 2,343,293 2021 (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX 6,738 2022-2023 (29,173) 2021-2022 Swing Swaps IFERC (106,333) 2022-2023 11,208 2021 Fixed Swaps/Futures (63,898) 2022-2023 (53,575) 2021-2022 Forward Physical Contracts (5,950) 2023 (11,861) 2021 NGL (MBbls) – Forwards/Swaps 8,493 2022-2024 (5,840) 2021-2022 Crude (MBbls) – Forwards/Swaps 3,672 2022-2023 — — Refined Products (MBbls) – Futures (3,349) 2022-2023 (2,765) 2021 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (40,533) 2022 (30,113) 2021 Fixed Swaps/Futures (40,533) 2022 (30,113) 2021 Hedged Item – Inventory 40,533 2022 30,113 2021 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. Interest Rate Risk We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances. The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: Term Type (1) Notional Amount Outstanding December 31, 2021 December 31, 2020 July 2021 (2) (3) Forward-starting to pay a fixed rate of 3.55% and receive a floating rate $ — $ 400 July 2022 (2) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 400 400 July 2023 (2) Forward-starting to pay a fixed rate of 3.78% and receive a floating rate 200 — July 2024 (2) Forward-starting to pay a fixed rate of 3.88% and receive a floating rate 200 — (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date. (3) The July 2021 interest rate swaps were amended in June 2021. Credit Risk and Customers Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income. Derivative Summary The following table provides a summary of our derivative assets and liabilities: Fair Value of Derivative Instruments Asset Derivatives Liability Derivatives December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 46 $ 25 $ (3) $ (32) 46 25 (3) (32) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 173 90 (156) (166) Commodity derivatives 53 53 (52) (71) Interest rate derivatives — — (387) (448) 226 143 (595) (685) Total derivatives $ 272 $ 168 $ (598) $ (717) The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 Derivatives without offsetting agreements Derivative liabilities $ — $ — $ (387) $ (448) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 53 53 (52) (71) Broker cleared derivative contracts Other current assets (liabilities) 219 115 (159) (198) 272 168 (598) (717) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (43) (44) 43 44 Counterparty netting Other current assets (liabilities) (150) (64) 150 64 Total net derivatives $ 79 $ 60 $ (405) $ (609) We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement The following tables summarize the amounts recognized with respect to our derivative financial instruments: Location of Gain (Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2021 2020 2019 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Revenues $ — $ — $ (3) Commodity derivatives – Trading Cost of products sold (6) 8 21 Commodity derivatives – Non-trading Cost of products sold (141) (34) (100) Interest rate derivatives Gains (losses) on interest rate derivatives 61 (203) (241) Total $ (86) $ (229) $ (323) |
Retirement Benefits
Retirement Benefits | 12 Months Ended |
Dec. 31, 2021 | |
Retirement Benefits [Abstract] | |
Retirement Benefits | RETIREMENT BENEFITS: Savings and Profit Sharing Plans We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of Lake Charles LNG, Sunoco LP and USAC. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $65 million, $35 million and $66 million to these 401(k) savings plans for the years ended December 31, 2021, 2020 and 2019, respectively. As a result of the economic conditions in 2020, effective June 8, 2020, the Partnership ceased employer matching and profit sharing contributions through December 31, 2020. The Partnership resumed all such contributions in 2021. Pension and Other Postretirement Benefit Plans Panhandle Postretirement benefits expense for the years ended December 31, 2021, 2020, and 2019 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees. Effective January 1, 2018, the plan was amended to extend coverage to a closed group of former employees based on certain criteria. ETC Sunoco ETC Sunoco has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by ETC Sunoco. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. ETC Sunoco has established a trust for its postretirement benefit liabilities. The funding of the trust eliminated substantially all of ETC Sunoco’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations. SemGroup SemGroup sponsors two defined benefit pension plans and a supplemental defined benefit pension plan (collectively, the “SemGroup Plans”) for certain employees. The SemGroup Plans are closed to new participants and do not accrue any additional benefits. Obligations and Funded Status Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: December 31, 2021 December 31, 2020 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Change in benefit obligation: Benefit obligation at beginning of period $ 55 $ 31 $ 208 $ 52 $ 34 $ 208 Service cost — — 1 — — 1 Interest cost 1 1 4 2 1 5 Benefits paid, net (2) (4) (16) (2) (5) (16) Actuarial (gain) loss and other (2) (2) (2) 5 1 10 Settlements (2) — — (2) — — Benefit obligation at end of period 50 26 195 55 31 208 Change in plan assets: Fair value of plan assets at beginning of period 45 — 291 43 — 270 Return on plan assets and other 2 — 26 5 — 28 Employer contributions 1 — 10 1 — 9 Benefits paid, net (2) — (16) (2) — (16) Settlements (2) — — (2) — — Fair value of plan assets at end of period 44 — 311 45 — 291 Amount underfunded (overfunded) at end of period $ 6 $ 26 $ (116) $ 10 $ 31 $ (83) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 138 $ — $ — $ 108 Current liabilities — (4) (2) — (4) (2) Non-current liabilities (6) (22) (20) (10) (27) (23) $ (6) $ (26) $ 116 $ (10) $ (31) $ 83 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain (loss) $ — $ 1 $ (27) $ — $ 2 $ (18) Prior service cost — — 19 — — 21 $ — $ 1 $ (8) $ — $ 2 $ 3 The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2021 December 31, 2020 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 50 $ 26 N/A $ 55 $ 31 N/A Accumulated benefit obligation 50 26 195 55 31 208 Fair value of plan assets 44 — 311 45 — 291 Components of Net Periodic Benefit Cost December 31, 2021 December 31, 2020 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Service cost $ — $ 1 $ — $ 1 Interest cost 2 4 3 5 Expected return on plan assets (2) (11) (2) (11) Prior service cost amortization — 19 — 19 Net periodic benefit cost $ — $ 13 $ 1 $ 14 Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2021 December 31, 2020 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 2.79 % 2.24 % 2.40 % 2.04 % The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2021 December 31, 2020 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 2.57 % 2.18 % 3.05 % 2.94 % Expected return on assets: Tax exempt accounts 4.76 % 7.00 % 4.57 % 7.00 % Taxable accounts — 4.75 % — 4.75 % The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness. The assumed health care cost trend weighted-average rates used to measure the expected cost of benefits covered by the plans are shown in the table below: December 31, 2021 2020 Health care cost trend rate 7.14 % 7.30 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.95 % 4.82 % Year that the rate reaches the ultimate trend rate 2028 2027 Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits. Plan Assets For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%. The investment strategy of ETC Sunoco funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, ETC Sunoco targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets. The fair value of the pension plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2021 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Cash and cash equivalents $ 1 $ 1 $ — $ — Mutual funds (1) 24 24 — — Fixed income securities 19 — 19 — Total $ 44 $ 25 $ 19 $ — (1) Comprised of approximately 100% equities as of December 31, 2021. Fair Value Measurements at December 31, 2020 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Cash and cash equivalents $ 1 $ 1 $ — $ — Mutual funds (1) 20 20 — — Fixed income securities 24 — 24 — Total $ 45 $ 21 $ 24 $ — (1) Comprised of approximately 100% equities as of December 31, 2020. The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2021 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 22 $ 22 $ — $ — Mutual funds (1) 175 175 — — Fixed income securities 114 — 114 — Total $ 311 $ 197 $ 114 $ — (1) Primarily composed of market index funds as of December 31, 2021. Fair Value Measurements at December 31, 2020 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 18 $ 18 $ — $ — Mutual funds (1) 202 202 — — Fixed income securities 71 — 71 — Total $ 291 $ 220 $ 71 $ — (1) Primarily composed of market index funds as of December 31, 2020. The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. Contributions We expect to contribute $5 million to pension plans and $8 million to other postretirement plans in 2022. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes. Benefit Payments The Partnership’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: Years Pension Benefits - Funded Plans Pension Benefits - Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2022 $ 4 $ 4 $ 18 2023 3 4 17 2024 3 3 16 2025 2 3 15 2026 2 2 14 2027 – 2031 11 7 57 The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Panhandle does not expect to receive any Medicare Part D subsidies in any future periods. |
Reportable Segments
Reportable Segments | 12 Months Ended |
Dec. 31, 2021 | |
Reportable Segments [Abstract] | |
Reportable Segments | REPORTABLE SEGMENTS: Our reportable segments currently reflect the following segments, which conduct their business primarily in the United States: • intrastate transportation and storage; • interstate transportation and storage; • midstream; • NGL and refined products transportation and services; • crude oil transportation and services; • investment in Sunoco LP; • investment in USAC; and • all other. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are reflected in crude sales and gathering, transportation and other fees. Revenues from our investment in Sunoco LP segment are primarily reflected in refined product sales. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales. We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Segment Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly. The following tables present financial information by segment: Years Ended December 31, 2021 2020 2019 Revenues: Intrastate transportation and storage: Revenues from external customers $ 7,307 $ 2,312 $ 2,749 Intersegment revenues 1,264 232 350 8,571 2,544 3,099 Interstate transportation and storage: Revenues from external customers 1,802 1,841 1,941 Intersegment revenues 39 20 22 1,841 1,861 1,963 Midstream: Revenues from external customers 2,620 1,944 2,280 Intersegment revenues 8,696 3,082 3,751 11,316 5,026 6,031 NGL and refined products transportation and services: Revenues from external customers 16,989 8,501 9,920 Intersegment revenues 2,972 2,012 1,721 19,961 10,513 11,641 Crude oil transportation and services: Revenues from external customers 17,442 11,674 18,447 Intersegment revenues 4 5 — 17,446 11,679 18,447 Investment in Sunoco LP: Revenues from external customers 17,571 10,653 16,590 Intersegment revenues 25 57 6 17,596 10,710 16,596 Investment in USAC: Revenues from external customers 621 655 678 Intersegment revenues 12 12 20 633 667 698 All other: Revenues from external customers 3,065 1,374 1,608 Intersegment revenues 411 464 81 3,476 1,838 1,689 Eliminations (13,423) (5,884) (5,951) Total revenues $ 67,417 $ 38,954 $ 54,213 Years Ended December 31, 2021 2020 2019 Cost of products sold: Intrastate transportation and storage $ 4,769 $ 1,478 $ 1,909 Interstate transportation and storage 11 — — Midstream 8,569 2,598 3,577 NGL and refined products transportation and services 16,248 7,139 8,393 Crude oil transportation and services 14,759 8,838 14,832 Investment in Sunoco LP 16,246 9,654 15,380 Investment in USAC 85 82 91 All other 3,068 1,527 1,504 Eliminations (13,360) (5,829) (5,885) Total cost of products sold $ 50,395 $ 25,487 $ 39,801 Years Ended December 31, 2021 2020 2019 Depreciation, depletion and amortization: Intrastate transportation and storage $ 191 $ 185 $ 184 Interstate transportation and storage 457 411 387 Midstream 1,190 1,140 1,066 NGL and refined products transportation and services 778 667 613 Crude oil transportation and services 588 640 437 Investment in Sunoco LP 177 189 181 Investment in USAC 239 239 231 All other 197 207 48 Total depreciation, depletion and amortization $ 3,817 $ 3,678 $ 3,147 Years Ended December 31, 2021 2020 2019 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 20 $ 18 $ 18 Interstate transportation and storage 140 17 222 Midstream 24 24 20 NGL and refined products transportation and services 51 60 53 Crude oil transportation and services 10 (2) (1) All other 1 2 (10) Total equity in earnings of unconsolidated affiliates $ 246 $ 119 $ 302 Years Ended December 31, 2021 2020 2019 Segment Adjusted EBITDA: Intrastate transportation and storage $ 3,483 $ 863 $ 999 Interstate transportation and storage 1,515 1,680 1,792 Midstream 1,868 1,670 1,602 NGL and refined products transportation and services 2,828 2,802 2,666 Crude oil transportation and services 2,023 2,258 2,898 Investment in Sunoco LP 754 739 665 Investment in USAC 398 414 420 All Other 177 105 98 Total Segment Adjusted EBITDA 13,046 10,531 11,140 Depreciation, depletion and amortization (3,817) (3,678) (3,147) Interest expense, net of interest capitalized (2,267) (2,327) (2,331) Impairment losses (21) (2,880) (74) Gains (losses) on interest rate derivatives 61 (203) (241) Non-cash compensation expense (111) (121) (113) Unrealized gains (losses) on commodity risk management activities 162 (71) (5) Inventory valuation adjustments 190 (82) 79 Losses on extinguishments of debt (38) (75) (18) Adjusted EBITDA related to unconsolidated affiliates (523) (628) (626) Equity in earnings of unconsolidated affiliates 246 119 302 Impairment of investments in unconsolidated affiliates — (129) — Other, net (57) (79) 54 Income before income tax expense 6,871 377 5,020 Income tax expense (184) (237) (195) Net income $ 6,687 $ 140 $ 4,825 December 31, 2021 2020 2019 Segment assets: Intrastate transportation and storage $ 7,322 $ 6,308 $ 6,648 Interstate transportation and storage 17,774 17,582 18,111 Midstream 21,960 18,583 20,332 NGL and refined products transportation and services 28,160 21,423 19,145 Crude oil transportation and services 19,649 17,960 22,933 Investment in Sunoco LP 5,815 5,267 5,438 Investment in USAC 2,768 2,949 3,730 All other and eliminations 2,515 5,072 2,636 Total segment assets $ 105,963 $ 95,144 $ 98,973 Years Ended December 31, 2021 2020 2019 Additions to property, plant and equipment (1) : Intrastate transportation and storage $ 52 $ 49 $ 124 Interstate transportation and storage 159 150 375 Midstream 484 487 827 NGL and refined products transportation and services 751 2,403 2,976 Crude oil transportation and services 343 291 403 Investment in Sunoco LP 174 124 148 Investment in USAC 60 119 200 All other 135 136 215 Total additions to property, plant and equipment (1) $ 2,158 $ 3,759 $ 5,268 (1) Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis). December 31, 2021 2020 2019 Investments in unconsolidated affiliates: Intrastate transportation and storage $ 110 $ 89 $ 88 Interstate transportation and storage 2,209 2,278 2,524 Midstream 101 110 112 NGL and refined products transportation and services 476 509 461 Crude oil transportation and services — 22 242 All other 51 52 33 Total investments in unconsolidated affiliates $ 2,947 $ 3,060 $ 3,460 |
Operations And Organization Ope
Operations And Organization Operations and Organization (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Accounting, Policy [Policy Text Block] | The consolidated financial statements of Energy Transfer LP presented herein for the years ended December 31, 2021, 2020 and 2019, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. |
Estimates, Significant Accoun_2
Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. |
Regulatory Accounting - Regulatory Assets and Liabilities | Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities, in accordance with Accounting Standards Codification (“ASC”) Topic 980. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment under ASC Topic 980 for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the NGA and NGPA, Panhandle does not currently apply ASC Topic 980 in its GAAP-basis consolidated financial statements, primarily due to the level of discounting from tariff rates and its inability to recover specific costs. |
Cash, Cash Equivalents and Supplemental Cash Flow Information | Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. |
Accounts Receivable | Accounts Receivable Our operations deal with a variety of counterparties across the energy sector. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. |
Inventories | Inventories Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method. Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2021 and 2020, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $121 million and $311 million, respectively. The fuel inventory balance is not materially different than its replacement cost at the respective dates. For the years ended December 31, 2021, 2020 and 2019, the Partnership’s consolidated statements of operations and comprehensive income did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the years ended December 31, 2021 and 2019, Sunoco LP’s cost of sales included favorable inventory adjustments of $190 million and $79 million, respectively, and for the year ended December 31, 2020, Sunoco LP’s cost of sales included a write-down of fuel inventory of $82 million. The Partnership’s inventories consisted of the following: December 31, 2021 2020 Natural gas, NGLs and refined products $ 1,259 $ 1,013 Crude oil 328 287 Spare parts and other 427 439 Total inventories $ 2,014 $ 1,739 |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC-mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment is retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2021, USAC recognized a $5 million fixed asset impairment related to its compression equipment as a result of its evaluation of the future deployment of idle fleet. In 2020, the Partnership recognized a $58 million fixed asset impairment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. USAC recorded an $8 million impairment of compression equipment as a result of its evaluations of the future deployment of its idle fleet. In 2019, USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets. Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York. |
Other Non-Current Assets, net | Other Non-Current Assets, netOther non-current assets, net are stated at cost less accumulated amortization. |
Intangible Assets | Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: December 31, 2021 December 31, 2020 Gross Carrying Accumulated Gross Carrying Accumulated Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 7,982 $ (2,464) $ 7,513 $ (2,117) Patents (10 years) 48 (44) 48 (40) Trade names (20 years) 66 (38) 66 (35) Other (5 to 20 years) 19 (20) 19 (15) Total amortizable intangible assets 8,115 (2,566) 7,646 (2,207) Non-amortizable intangible assets: Trademarks 295 — 295 — Other 12 — 12 — Total non-amortizable intangible assets 307 — 307 — Total intangible assets $ 8,422 $ (2,566) $ 7,953 $ (2,207) Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2021 2020 2019 Reported in depreciation, depletion and amortization expense $ 352 $ 403 $ 308 Estimated aggregate amortization of intangible assets for the next five years is as follows: Years Ending December 31: 2022 $ 379 2023 362 2024 348 2025 335 2026 331 |
Goodwill | Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test was performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: Intrastate Interstate Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total Balance, December 31, 2019 $ 10 $ 226 $ 483 $ 693 $ 1,397 $ 1,555 $ 619 $ 184 $ 5,167 Acquired — — — — — 9 — — 9 Impaired (10) (226) (483) — (1,279) — (619) (198) (2,815) Other — — — — (66) — — 96 30 Balance, December 31, 2020 — — — 693 52 1,564 — 82 2,391 Acquired — — — — 138 4 — — 142 Balance, December 31, 2021 $ — $ — $ — $ 693 $ 190 $ 1,568 $ — $ 82 $ 2,533 As of December 31, 2021, the all other segment includes $72 million of goodwill allocated to a reporting unit that had a negative carrying value. During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. The Partnership performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized goodwill impairments of $483 million related to our Ark-La-Tex and South Texas operations within the midstream segment, $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations. During the third quarter of 2020, the Partnership performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $1.28 billion related to our crude operations, $132 million related to our Energy Transfer Canada operations within the all other segment and $43 million related to our interstate operations primarily due to decreases in projected future cash flow as a result of the overall market demand decline. During the fourth quarter of 2020, the Partnership performed annual impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $10 million related to our intrastate operations, $11 million related to our PEI operations and $15 million related to our Natural Resources operations within the all other segment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. No other impairments of the Partnership’s goodwill were identified. Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the fourth quarter of 2019, $265 million of goodwill was recorded in conjunction with the acquisition of SemGroup. During the fourth quarter of 2021, $138 million of goodwill was recorded in conjunction with the acquisition of Enable. In addition, Sunoco LP recorded $4 million of goodwill in conjunction with its acquisition of eight refined product terminals. During the third quarter of 2019, the Partnership recognized a goodwill impairment of $12 million related to the Southwest Gas operations within the interstate segment primarily due to decreases in projected future revenues and cash flows. During the fourth quarter of 2019, the Partnership recognized a goodwill impairment of $9 million related to our North Central operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows. The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result |
Asset Retirement Obligation | Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an ARO in the periods in which management can reasonably estimate the settlement dates. As of December 31, 2021 and 2020, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $369 million and $280 million, respectively. For the years ended December 31, 2021, 2020 and 2019 aggregate accretion expense related to AROs was $12 million, $16 million and $5 million, respectively. Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2021 and 2020, in most cases because the settlement dates were indeterminable. Although a number of onshore assets in our systems are subject to agreements or regulations that give rise to an ARO upon discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Our subsidiaries also have legal obligations for several other assets at previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, our subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional AROs related to pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks. |
Redeemable Noncontrolling Interest [Text Block] | Redeemable Noncontrolling Interests Our redeemable noncontrolling interests relate to certain preferred unitholders of one of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in one of our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 7 for further information. |
Environmental Costs, Policy [Policy Text Block] | Environmental RemediationWe accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. |
Contributions In Aid Of Construction Costs Policy Text Block | Contributions in Aid of Construction Costs On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received. |
Shipping and Handling Costs | Shipping and Handling CostsShipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses. |
Costs and Expenses | Costs and Expenses Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel. We record the collection of taxes to be remitted to government authorities on a net basis, except for consumer excise taxes collected by Sunoco LP on sales of refined products and merchandise which are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income. For the years ended December 31, 2021, 2020 and 2019, excise taxes collected by Sunoco LP were $332 million, $301 million and $386 million, respectively. |
Issuances of Subsidiary Units | Issuances of Subsidiary UnitsWe record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interests are adjusted as a change in partners’ capital. |
Income Taxes | Income Taxes Energy Transfer is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”). We do not have access to information regarding each partner’s individual tax basis in our limited partner interests. As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, Energy Transfer would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2021, 2020 and 2019, our qualifying income met the statutory requirement. The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Sunoco Retail LLC and Aloha. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax |
Accounting for Derivative Instruments and Hedging Activities | Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period. If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations. Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations. |
Share-based Payment Arrangement [Policy Text Block] | For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of the underlying common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of the underlying common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets. |
Pension and Other Postretirement Plans, Policy [Policy Text Block] | Pensions and Other Postretirement Benefit PlansThe Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability. |
Allocation of Income (Loss) | Allocation of Income For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. |
Equity Method Investments Issuances, Policy | Investments in Unconsolidated AffiliatesWe own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. During the year ended December 31, 2020, the Partnership recorded an impairment of its investment in White Cliffs of $129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup acquisition in December 2019. |
Revenue (Policies)
Revenue (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |
Revenue Recognition | Disaggregation of revenue The major types of revenue within our reportable segments, are as follows: • intrastate transportation and storage; • interstate transportation and storage; • midstream; • NGL and refined products transportation and services; • crude oil transportation and services; • investment in Sunoco LP; • fuel distribution and marketing; • all other; • investment in USAC; • contract operations; • retail parts and services; and • all other. Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Royal Dutch Shell plc (“Shell”). Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed. The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal. The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below: • In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed. • Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers. NGL and refined products transportation and services revenue Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Crude oil transportation and services revenue Our crude oil transportation and services segment revenues are primarily derived from providing transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed. Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Sunoco LP’s fuel distribution and marketing revenue Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin, and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. Under the new standard, to determine when control transfers to the customer, the shipping terms of the contract are assessed as shipping terms are considered a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized. Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer. Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor are recognized ratably over the term of the underlying lease. Sunoco LP’s all other revenue Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided). USAC’s contract operations revenue USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years, however USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract. Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower. USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin. The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date. There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration. USAC’s retail parts and services revenue USAC’s retail parts and service revenue is earned primarily on freight and crane charges that are directly reimbursable by USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration. All other revenue |
Lease Accounting (Policies)
Lease Accounting (Policies) | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Lessee, Leases [Policy Text Block] | Lessee Accounting The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives. Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance. For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded. |
Lessor, Leases [Policy Text Block] | Lessor AccountingSunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement. |
Estimates, Significant Accoun_3
Estimates, Significant Accounting Policies and Balance Sheet Detail (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Accounting Policies [Abstract] | |
Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities | The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows: Years Ended December 31, 2021 2020 2019 Accounts receivable $ (3,356) $ 1,163 $ (473) Accounts receivable from related companies 38 (290) (69) Inventories (19) (271) (19) Other current assets (216) 172 117 Other non-current assets, net 1 (7) (102) Accounts payable 3,834 (1,327) 146 Accounts payable to related companies (34) 367 (32) Accrued and other current liabilities 238 163 (44) Other non-current liabilities 117 8 (133) Derivative assets and liabilities, net (88) 69 218 Net change in operating assets and liabilities, net of effects of acquisitions $ 515 $ 47 $ (391) |
Schedule Of Non-Cash Investing And Financing Activities | Non-cash investing and financing activities and supplemental cash flow information are as follows: Years Ended December 31, 2021 2020 2019 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 464 $ 604 $ 1,334 Units issued in connection with the Enable Acquisition (1) 3,509 — — Lease assets obtained in exchange for new lease liabilities 18 42 68 Acquisition of interest in unconsolidated affiliate 49 — — SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest, net of interest capitalized $ 2,188 $ 2,092 $ 1,932 Cash paid for income taxes (net of refunds) 41 (64) 31 (1) See Note 3 for additional information. |
Schedule of Inventory | The Partnership’s inventories consisted of the following: December 31, 2021 2020 Natural gas, NGLs and refined products $ 1,259 $ 1,013 Crude oil 328 287 Spare parts and other 427 439 Total inventories $ 2,014 $ 1,739 |
Other Current Assets | Other current assets consisted of the following: December 31, 2021 2020 Deposits paid to vendors $ 215 $ 75 Prepaid expenses and other 222 138 Total other current assets $ 437 $ 213 |
Property, Plant and Equipment | Components and useful lives of property, plant and equipment were as follows: December 31, 2021 2020 Land and improvements $ 1,369 $ 1,233 Buildings and improvements (1 to 45 years) 4,598 4,236 Pipelines and equipment (5 to 83 years) 77,112 69,120 Product storage and related facilities (2 to 83 years) 7,410 6,393 Right of way (20 to 83 years) 5,021 5,099 Other (1 to 48 years) 2,816 2,263 Construction work-in-process 5,665 5,771 103,991 94,115 Less – Accumulated depreciation and depletion (22,384) (19,008) Property, plant and equipment, net $ 81,607 $ 75,107 |
Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense | We recognized the following amounts for the periods presented: Years Ended December 31, 2021 2020 2019 Depreciation, depletion and amortization expense $ 3,465 $ 3,275 $ 2,839 Capitalized interest 135 189 166 |
Schedule of Other Non-Current Assets, net | Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: December 31, 2021 2020 Crude pipeline linefill and tank bottoms $ 498 $ 517 Regulatory assets 42 41 Pension assets 140 103 Deferred charges 177 188 Restricted funds 164 179 Other 624 629 Total other non-current assets, net $ 1,645 $ 1,657 |
Components And Useful Lives Of Intangibles And Other Assets | Components and useful lives of intangible assets were as follows: December 31, 2021 December 31, 2020 Gross Carrying Accumulated Gross Carrying Accumulated Amortizable intangible assets: Customer relationships, contracts and agreements (3 to 46 years) $ 7,982 $ (2,464) $ 7,513 $ (2,117) Patents (10 years) 48 (44) 48 (40) Trade names (20 years) 66 (38) 66 (35) Other (5 to 20 years) 19 (20) 19 (15) Total amortizable intangible assets 8,115 (2,566) 7,646 (2,207) Non-amortizable intangible assets: Trademarks 295 — 295 — Other 12 — 12 — Total non-amortizable intangible assets 307 — 307 — Total intangible assets $ 8,422 $ (2,566) $ 7,953 $ (2,207) |
Aggregate Amortization Expense Of Intangibles And Other Assets | Aggregate amortization expense of intangible assets was as follows: Years Ended December 31, 2021 2020 2019 Reported in depreciation, depletion and amortization expense $ 352 $ 403 $ 308 |
Estimated Aggregate Amortization Expense | Estimated aggregate amortization of intangible assets for the next five years is as follows: Years Ending December 31: 2022 $ 379 2023 362 2024 348 2025 335 2026 331 |
Schedule of Goodwill | Changes in the carrying amount of goodwill were as follows: Intrastate Interstate Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services Investment in Sunoco LP Investment in USAC All Other Total Balance, December 31, 2019 $ 10 $ 226 $ 483 $ 693 $ 1,397 $ 1,555 $ 619 $ 184 $ 5,167 Acquired — — — — — 9 — — 9 Impaired (10) (226) (483) — (1,279) — (619) (198) (2,815) Other — — — — (66) — — 96 30 Balance, December 31, 2020 — — — 693 52 1,564 — 82 2,391 Acquired — — — — 138 4 — — 142 Balance, December 31, 2021 $ — $ — $ — $ 693 $ 190 $ 1,568 $ — $ 82 $ 2,533 |
Accrued and Other Current Liabilities | Accrued and other current liabilities consisted of the following: December 31, 2021 2020 Interest payable $ 561 $ 600 Customer advances and deposits 188 161 Accrued capital expenditures 461 604 Accrued wages and benefits 297 109 Taxes payable other than income taxes 384 446 Exchanges payable 155 127 Deferred revenue 158 112 Other 867 616 Total accrued and other current liabilities $ 3,071 $ 2,775 |
Schedule of Derivative Assets at Fair Value | The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2021 and 2020 based on inputs used to derive their fair values: Fair Value Total Fair Value Measurements at December 31, 2021 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 7 $ 7 $ — Swing Swaps IFERC 38 38 — Fixed Swaps/Futures 26 26 — Forward Physical Contracts 7 — 7 Power: Forwards 17 — 17 Futures 6 6 — NGLs – Forwards/Swaps 152 152 — Refined Products – Futures 3 3 — Crude – Forwards/Swaps 16 16 — Total commodity derivatives 272 248 24 Other non-current assets 39 26 13 Total assets $ 311 $ 274 $ 37 Liabilities: Interest rate derivatives $ (387) $ — $ (387) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (10) (10) — Swing Swaps IFERC (6) (6) — Fixed Swaps/Futures (9) (9) — Forward Physical Contracts (6) — (6) Power: Forwards (15) — (15) Futures (4) (4) — NGLs – Forwards/Swaps (140) (140) — Refined Products – Futures (18) (18) — Crude – Forwards/Swaps (3) (3) — Total commodity derivatives (211) (190) (21) Total liabilities $ (598) $ (190) $ (408) Fair Value Total Fair Value Measurements at December 31, 2020 Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 12 $ 12 $ — Swing Swaps IFERC 1 — 1 Fixed Swaps/Futures 13 13 — Forward Physical Contracts 5 — 5 Power: Power – Forwards 4 — 4 Futures 2 2 — Options – Calls 1 1 — NGLs – Forwards/Swaps 127 127 — Refined Products – Futures 3 3 — Total commodity derivatives 168 158 10 Other non-current assets 34 22 12 Total assets $ 202 $ 180 $ 22 Liabilities: Interest rate derivatives $ (448) $ — $ (448) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (11) (11) — Swing Swaps IFERC (3) — (3) Fixed Swaps/Futures (13) (13) — Forward Physical Contracts (1) — (1) Power: Futures (3) (3) — NGLs – Forwards/Swaps (227) (227) — Refined Products – Futures (11) (11) — Total commodity derivatives (269) (265) (4) Total liabilities $ (717) $ (265) $ (452) |
Acquisitions and Related Tran_2
Acquisitions and Related Transactions (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
SemGroup [Member] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | During the first and second quarters of 2020, Energy Transfer contributed former SemGroup assets to ETO through sale and contribution transactions. The following table represents the fair value, as of December 5, 2019, of the SemGroup assets and liabilities transferred from Energy Transfer to ETO: At December 5, 2019 Total current assets $ 794 Property, plant and equipment 3,891 Other non-current assets 617 Goodwill 295 Intangible assets 460 Total assets $ 6,057 Total current liabilities $ 629 Long-term debt, less current maturities (1) 2,576 Other non-current liabilities 197 Energy Transfer Canada Preferred shares 241 Total liabilities 3,643 Noncontrolling interest 822 Partners’ capital 1,592 Total liabilities and partners’ capital $ 6,057 (1) Long-term debt at December 5, 2019 includes SemGroup senior notes with an aggregate principal amount of $1.375 billion and SemGroup subsidiary debt of $593 million, all of which was redeemed in December 2019, subsequent to the close of the SemGroup Transaction. During 2020, the Partnership has recorded impairments on certain of the contributed SemGroup assets. Those impairments include a $244 million impairment of goodwill and a $129 million impairment of other non-current assets. |
Enable | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed: At December 2, 2021 Total current assets $ 593 Property, plant and equipment, net 7,076 Investments in unconsolidated affiliates 40 Other non-current assets 39 Intangible assets, net 440 Goodwill 138 Total assets 8,326 Total current liabilities 488 Long-term debt, less current maturities (1) 4,267 Other non-current liabilities 18 Total liabilities 4,773 Noncontrolling interests 34 Total consideration 3,519 Cash received 61 Total consideration $ 3,458 (1) Long-term debt at December 2, 2021 includes Enable senior notes with an aggregate principal amount of $3.18 billion in senior notes and a fair value of $3.43 billion. It also includes $800 million outstanding on the Enable 2019 Term Loan Agreement and $35 million outstanding on the Enable Five-Year Revolving Credit Facility, both of which were repaid and terminated in December 2021, immediately subsequent to the close of the Enable Acquisition. |
Advances to and Investments i_2
Advances to and Investments in Unconsolidated Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Investment In Affiliates [Abstract] | |
Schedule Of Aggregated Selected Balance Sheet And Income Statement Data For Our Unconsolidated Affiliates | The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2021 and 2020 were as follows: December 31, 2021 2020 Citrus $ 1,792 $ 1,867 FEP — 4 MEP 378 406 White Cliffs 245 274 Other 532 509 Total $ 2,947 $ 3,060 The following table presents equity in earnings (losses) of unconsolidated affiliates: Years Ended December 31, 2021 2020 2019 Citrus $ 157 $ 162 $ 148 FEP (1) — (139) 59 MEP (17) (6) 15 White Cliffs — 20 4 Other 106 82 76 Total equity in earnings of unconsolidated affiliates $ 246 $ 119 $ 302 (1) For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million. |
Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block] | The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP, and White Cliffs (on a 100% basis) for all periods presented: December 31, 2021 2020 Current assets $ 242 $ 227 Property, plant and equipment, net 7,239 7,339 Other assets 77 58 Total assets $ 7,558 $ 7,624 Current liabilities $ 500 $ 600 Non-current liabilities 3,602 3,298 Equity 3,456 3,726 Total liabilities and equity $ 7,558 $ 7,624 Years Ended December 31, 2021 2020 2019 Revenue $ 1,003 $ 1,243 $ 1,192 Operating income 459 6 683 Net income (loss) 282 (199) 443 In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements. |
Net Income Per Limited Partne_2
Net Income Per Limited Partner Unit (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Earnings Per Share [Abstract] | |
Reconciliation Of Net Income (Loss) And Weighted Average Units | A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows: Years Ended December 31, 2021 2020 2019 Net income $ 6,687 $ 140 $ 4,825 Less: Net income attributable to redeemable noncontrolling interests 50 49 51 Less: Net income attributable to noncontrolling interests 1,167 739 1,256 Net income (loss), net of noncontrolling interests 5,470 (648) 3,518 Less: General Partner’s interest in income (loss) 6 (1) 4 Less: Preferred Unitholders’ interest in income 285 — — Income (loss) available to Limited Partners $ 5,179 $ (647) $ 3,514 Basic Income (Loss) per Limited Partner Unit: Weighted average limited partner units 2,734.4 2,695.6 2,628.0 Basic income (loss) per Limited Partner unit $ 1.89 $ (0.24) $ 1.34 Diluted Income (Loss) per Limited Partner Unit: Income (loss) available to Limited Partners $ 5,179 $ (647) $ 3,514 Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units (2) — (1) Diluted income (loss) available to Limited Partners $ 5,177 $ (647) $ 3,513 Weighted average limited partner units 2,734.4 2,695.6 2,628.0 Dilutive effect of unvested unit awards 5.1 — 9.6 Weighted average limited partner units, assuming dilutive effect of unvested unit awards 2,739.5 2,695.6 2,637.6 Diluted income (loss) per Limited Partner unit $ 1.89 $ (0.24) $ 1.33 |
Debt Obligations Debt Obligatio
Debt Obligations Debt Obligations (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Debt Obligations [Abstract] | |
Schedule of debt obligations | Our debt obligations consist of the following: December 31, 2021 2020 Energy Transfer Indebtedness 4.40% Senior Notes due April 1, 2021 (1) $ — $ 600 4.65% Senior Notes due June 1, 2021 (1) — 800 5.20% Senior Notes due February 1, 2022 (1) — 1,000 4.65% Senior Notes due February 15, 2022 (2) 300 300 5.875% Senior Notes due March 1, 2022 (1) — 900 5.00% Senior Notes due October 1, 2022 (2) 700 700 3.45% Senior Notes due January 15, 2023 350 350 3.60% Senior Notes due February 1, 2023 800 800 4.25% Senior Notes due March 15, 2023 5 5 4.25% Senior Notes due March 15, 2023 995 995 4.20% Senior Notes due September 15, 2023 500 500 4.50% Senior Notes due November 1, 2023 600 600 5.875% Senior Notes due January 15, 2024 23 23 5.875% Senior Notes due January 15, 2024 1,127 1,127 4.90% Senior Notes due February 1, 2024 350 350 7.60% Senior Notes due February 1, 2024 277 277 4.25% Senior Notes due April 1, 2024 500 500 4.50% Senior Notes due April 15, 2024 750 750 3.90% Senior Notes due May 15, 2024 (3) 600 — 9.00% Debentures due November 1, 2024 65 65 4.05% Senior Notes due March 15, 2025 1,000 1,000 2.90% Senior Notes due May 15, 2025 1,000 1,000 5.95% Senior Notes due December 1, 2025 400 400 4.75% Senior Notes due January 15, 2026 1,000 1,000 3.90% Senior Notes due July 15, 2026 550 550 4.40% Senior Notes due March 15, 2027 (3) 700 — 4.20% Senior Notes due April 15, 2027 600 600 5.50% Senior Notes due June 1, 2027 44 44 5.50% Senior Notes due June 1, 2027 956 956 4.00% Senior Notes due October 1, 2027 750 750 4.95% Senior Notes due May 15, 2028 (3) 800 — 4.95% Senior Notes due June 15, 2028 1,000 1,000 5.25% Senior Notes due April 15, 2029 1,500 1,500 4.15% Senior Notes due September 15, 2029 (3) 547 — 8.25% Senior Notes due November 15, 2029 267 267 3.75% Senior Note due May 15, 2030 1,500 1,500 4.90% Senior Notes due March 15, 2035 500 500 6.625% Senior Notes due October 15, 2036 400 400 5.80% Senior Notes due June 15, 2038 500 500 7.50% Senior Notes due July 1, 2038 550 550 6.85% Senior Notes due February 15, 2040 250 250 6.05% Senior Notes due June 1, 2041 700 700 6.50% Senior Notes due February 1, 2042 1,000 1,000 6.10% Senior Notes due February 15, 2042 300 300 4.95% Senior Notes due January 15, 2043 350 350 5.15% Senior Notes due February 1, 2043 450 450 5.95% Senior Notes due October 1, 2043 450 450 5.30% Senior Notes due April 1, 2044 700 700 5.00% Senior Notes due May 15, 2044 (3) 531 — 5.15% Senior Notes due March 15, 2045 1,000 1,000 5.35% Senior Notes due May 15, 2045 800 800 6.125% Senior Notes due December 15, 2045 1,000 1,000 5.30% Senior Notes due April 15, 2047 900 900 5.40% Senior Notes due October 1, 2047 1,500 1,500 6.00% Senior Notes due June 15, 2048 1,000 1,000 6.25% Senior Notes due April 15, 2049 1,750 1,750 5.00% Senior Notes due May 15, 2050 2,000 2,000 Floating Rate Junior Subordinated Notes due November 1, 2066 546 546 Term Loan — 2,000 Five-Year Credit Facility 2,937 3,103 Unamortized premiums, discounts and fair value adjustments, net 233 (17) Deferred debt issuance costs (186) (215) 40,717 42,726 Subsidiary Indebtedness Transwestern Debt 5.89% Senior Notes due May 24, 2022 (2) 150 150 5.66% Senior Notes due December 9, 2024 175 175 6.16% Senior Notes due May 24, 2037 75 75 400 400 Panhandle Debt 7.60% Senior Notes due February 1, 2024 82 82 7.00% Senior Notes due July 15, 2029 66 66 8.25% Senior Notes due November 15, 2029 33 33 Floating Rate Junior Subordinated Notes due November 1, 2066 54 54 Unamortized premiums, discounts and fair value adjustments, net 8 10 243 245 Bakken Project Debt 3.625% Senior Notes due April 1, 2022 650 650 3.90% Senior Notes due April 1, 2024 1,000 1,000 4.625% Senior Notes due April 1, 2029 850 850 Unamortized premiums, discounts and fair value adjustments, net (2) (3) Deferred debt issuance costs (9) (13) 2,489 2,484 Sunoco LP Debt 4.875% Senior Notes Due January 15, 2023 — 436 5.50% Senior Notes Due February 15, 2026 — 800 6.00% Senior Notes Due April 15, 2027 600 600 5.875% Senior Notes Due March 15, 2028 400 400 4.50% Senior Notes due May 15, 2029 800 800 4.50% Senior Notes due April 30, 2030 800 — Sunoco LP $1.50 billion Revolving Credit Facility due July 2023 581 — Lease-related obligations 100 103 Deferred debt issuance costs (26) (27) 3,255 3,112 USAC Debt 6.875% Senior Notes due April 1, 2026 725 725 6.875% Senior Notes due September 1, 2027 750 750 USAC $1.60 billion Revolving Credit Facility due December 2026 516 474 Deferred debt issuance costs (18) (22) 1,973 1,927 HFOTCO Debt HFOTCO Tax Exempt Notes due 2050 225 225 Unamortized premiums, discounts and fair value adjustments, net (1) (2) 224 223 Energy Transfer Canada Debt Energy Transfer Canada Revolving Credit Facility 7 57 Energy Transfer Canada Term Loan A 249 261 Energy Transfer Canada KAPS Facility 142 — 398 318 Other 3 3 Total debt 49,702 51,438 Less: Current maturities of long-term debt 680 21 Long-term debt, less current maturities $ 49,022 $ 51,417 |
Future maturities of long-term debt | The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $1 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: 2022 $ 1,827 2023 3,859 2024 8,250 2025 2,407 2026 2,799 Thereafter 30,561 Total $ 49,703 |
Equity (Tables)
Equity (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Change In ETE Common Units | The change in Energy Transfer Common Units during the years ended December 31, 2021, 2020 and 2019 was as follows: Years Ended December 31, 2021 2020 2019 Number of Common Units, beginning of period 2,702.4 2,689.6 2,619.4 Common Units issued in mergers and acquisitions (1) 374.6 — 57.6 Common Units repurchased (4.2) — (1.9) Issuance of Common Units (2) 9.7 12.8 14.5 Number of Common Units, end of period 3,082.5 2,702.4 2,689.6 |
Accumulated Other Comprehensive Income (Loss) | The following table presents the components of AOCI, net of tax: December 31, 2021 2020 Available-for-sale securities $ 19 $ 18 Foreign currency translation adjustment 13 7 Actuarial gain (loss) related to pensions and other postretirement benefits 5 (7) Investments in unconsolidated affiliates, net (11) (14) Total AOCI, net of tax 26 4 Amounts attributable to noncontrolling interests (3) 2 Total AOCI included in partners’ capital, net of tax $ 23 $ 6 |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The table below sets forth the tax amounts included in the respective components of other comprehensive income: December 31, 2021 2020 Available-for-sale securities $ (1) $ (1) Foreign currency translation adjustment 6 8 Actuarial loss relating to pension and other postretirement benefits 1 3 Total $ 6 $ 10 |
Schedule of Preferred Units | The following table summarizes changes in the Energy Transfer Preferred Units: Preferred Unitholders Series A Series B Series C Series D Series E Series F Series G Series H Total Balance, December 31, 2020 $ — $ — $ — $ — $ — $ — $ — $ — $ — Preferred units conversion 943 547 440 434 786 504 1,114 — 4,768 Units issued for cash — — — — — — — 889 889 Distributions to partners (30) (18) (25) (25) (45) (34) (79) (24) (280) Units issued in Enable Acquisition — — — — — — 392 — 392 Other, net — — — — — — — (3) (3) Net income 45 27 25 25 45 26 61 31 285 Balance, December 31, 2021 $ 958 $ 556 $ 440 $ 434 $ 786 $ 496 $ 1,488 $ 893 $ 6,051 |
Sunoco LP [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2018 February 6, 2019 February 14, 2019 $ 0.8255 March 31, 2019 May 7, 2019 May 15, 2019 0.8255 June 30, 2019 August 6, 2019 August 14, 2019 0.8255 September 30, 2019 November 5, 2019 November 19, 2019 0.8255 December 31, 2019 February 7, 2020 February 19, 2020 0.8255 March 31, 2020 May 7, 2020 May 19, 2020 0.8255 June 30, 2020 August 7, 2020 August 19, 2020 0.8255 September 30, 2020 November 6, 2020 November 19, 2020 0.8255 December 31, 2020 February 8, 2021 February 19, 2021 0.8255 March 31, 2021 May 11, 2021 May 19, 2021 0.8255 June 30, 2021 August 6, 2021 August 19, 2021 0.8255 September 30, 2021 November 5, 2021 November 19, 2021 0.8255 December 31, 2021 February 8, 2022 February 18, 2022 0.8255 |
Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution [Table Text Block] | The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Marginal Percentage Interest in Distributions Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs Minimum Quarterly Distribution $0.4375 100% —% First Target Distribution $0.4375 to $0.503125 100% —% Second Target Distribution $0.503125 to $0.546875 85% 15% Third Target Distribution $0.546875 to $0.656250 75% 25% Thereafter Above $0.656250 50% 50% |
USAC [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | USAC Cash Distributions Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2021, USAC had approximately 97.3 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs. Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2018 January 28, 2019 February 8, 2019 $ 0.5250 March 31, 2019 April 29, 2019 May 10, 2019 0.5250 June 30, 2019 July 29, 2019 August 9, 2019 0.5250 September 30, 2019 October 28, 2019 November 8, 2019 0.5250 December 31, 2019 January 27, 2020 February 7, 2020 0.5250 March 31, 2020 April 27, 2020 May 8, 2020 0.5250 June 30, 2020 July 31, 2020 August 10, 2020 0.5250 September 30, 2020 October 26, 2020 November 6, 2020 0.5250 December 31, 2020 January 25, 2021 February 5, 2021 0.5250 March 31, 2021 April 26, 2021 May 7, 2021 0.5250 June 30, 2021 July 26, 2021 August 6, 2021 0.5250 September 30, 2021 October 25, 2021 November 5, 2021 0.5250 December 31, 2021 January 24, 2022 February 4, 2022 0.5250 |
ET [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Our distributions declared and paid with respect to our common units were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2018 February 8, 2019 February 19, 2019 $ 0.3050 March 31, 2019 May 7, 2019 May 20, 2019 0.3050 June 30, 2019 August 6, 2019 August 19, 2019 0.3050 September 30, 2019 November 5, 2019 November 19, 2019 0.3050 December 31, 2019 February 7, 2020 February 19, 2020 0.3050 March 31, 2020 May 7, 2020 May 19, 2020 0.3050 June 30, 2020 August 7, 2020 August 19, 2020 0.3050 September 30, 2020 November 6, 2020 November 19, 2020 0.1525 December 31, 2020 February 8, 2021 February 19, 2021 0.1525 March 31, 2021 May 11, 2021 May 19, 2021 0.1525 June 30, 2021 August 6, 2021 August 19, 2021 0.1525 September 30, 2021 November 5, 2021 November 19, 2021 0.1525 December 31, 2021 February 8, 2022 February 18, 2022 0.1750 |
Preferred Units [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions on Energy Transfer’s Series A, Series B, Series C, Series D, Series E, Series F, Series G and Series H preferred units declared and/or paid by Energy Transfer were as follows: Period Ended Record Date Payment Date Series A (1) Series B (1) Series C Series D Series E Series F (1) Series G (1) Series H (1) March 31, 2021 May 3, 2021 May 17, 2021 $— $— $0.4609 $0.4766 $0.4750 $33.7500 $35.63 $— June 30, 2021 August 2, 2021 August 16, 2021 31.25 33.13 0.4609 0.4766 0.4750 — — — September 30, 2021 November 1, 2021 November 15, 2021 — — 0.4609 0.4766 0.4750 33.7500 35.63 27.08 * December 31, 2021 February 1, 2022 February 15, 2022 31.25 33.13 0.4609 0.4766 0.4750 — — — * Represents prorated initial distribution. (1) Series A, Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis. |
Non-Cash Compensation Plans Uni
Non-Cash Compensation Plans Unit-Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Schedule of weighted average grant-date fair values | The following table summarizes the weighted average grant-date fair value per unit award granted: Years Ended December 31, 2021 2020 2019 Sunoco LP $ 37.72 $ 28.63 $ 30.70 USAC 14.92 12.55 15.88 |
Schedule of Subsidiary Awards Granted To Employees And Non-Employee Directors | The following table shows the activity of the awards granted to employees and non-employee directors: Number of Units Weighted Average Grant-Date Fair Value Per Unit Unvested awards as of December 31, 2020 29.4 $ 11.26 Replacement awards issued in the Enable Acquisition 2.7 8.32 Awards granted 11.9 8.46 Awards vested (6.4) 15.10 Awards forfeited (1.5) 11.23 Unvested awards as of December 31, 2021 36.1 $ 9.49 |
Subsidiaries [Member] | |
Schedule of Subsidiary Awards Granted To Employees And Non-Employee Directors | The following table summarizes the activity of the Subsidiary Unit Awards: Sunoco LP USAC Number of Weighted Average Number of Weighted Average Unvested awards as of December 31, 2020 2.1 $ 28.63 2.1 $ 14.88 Awards granted 0.5 37.72 0.6 14.92 Awards vested (0.5) 27.06 (0.4) 15.13 Awards forfeited (0.1) 28.57 (0.1) 14.50 Unvested awards as of December 31, 2021 2.0 $ 30.92 2.2 $ 13.57 |
Income Taxes Income Taxes (Tabl
Income Taxes Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows: Years Ended December 31, 2021 2020 2019 Current expense (benefit): Federal $ 19 $ (6) $ (20) State 24 32 (2) Foreign — 1 — Total 43 27 (22) Deferred expense (benefit): Federal 246 176 174 State (106) 41 43 Foreign 1 (7) — Total 141 210 217 Total income tax expense $ 184 $ 237 $ 195 |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2021, 2020 and 2019 is as follows: Years Ended December 31, 2021 2020 2019 Income tax expense at United States statutory rate $ 1,443 $ 79 $ 1,054 Increase (reduction) in income taxes resulting from: Partnership earnings not subject to tax (1,211) 88 (866) Noncontrolling interests — 16 — State tax, net of federal tax benefit 85 58 12 Statutory rate change (46) — — Valuation allowance (63) — — Uncertain tax positions (34) — — Dividend received deduction (4) — (3) Foreign taxes 1 (7) — Other 13 3 (2) Income tax expense $ 184 $ 237 $ 195 |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: December 31, 2021 2020 Deferred income tax assets: Net operating losses and other carryforwards $ 803 $ 1,047 Pension and other postretirement benefits — — Other 35 34 Total deferred income tax assets 838 1,081 Valuation allowance (34) (134) Net deferred income tax assets 804 947 Deferred income tax liabilities: Property, plant and equipment (314) (298) Investments in affiliates (4,042) (3,994) Trademarks (79) (77) Other (17) (6) Total deferred income tax liabilities (4,452) (4,375) Net deferred income taxes $ (3,648) $ (3,428) |
ScheduleOfUnrecognizedTaxBenefits [Table Text Block] | The following table sets forth the changes in unrecognized tax benefits: Years Ended December 31, 2021 2020 2019 Balance at beginning of year $ 90 $ 94 $ 624 Additions attributable to tax positions taken in prior years — — 11 Reduction attributable to tax positions taken in prior years (34) — (541) Lapse of statute — (4) — Balance at end of year $ 56 $ 90 $ 94 |
Regulatory Matters, Commitmen_2
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Environmental Exit Costs by Cost [Table Text Block] | The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. December 31, 2021 2020 Current $ 46 $ 44 Non-current 247 262 Total environmental liabilities $ 293 $ 306 |
Right of way (20 to 83 years) | |
Other Commitments | We have certain non-cancelable rights-of-way (“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The table below reflects ROW expense included in operating expenses in the accompanying statements of operations: Years Ended December 31, 2021 2020 2019 ROW expense $ 48 $ 47 $ 45 |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Contract with Customer, Asset and Liability [Table Text Block] | The following table summarizes the consolidated activity of our contract liabilities: Contract Liabilities Balance, December 31, 2019 $ 367 Additions 788 Revenue recognized (846) Balance, December 31, 2020 309 Additions 849 Revenue recognized (699) Balance, December 31, 2021 $ 459 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block] | As of December 31, 2021, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $38.76 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below: Years Ending December 31, 2022 2023 2024 Thereafter Total Revenue expected to be recognized on contracts with customers existing as of December 31, 2021 $ 6,189 $ 5,594 $ 4,775 $ 22,198 $ 38,756 |
Sunoco LP [Member] | |
Contract with Customer, Asset and Liability [Table Text Block] | The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2021 and 2020 were as follows: December 31, 2021 2020 Contract Balances Contract asset $ 157 $ 121 Accounts receivable from contracts with customers 463 256 |
Lease Accounting (Tables)
Lease Accounting (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Leases [Abstract] | |
Schedule of Property Subject to or Available for Operating Lease [Table Text Block] | The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of December 31, 2021 and 2020 were as follows: December 31, 2021 2020 Operating leases: Lease right-of-use assets, net $ 826 $ 863 Operating lease current liabilities 47 53 Accrued and other current liabilities 1 1 Non-current operating lease liabilities 814 837 Finance leases: Property, plant and equipment, net $ 1 $ 1 Lease right-of-use assets, net 12 3 Accrued and other current liabilities 1 1 Current maturities of long-term debt 3 1 Long-term debt, less current maturities 9 6 Other non-current liabilities 1 1 |
Lease, Cost [Table Text Block] | The components of lease expense for the years ended December 31, 2021 and 2020 were as follows: Year Ended December 31, Income Statement Location 2021 2020 Operating lease costs: Operating lease cost Cost of goods sold $ 10 $ 14 Operating lease cost Operating expenses 78 75 Operating lease cost Selling, general and administrative 17 17 Total operating lease costs 105 106 Finance lease costs: Amortization of lease assets Depreciation, depletion and amortization 1 3 Interest on lease liabilities Interest expense, net of capitalized interest 1 1 Total finance lease costs 2 4 Short-term lease cost Operating expenses 40 31 Variable lease cost Operating expenses 9 16 Lease costs, gross 156 157 Less: Sublease income Other revenue 45 48 Lease costs, net $ 111 $ 109 |
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2021 and 2020 were as follows: December 31, 2021 2020 Weighted-average remaining lease term (years): Operating leases 19 22 Finance leases 29 9 Weighted-average discount rate (%): Operating leases 5 % 5 % Finance leases 4 % 8 % Maturities of lease liabilities as of December 31, 2021 are as follows: Operating leases Finance leases Total 2022 $ 90 $ 4 $ 94 2023 86 1 87 2024 82 — 82 2025 78 — 78 2026 75 — 75 Thereafter 1,064 15 1,079 Total lease payments 1,475 20 1,495 Less: present value discount 613 6 619 Present value of lease liabilities $ 862 $ 14 $ 876 |
Schedule of additional lease information [Table Text Block] | Cash flows and non-cash activity related to leases for the years ended December 31, 2021 and 2020 were as follows: Year Ended December 31, 2021 2020 Operating cash flows from operating leases $ (147) $ (117) Lease assets obtained in exchange for new finance lease liabilities 9 — Lease assets obtained in exchange for new operating lease liabilities 9 42 |
Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block] | Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2021 are as follows: Lease Payments 2022 $ 84 2023 47 2024 3 2025 2 2026 1 Thereafter 5 Total undiscounted cash flows $ 142 |
Derivative Assets And Liabili_2
Derivative Assets And Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |
Offsetting Assets [Table Text Block] | Asset Derivatives Liability Derivatives Balance Sheet Location December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 Derivatives without offsetting agreements Derivative liabilities $ — $ — $ (387) $ (448) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 53 53 (52) (71) Broker cleared derivative contracts Other current assets (liabilities) 219 115 (159) (198) 272 168 (598) (717) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (43) (44) 43 44 Counterparty netting Other current assets (liabilities) (150) (64) 150 64 Total net derivatives $ 79 $ 60 $ (405) $ (609) |
Outstanding Commodity-Related Derivatives | The following table details our outstanding commodity-related derivatives: December 31, 2021 December 31, 2020 Notional Maturity Notional Maturity Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures 585 2022-2023 1,603 2021-2022 Basis Swaps IFERC/NYMEX (1) (66,665) 2022 (44,225) 2021-2022 Power (Megawatt): Forwards 653,000 2023-2029 1,392,400 2021-2029 Futures (604,920) 2022-2023 18,706 2021-2022 Options – Puts (7,859) 2022 519,071 2021 Options – Calls (30,932) 2022 2,343,293 2021 (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX 6,738 2022-2023 (29,173) 2021-2022 Swing Swaps IFERC (106,333) 2022-2023 11,208 2021 Fixed Swaps/Futures (63,898) 2022-2023 (53,575) 2021-2022 Forward Physical Contracts (5,950) 2023 (11,861) 2021 NGL (MBbls) – Forwards/Swaps 8,493 2022-2024 (5,840) 2021-2022 Crude (MBbls) – Forwards/Swaps 3,672 2022-2023 — — Refined Products (MBbls) – Futures (3,349) 2022-2023 (2,765) 2021 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (40,533) 2022 (30,113) 2021 Fixed Swaps/Futures (40,533) 2022 (30,113) 2021 Hedged Item – Inventory 40,533 2022 30,113 2021 (1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Interest Rate Swaps Outstanding | The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: Term Type (1) Notional Amount Outstanding December 31, 2021 December 31, 2020 July 2021 (2) (3) Forward-starting to pay a fixed rate of 3.55% and receive a floating rate $ — $ 400 July 2022 (2) Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 400 400 July 2023 (2) Forward-starting to pay a fixed rate of 3.78% and receive a floating rate 200 — July 2024 (2) Forward-starting to pay a fixed rate of 3.88% and receive a floating rate 200 — (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date. (3) The July 2021 interest rate swaps were amended in June 2021. |
Fair Value Of Derivative Instruments | The following table provides a summary of our derivative assets and liabilities: Fair Value of Derivative Instruments Asset Derivatives Liability Derivatives December 31, 2021 December 31, 2020 December 31, 2021 December 31, 2020 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ 46 $ 25 $ (3) $ (32) 46 25 (3) (32) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 173 90 (156) (166) Commodity derivatives 53 53 (52) (71) Interest rate derivatives — — (387) (448) 226 143 (595) (685) Total derivatives $ 272 $ 168 $ (598) $ (717) |
Derivatives Not Designated as Hedging Instruments [Table Text Block] | Location of Gain (Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2021 2020 2019 Derivatives not designated as hedging instruments: Commodity derivatives – Trading Revenues $ — $ — $ (3) Commodity derivatives – Trading Cost of products sold (6) 8 21 Commodity derivatives – Non-trading Cost of products sold (141) (34) (100) Interest rate derivatives Gains (losses) on interest rate derivatives 61 (203) (241) Total $ (86) $ (229) $ (323) |
Retirement Benefits Retirement
Retirement Benefits Retirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Retirement Benefits [Abstract] | |
Schedule of Defined Benefit Plans Disclosures [Table Text Block] | Obligations and Funded Status Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: December 31, 2021 December 31, 2020 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Change in benefit obligation: Benefit obligation at beginning of period $ 55 $ 31 $ 208 $ 52 $ 34 $ 208 Service cost — — 1 — — 1 Interest cost 1 1 4 2 1 5 Benefits paid, net (2) (4) (16) (2) (5) (16) Actuarial (gain) loss and other (2) (2) (2) 5 1 10 Settlements (2) — — (2) — — Benefit obligation at end of period 50 26 195 55 31 208 Change in plan assets: Fair value of plan assets at beginning of period 45 — 291 43 — 270 Return on plan assets and other 2 — 26 5 — 28 Employer contributions 1 — 10 1 — 9 Benefits paid, net (2) — (16) (2) — (16) Settlements (2) — — (2) — — Fair value of plan assets at end of period 44 — 311 45 — 291 Amount underfunded (overfunded) at end of period $ 6 $ 26 $ (116) $ 10 $ 31 $ (83) Amounts recognized in the consolidated balance sheets consist of: Non-current assets $ — $ — $ 138 $ — $ — $ 108 Current liabilities — (4) (2) — (4) (2) Non-current liabilities (6) (22) (20) (10) (27) (23) $ (6) $ (26) $ 116 $ (10) $ (31) $ 83 Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: Net actuarial gain (loss) $ — $ 1 $ (27) $ — $ 2 $ (18) Prior service cost — — 19 — — 21 $ — $ 1 $ (8) $ — $ 2 $ 3 |
Defined Benefit Plan, Plan with Projected Benefit Obligation in Excess of Plan Assets [Table Text Block] | The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: December 31, 2021 December 31, 2020 Pension Benefits Pension Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits Projected benefit obligation $ 50 $ 26 N/A $ 55 $ 31 N/A Accumulated benefit obligation 50 26 195 55 31 208 Fair value of plan assets 44 — 311 45 — 291 |
Schedule of Health Care Cost Trend Rates [Table Text Block] | The assumed health care cost trend weighted-average rates used to measure the expected cost of benefits covered by the plans are shown in the table below: December 31, 2021 2020 Health care cost trend rate 7.14 % 7.30 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.95 % 4.82 % Year that the rate reaches the ultimate trend rate 2028 2027 |
Fair Value of Plan Assets [Table Text Block] | The fair value of the pension plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2021 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Cash and cash equivalents $ 1 $ 1 $ — $ — Mutual funds (1) 24 24 — — Fixed income securities 19 — 19 — Total $ 44 $ 25 $ 19 $ — (1) Comprised of approximately 100% equities as of December 31, 2021. Fair Value Measurements at December 31, 2020 Fair Value Total Level 1 Level 2 Level 3 Asset Category: Cash and cash equivalents $ 1 $ 1 $ — $ — Mutual funds (1) 20 20 — — Fixed income securities 24 — 24 — Total $ 45 $ 21 $ 24 $ — (1) Comprised of approximately 100% equities as of December 31, 2020. The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: Fair Value Measurements at December 31, 2021 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 22 $ 22 $ — $ — Mutual funds (1) 175 175 — — Fixed income securities 114 — 114 — Total $ 311 $ 197 $ 114 $ — (1) Primarily composed of market index funds as of December 31, 2021. Fair Value Measurements at December 31, 2020 Fair Value Total Level 1 Level 2 Level 3 Asset category: Cash and cash equivalents $ 18 $ 18 $ — $ — Mutual funds (1) 202 202 — — Fixed income securities 71 — 71 — Total $ 291 $ 220 $ 71 $ — (1) Primarily composed of market index funds as of December 31, 2020. |
Schedule of Expected Benefit Payments [Table Text Block] | Benefit Payments The Partnership’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: Years Pension Benefits - Funded Plans Pension Benefits - Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D) 2022 $ 4 $ 4 $ 18 2023 3 4 17 2024 3 3 16 2025 2 3 15 2026 2 2 14 2027 – 2031 11 7 57 |
Schedule of Net Benefit Costs [Table Text Block] | Components of Net Periodic Benefit Cost December 31, 2021 December 31, 2020 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Net periodic benefit cost: Service cost $ — $ 1 $ — $ 1 Interest cost 2 4 3 5 Expected return on plan assets (2) (11) (2) (11) Prior service cost amortization — 19 — 19 Net periodic benefit cost $ — $ 13 $ 1 $ 14 |
Defined Benefit Plan, Assumptions [Table Text Block] | The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: December 31, 2021 December 31, 2020 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 2.79 % 2.24 % 2.40 % 2.04 % The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: December 31, 2021 December 31, 2020 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits Discount rate 2.57 % 2.18 % 3.05 % 2.94 % Expected return on assets: Tax exempt accounts 4.76 % 7.00 % 4.57 % 7.00 % Taxable accounts — 4.75 % — 4.75 % |
Reportable Segments (Tables)
Reportable Segments (Tables) | 12 Months Ended |
Dec. 31, 2021 | |
Financial Information By Segment | The following tables present financial information by segment: Years Ended December 31, 2021 2020 2019 Revenues: Intrastate transportation and storage: Revenues from external customers $ 7,307 $ 2,312 $ 2,749 Intersegment revenues 1,264 232 350 8,571 2,544 3,099 Interstate transportation and storage: Revenues from external customers 1,802 1,841 1,941 Intersegment revenues 39 20 22 1,841 1,861 1,963 Midstream: Revenues from external customers 2,620 1,944 2,280 Intersegment revenues 8,696 3,082 3,751 11,316 5,026 6,031 NGL and refined products transportation and services: Revenues from external customers 16,989 8,501 9,920 Intersegment revenues 2,972 2,012 1,721 19,961 10,513 11,641 Crude oil transportation and services: Revenues from external customers 17,442 11,674 18,447 Intersegment revenues 4 5 — 17,446 11,679 18,447 Investment in Sunoco LP: Revenues from external customers 17,571 10,653 16,590 Intersegment revenues 25 57 6 17,596 10,710 16,596 Investment in USAC: Revenues from external customers 621 655 678 Intersegment revenues 12 12 20 633 667 698 All other: Revenues from external customers 3,065 1,374 1,608 Intersegment revenues 411 464 81 3,476 1,838 1,689 Eliminations (13,423) (5,884) (5,951) Total revenues $ 67,417 $ 38,954 $ 54,213 Years Ended December 31, 2021 2020 2019 Cost of products sold: Intrastate transportation and storage $ 4,769 $ 1,478 $ 1,909 Interstate transportation and storage 11 — — Midstream 8,569 2,598 3,577 NGL and refined products transportation and services 16,248 7,139 8,393 Crude oil transportation and services 14,759 8,838 14,832 Investment in Sunoco LP 16,246 9,654 15,380 Investment in USAC 85 82 91 All other 3,068 1,527 1,504 Eliminations (13,360) (5,829) (5,885) Total cost of products sold $ 50,395 $ 25,487 $ 39,801 Years Ended December 31, 2021 2020 2019 Depreciation, depletion and amortization: Intrastate transportation and storage $ 191 $ 185 $ 184 Interstate transportation and storage 457 411 387 Midstream 1,190 1,140 1,066 NGL and refined products transportation and services 778 667 613 Crude oil transportation and services 588 640 437 Investment in Sunoco LP 177 189 181 Investment in USAC 239 239 231 All other 197 207 48 Total depreciation, depletion and amortization $ 3,817 $ 3,678 $ 3,147 Years Ended December 31, 2021 2020 2019 Equity in earnings (losses) of unconsolidated affiliates: Intrastate transportation and storage $ 20 $ 18 $ 18 Interstate transportation and storage 140 17 222 Midstream 24 24 20 NGL and refined products transportation and services 51 60 53 Crude oil transportation and services 10 (2) (1) All other 1 2 (10) Total equity in earnings of unconsolidated affiliates $ 246 $ 119 $ 302 Years Ended December 31, 2021 2020 2019 Segment Adjusted EBITDA: Intrastate transportation and storage $ 3,483 $ 863 $ 999 Interstate transportation and storage 1,515 1,680 1,792 Midstream 1,868 1,670 1,602 NGL and refined products transportation and services 2,828 2,802 2,666 Crude oil transportation and services 2,023 2,258 2,898 Investment in Sunoco LP 754 739 665 Investment in USAC 398 414 420 All Other 177 105 98 Total Segment Adjusted EBITDA 13,046 10,531 11,140 Depreciation, depletion and amortization (3,817) (3,678) (3,147) Interest expense, net of interest capitalized (2,267) (2,327) (2,331) Impairment losses (21) (2,880) (74) Gains (losses) on interest rate derivatives 61 (203) (241) Non-cash compensation expense (111) (121) (113) Unrealized gains (losses) on commodity risk management activities 162 (71) (5) Inventory valuation adjustments 190 (82) 79 Losses on extinguishments of debt (38) (75) (18) Adjusted EBITDA related to unconsolidated affiliates (523) (628) (626) Equity in earnings of unconsolidated affiliates 246 119 302 Impairment of investments in unconsolidated affiliates — (129) — Other, net (57) (79) 54 Income before income tax expense 6,871 377 5,020 Income tax expense (184) (237) (195) Net income $ 6,687 $ 140 $ 4,825 December 31, 2021 2020 2019 Segment assets: Intrastate transportation and storage $ 7,322 $ 6,308 $ 6,648 Interstate transportation and storage 17,774 17,582 18,111 Midstream 21,960 18,583 20,332 NGL and refined products transportation and services 28,160 21,423 19,145 Crude oil transportation and services 19,649 17,960 22,933 Investment in Sunoco LP 5,815 5,267 5,438 Investment in USAC 2,768 2,949 3,730 All other and eliminations 2,515 5,072 2,636 Total segment assets $ 105,963 $ 95,144 $ 98,973 Years Ended December 31, 2021 2020 2019 Additions to property, plant and equipment (1) : Intrastate transportation and storage $ 52 $ 49 $ 124 Interstate transportation and storage 159 150 375 Midstream 484 487 827 NGL and refined products transportation and services 751 2,403 2,976 Crude oil transportation and services 343 291 403 Investment in Sunoco LP 174 124 148 Investment in USAC 60 119 200 All other 135 136 215 Total additions to property, plant and equipment (1) $ 2,158 $ 3,759 $ 5,268 (1) Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis). December 31, 2021 2020 2019 Investments in unconsolidated affiliates: Intrastate transportation and storage $ 110 $ 89 $ 88 Interstate transportation and storage 2,209 2,278 2,524 Midstream 101 110 112 NGL and refined products transportation and services 476 509 461 Crude oil transportation and services — 22 242 All other 51 52 33 Total investments in unconsolidated affiliates $ 2,947 $ 3,060 $ 3,460 |
Operations And Organization (Na
Operations And Organization (Narrative) (Details) - shares | 12 Months Ended | ||
Dec. 31, 2021 | Apr. 01, 2021 | Dec. 31, 2020 | |
Incentive Distribution Rights | 0.00% | ||
Issued | 3,082,497,494 | 2,702,352,154 | |
Class B Preferred Units [Member] | |||
Issued | 675,625,000 | ||
Sunoco LP [Member] | |||
Incentive Distribution Rights | 10000.00% | ||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 28.5 | ||
USAC [Member] | |||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 46,100,000 | ||
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest | 100.00% |
Estimates, Significant Accoun_4
Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($) $ in Millions | Dec. 02, 2021 | Dec. 05, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Impairment losses | $ 21 | $ 2,880 | $ 74 | ||||||||
Asset Retirement Obligation | $ 369 | $ 280 | 369 | 280 | |||||||
Costs Incurred, Asset Retirement Obligation Incurred | 12 | 16 | 5 | ||||||||
Asset Retirement Obligation, Legally Restricted Assets, Fair Value | 39 | 34 | 39 | 34 | |||||||
Long-term Debt, Fair Value | 54,970 | 56,210 | 54,970 | 56,210 | |||||||
Impairment losses | $ (9) | $ (12) | (2,815) | ||||||||
Goodwill | 142 | 9 | |||||||||
Goodwill | 2,533 | 2,391 | 5,167 | 2,533 | 2,391 | 5,167 | |||||
Long-term Debt | 49,702 | 51,438 | 49,702 | 51,438 | |||||||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net | 0 | ||||||||||
Inventory Write-down | 190 | 82 | 79 | ||||||||
Inventory Valuation Reserves | 121 | 311 | 121 | 311 | |||||||
Impairment of investment in unconsolidated affiliates | 0 | 129 | 0 | ||||||||
Revenue from Related Parties | 410 | 466 | 492 | ||||||||
White Cliffs | |||||||||||
Impairment of investment in unconsolidated affiliates | 129 | ||||||||||
Midstream | |||||||||||
Impairment losses | $ (483) | (483) | |||||||||
Goodwill | 0 | 0 | |||||||||
Goodwill | 0 | 0 | 483 | 0 | 0 | 483 | |||||
All Other | |||||||||||
Impairment losses | (15) | $ (132) | (40) | (198) | |||||||
Goodwill | 0 | 0 | |||||||||
Goodwill | 82 | 82 | 184 | 82 | 82 | 184 | |||||
Investment in Sunoco LP | |||||||||||
Impairment losses | 0 | ||||||||||
Goodwill | 4 | 9 | |||||||||
Goodwill | 1,568 | 1,564 | 1,555 | 1,568 | 1,564 | 1,555 | |||||
Retail Marketing [Member] | |||||||||||
Excise Taxes Collected | 332 | 301 | 386 | ||||||||
Interstate Transportation and Storage | |||||||||||
Impairment losses | 58 | ||||||||||
Impairment losses | (43) | (183) | (226) | ||||||||
Goodwill | 0 | 0 | |||||||||
Goodwill | 0 | 0 | 226 | 0 | 0 | 226 | |||||
Investment in USAC | |||||||||||
Impairment losses | $ (619) | (619) | |||||||||
Goodwill | 0 | 0 | |||||||||
Goodwill | 0 | 0 | 619 | 0 | 0 | 619 | |||||
Crude Oil Transportation and Services | |||||||||||
Impairment losses | $ (1,280) | (1,279) | |||||||||
Goodwill | 138 | 0 | |||||||||
Goodwill | 190 | 52 | 1,397 | 190 | 52 | 1,397 | |||||
Intrastate Transportation and Storage | |||||||||||
Impairment losses | (10) | (10) | |||||||||
Goodwill | 0 | 0 | |||||||||
Goodwill | 0 | 0 | 10 | 0 | 0 | 10 | |||||
Sunoco LP [Member] | |||||||||||
Impairment losses | 47 | ||||||||||
Long-term Debt | 3,255 | 3,112 | 3,255 | 3,112 | |||||||
USAC [Member] | |||||||||||
Impairment losses | 5 | $ 8 | $ 6 | ||||||||
PEI [Member] | All Other | |||||||||||
Impairment losses | $ (11) | ||||||||||
ETC Marketing | All Other | |||||||||||
Goodwill | 72 | $ 72 | |||||||||
SemGroup [Member] | |||||||||||
Goodwill | $ 295 | $ 265 | |||||||||
Enable | |||||||||||
Long-term Debt, Fair Value | $ 3,430 | ||||||||||
Goodwill | $ 138 | 138 | |||||||||
Sunoco LP [Member] | |||||||||||
Goodwill | $ 4 |
Estimates (Schedule Of Net Chan
Estimates (Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |||
Accounts receivable | $ (3,356) | $ 1,163 | $ (473) |
Accounts receivable from related companies | 38 | (290) | (69) |
Inventories | (19) | (271) | (19) |
Other current assets | 216 | (172) | (117) |
Other non-current assets, net | 1 | (7) | (102) |
Accounts payable | 3,834 | (1,327) | 146 |
Accounts payable to related companies | (34) | 367 | (32) |
Accrued and other current liabilities | 238 | 163 | (44) |
Other non-current liabilities | 117 | 8 | (133) |
Derivative assets and liabilities, net | (88) | 69 | 218 |
Net change in operating assets and liabilities, net of effects of acquisitions | $ 515 | $ 47 | $ (391) |
Estimates (Schedule Of Non-Cash
Estimates (Schedule Of Non-Cash Investing And Financing Activities) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
NON-CASH INVESTING ACTIVITIES: [Abstract] | ||||
Accrued capital expenditures | $ 464 | $ 604 | $ 1,334 | |
Units issued in connection with the Enable Acquisition(1) | [1] | 3,509 | 0 | 0 |
Lease assets obtained in exchange for new lease liabilities | 18 | 42 | 68 | |
Acquisition of interest in unconsolidated affiliate | 49 | 0 | 0 | |
SUPPLEMENTAL CASH FLOW INFORMATION; [Abstract] | ||||
Cash paid for interest, net of interest capitalized | 2,188 | 2,092 | 1,932 | |
Cash paid for income taxes (net of refunds) | $ 41 | $ (64) | $ 31 | |
[1] | See Note 3 for additional information. |
Estimates (Schedule of Inventor
Estimates (Schedule of Inventory) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Inventory, Net [Abstract] | ||
Natural gas, NGLs and refined products | $ 1,259 | $ 1,013 |
Crude oil | 328 | 287 |
Spare parts and other | 427 | 439 |
Total inventories | $ 2,014 | $ 1,739 |
Estimates (Other Current Assets
Estimates (Other Current Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Other Information [Abstract] | ||
Deposits paid to vendors | $ 215 | $ 75 |
Prepaid expenses and other | 222 | 138 |
Total other current assets | $ 437 | $ 213 |
Estimates (Property, Plant and
Estimates (Property, Plant and Equipment) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Property, Plant and Equipment, Net [Abstract] | ||
Property, plant and equipment, gross | $ 103,991 | $ 94,115 |
Less - Accumulated depreciation | (22,384) | (19,008) |
Property, plant and equipment, net | 81,607 | 75,107 |
Land and improvements | ||
Property, Plant and Equipment, Net [Abstract] | ||
Property, plant and equipment, gross | 1,369 | 1,233 |
Buildings and improvements (1 to 45 years) | ||
Property, Plant and Equipment, Net [Abstract] | ||
Property, plant and equipment, gross | 4,598 | 4,236 |
Pipelines and equipment (5 to 83 years) | ||
Property, Plant and Equipment, Net [Abstract] | ||
Property, plant and equipment, gross | 77,112 | 69,120 |
Product storage and related facilities (2 to 83 years) | ||
Property, Plant and Equipment, Net [Abstract] | ||
Property, plant and equipment, gross | 7,410 | 6,393 |
Right of way (20 to 83 years) | ||
Property, Plant and Equipment, Net [Abstract] | ||
Property, plant and equipment, gross | 5,021 | 5,099 |
Other (1 to 48 years) | ||
Property, Plant and Equipment, Net [Abstract] | ||
Property, plant and equipment, gross | 2,816 | 2,263 |
Construction work-in-process | ||
Property, Plant and Equipment, Net [Abstract] | ||
Property, plant and equipment, gross | $ 5,665 | $ 5,771 |
Estimates (Schedule Of Property
Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Accounting Policies [Abstract] | |||
Depreciation, depletion and amortization expense | $ 3,465 | $ 3,275 | $ 2,839 |
Capitalized interest | $ 135 | $ 189 | $ 166 |
Estimates (Schedule of Other No
Estimates (Schedule of Other Non-Current Assets, net) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Accounting Policies [Abstract] | ||
Crude pipeline linefill and tank bottoms | $ 498 | $ 517 |
Regulatory assets | 42 | 41 |
Pension assets | 140 | 103 |
Deferred charges | 177 | 188 |
Restricted funds | 164 | 179 |
Other | 624 | 629 |
Total other non-current assets, net | $ 1,645 | $ 1,657 |
Estimates (Components Of Intang
Estimates (Components Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Gross Carrying Amount | $ 8,422 | $ 7,953 |
Accumulated Amortization | (2,566) | (2,207) |
Customer relationships, contracts and agreements (3 to 46 years) | ||
Gross Carrying Amount | 7,982 | 7,513 |
Accumulated Amortization | (2,464) | (2,117) |
Patents (10 years) | ||
Gross Carrying Amount | 48 | 48 |
Accumulated Amortization | (44) | (40) |
Trade names (20 years) | ||
Gross Carrying Amount | 66 | 66 |
Accumulated Amortization | (38) | (35) |
Other (5 to 20 years) | ||
Gross Carrying Amount | 19 | 19 |
Accumulated Amortization | (20) | (15) |
Total Amortizable Intangible Assets [Member] | ||
Gross Carrying Amount | 8,115 | 7,646 |
Accumulated Amortization | (2,566) | (2,207) |
Trademarks [Member] | ||
Gross Carrying Amount | 295 | 295 |
Accumulated Amortization | 0 | 0 |
Other | ||
Gross Carrying Amount | 12 | 12 |
Accumulated Amortization | 0 | 0 |
Non-amortizable intangible assets [Member] | ||
Gross Carrying Amount | 307 | 307 |
Accumulated Amortization | $ 0 | $ 0 |
Estimates, Significant Accoun_5
Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details) | 12 Months Ended |
Dec. 31, 2021 | |
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years) | |
Intangible assets, useful life, minimum (years) | 3 years |
Minimum [Member] | Other (5 to 20 years) | |
Intangible assets, useful life, minimum (years) | 5 years |
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years) | |
Intangible assets, useful life, minimum (years) | 46 years |
Maximum [Member] | Patents (10 years) | |
Intangible assets, useful life, minimum (years) | 20 years |
Maximum [Member] | Trade names (20 years) | |
Intangible assets, useful life, minimum (years) | 10 years |
Maximum [Member] | Other (5 to 20 years) | |
Intangible assets, useful life, minimum (years) | 20 years |
Buildings and improvements [Member] | Minimum [Member] | |
Property, plant and equipment, useful life, minimum (years) | 1 year |
Buildings and improvements [Member] | Maximum [Member] | |
Property, plant and equipment, useful life, minimum (years) | 45 years |
Pipelines And Equipment [Member] | Minimum [Member] | |
Property, plant and equipment, useful life, minimum (years) | 5 years |
Pipelines And Equipment [Member] | Maximum [Member] | |
Property, plant and equipment, useful life, minimum (years) | 83 years |
Product storage and related facilities (2 to 83 years) | Minimum [Member] | |
Property, plant and equipment, useful life, minimum (years) | 2 years |
Product storage and related facilities (2 to 83 years) | Maximum [Member] | |
Property, plant and equipment, useful life, minimum (years) | 83 years |
Right of way (20 to 83 years) | Minimum [Member] | |
Property, plant and equipment, useful life, minimum (years) | 20 years |
Right of way (20 to 83 years) | Maximum [Member] | |
Property, plant and equipment, useful life, minimum (years) | 83 years |
Other (1 to 48 years) | Minimum [Member] | |
Property, plant and equipment, useful life, minimum (years) | 1 year |
Other (1 to 48 years) | Maximum [Member] | |
Property, plant and equipment, useful life, minimum (years) | 48 years |
Estimates (Aggregate Amortizati
Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Accounting Policies [Abstract] | |||
Reported in depreciation and amortization | $ 352 | $ 403 | $ 308 |
Estimates (Estimated Aggregate
Estimates (Estimated Aggregate Amortization Expense) (Details) $ in Millions | Dec. 31, 2021USD ($) |
Goodwill and Intangible Assets Disclosure [Abstract] | |
2022 | $ 379 |
2023 | 362 |
2024 | 348 |
2025 | 335 |
2026 | $ 331 |
Estimates (Schedule Of Goodwill
Estimates (Schedule Of Goodwill) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2020 | Sep. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | |
Goodwill [Roll Forward] | |||||||
Goodwill | $ 5,167 | $ 2,391 | $ 5,167 | ||||
Goodwill | 142 | 9 | |||||
Goodwill | $ 2,391 | $ 5,167 | 2,533 | 2,391 | |||
Goodwill impairment | (9) | $ (12) | (2,815) | ||||
Goodwill, Other Changes | 30 | ||||||
Intrastate Transportation and Storage | |||||||
Goodwill [Roll Forward] | |||||||
Goodwill | 10 | 0 | 10 | ||||
Goodwill | 0 | 0 | |||||
Goodwill | 0 | 10 | 0 | 0 | |||
Goodwill impairment | (10) | (10) | |||||
Goodwill, Other Changes | 0 | ||||||
Interstate Transportation and Storage | |||||||
Goodwill [Roll Forward] | |||||||
Goodwill | 226 | 0 | 226 | ||||
Goodwill | 0 | 0 | |||||
Goodwill | 0 | 226 | 0 | 0 | |||
Goodwill impairment | $ (43) | (183) | (226) | ||||
Goodwill, Other Changes | 0 | ||||||
Midstream | |||||||
Goodwill [Roll Forward] | |||||||
Goodwill | 483 | 0 | 483 | ||||
Goodwill | 0 | 0 | |||||
Goodwill | 0 | 483 | 0 | 0 | |||
Goodwill impairment | (483) | (483) | |||||
Goodwill, Other Changes | 0 | ||||||
NGL and Refined Products Transportation and Services | |||||||
Goodwill [Roll Forward] | |||||||
Goodwill | 693 | 693 | 693 | ||||
Goodwill | 0 | 0 | |||||
Goodwill | 693 | 693 | 693 | 693 | |||
Goodwill impairment | 0 | ||||||
Goodwill, Other Changes | 0 | ||||||
Crude Oil Transportation and Services | |||||||
Goodwill [Roll Forward] | |||||||
Goodwill | 1,397 | 52 | 1,397 | ||||
Goodwill | 138 | 0 | |||||
Goodwill | 52 | 1,397 | 190 | 52 | |||
Goodwill impairment | (1,280) | (1,279) | |||||
Goodwill, Other Changes | (66) | ||||||
Investment in Sunoco LP | |||||||
Goodwill [Roll Forward] | |||||||
Goodwill | 1,555 | 1,564 | 1,555 | ||||
Goodwill | 4 | 9 | |||||
Goodwill | 1,564 | 1,555 | 1,568 | 1,564 | |||
Goodwill impairment | 0 | ||||||
Goodwill, Other Changes | 0 | ||||||
Investment in USAC | |||||||
Goodwill [Roll Forward] | |||||||
Goodwill | 619 | 0 | 619 | ||||
Goodwill | 0 | 0 | |||||
Goodwill | 0 | 619 | 0 | 0 | |||
Goodwill impairment | (619) | (619) | |||||
Goodwill, Other Changes | 0 | ||||||
All Other | |||||||
Goodwill [Roll Forward] | |||||||
Goodwill | 184 | 82 | 184 | ||||
Goodwill | 0 | 0 | |||||
Goodwill | 82 | $ 184 | $ 82 | 82 | |||
Goodwill impairment | $ (15) | $ (132) | $ (40) | (198) | |||
Goodwill, Other Changes | $ 96 |
Estimates (Accrued And Other Cu
Estimates (Accrued And Other Current Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Other Information [Abstract] | ||
Interest payable | $ 561 | $ 600 |
Customer advances and deposits | 188 | 161 |
Accrued capital expenditures | 461 | 604 |
Accrued wages and benefits | 297 | 109 |
Taxes payable other than income taxes | 384 | 446 |
Exchanges payable | 155 | 127 |
Deferred Revenue | 158 | 112 |
Other | 867 | 616 |
Accrued and other current liabilities | $ 3,071 | $ 2,775 |
Estimates (Fair Value Of Financ
Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Commodity derivatives: | $ 272 | $ 168 |
Other Assets, Fair Value Disclosure | 39 | 34 |
Total assets | 311 | 202 |
Interest rate derivatives | (387) | (448) |
Commodity derivatives: | (211) | (269) |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (598) | (717) |
Level 1 [Member] | ||
Commodity derivatives: | 248 | 158 |
Other Assets, Fair Value Disclosure | 26 | 22 |
Total assets | 274 | 180 |
Interest rate derivatives | 0 | 0 |
Commodity derivatives: | (190) | (265) |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (190) | (265) |
Level 2 [Member] | ||
Commodity derivatives: | 24 | 10 |
Other Assets, Fair Value Disclosure | 13 | 12 |
Total assets | 37 | 22 |
Interest rate derivatives | (387) | (448) |
Commodity derivatives: | (21) | (4) |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (408) | (452) |
Commodity Derivatives - Power [Member] | Options - Calls [Member] | ||
Commodity derivatives: | 1 | |
Commodity Derivatives - Power [Member] | Forwards Swaps [Member] | ||
Commodity derivatives: | 17 | 4 |
Commodity derivatives: | (15) | |
Commodity Derivatives - Power [Member] | Future [Member] | ||
Commodity derivatives: | 6 | 2 |
Commodity derivatives: | (4) | (3) |
Commodity Derivatives - Power [Member] | Level 1 [Member] | Options - Calls [Member] | ||
Commodity derivatives: | 1 | |
Commodity Derivatives - Power [Member] | Level 1 [Member] | Forwards Swaps [Member] | ||
Commodity derivatives: | 0 | 0 |
Commodity derivatives: | 0 | |
Commodity Derivatives - Power [Member] | Level 1 [Member] | Future [Member] | ||
Commodity derivatives: | 6 | 2 |
Commodity derivatives: | (4) | (3) |
Commodity Derivatives - Power [Member] | Level 2 [Member] | Options - Calls [Member] | ||
Commodity derivatives: | 0 | |
Commodity Derivatives - Power [Member] | Level 2 [Member] | Forwards Swaps [Member] | ||
Commodity derivatives: | 17 | 4 |
Commodity derivatives: | (15) | |
Commodity Derivatives - Power [Member] | Level 2 [Member] | Future [Member] | ||
Commodity derivatives: | 0 | 0 |
Commodity derivatives: | 0 | 0 |
Commodity Derivatives - Refined Products [Member] | Future [Member] | ||
Commodity derivatives: | 3 | 3 |
Commodity derivatives: | (18) | (11) |
Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Future [Member] | ||
Commodity derivatives: | 3 | 3 |
Commodity derivatives: | (18) | (11) |
Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Future [Member] | ||
Commodity derivatives: | 0 | 0 |
Commodity derivatives: | 0 | 0 |
Commodity Derivatives - Crude [Member] | Forwards Swaps [Member] | ||
Commodity derivatives: | 16 | |
Commodity derivatives: | (3) | |
Commodity Derivatives - Crude [Member] | Level 1 [Member] | Forwards Swaps [Member] | ||
Commodity derivatives: | 16 | |
Commodity derivatives: | (3) | |
Commodity Derivatives - Crude [Member] | Level 2 [Member] | Forwards Swaps [Member] | ||
Commodity derivatives: | 0 | |
Commodity derivatives: | 0 | |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member] | ||
Commodity derivatives: | 7 | 12 |
Commodity derivatives: | (10) | (11) |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | ||
Commodity derivatives: | 38 | 1 |
Commodity derivatives: | (6) | (3) |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | ||
Commodity derivatives: | 26 | 13 |
Commodity derivatives: | (9) | (13) |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Contracts [Member] | ||
Commodity derivatives: | (6) | (1) |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | ||
Commodity derivatives: | 7 | 5 |
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Basis Swaps IFERC NYMEX [Member] | ||
Commodity derivatives: | 7 | 12 |
Commodity derivatives: | (10) | (11) |
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Swing Swaps IFERC [Member] | ||
Commodity derivatives: | 38 | 0 |
Commodity derivatives: | (6) | 0 |
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member] | ||
Commodity derivatives: | 26 | 13 |
Commodity derivatives: | (9) | (13) |
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Contracts [Member] | ||
Commodity derivatives: | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Swaps [Member] | ||
Commodity derivatives: | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Basis Swaps IFERC NYMEX [Member] | ||
Commodity derivatives: | 0 | 0 |
Commodity derivatives: | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Swing Swaps IFERC [Member] | ||
Commodity derivatives: | 0 | 1 |
Commodity derivatives: | 0 | (3) |
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member] | ||
Commodity derivatives: | 0 | 0 |
Commodity derivatives: | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Forward Physical Contracts [Member] | ||
Commodity derivatives: | (6) | (1) |
Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Forward Physical Swaps [Member] | ||
Commodity derivatives: | 7 | 5 |
Commodity Derivatives - NGLs [Member] | Forwards Swaps [Member] | ||
Commodity derivatives: | 152 | 127 |
Commodity derivatives: | (140) | (227) |
Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Forwards Swaps [Member] | ||
Commodity derivatives: | 152 | 127 |
Commodity derivatives: | (140) | (227) |
Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Forwards Swaps [Member] | ||
Commodity derivatives: | 0 | 0 |
Commodity derivatives: | $ 0 | $ 0 |
Acquisitions and Related Tran_3
Acquisitions and Related Transactions Acquisitions (Current Transactions) (Details) - USD ($) $ in Millions | Dec. 02, 2021 | Dec. 05, 2019 | Feb. 28, 2021 | Dec. 31, 2021 | Dec. 31, 2019 | Dec. 31, 2021 | Dec. 31, 2020 |
Business Acquisition [Line Items] | |||||||
Preferred Units, Issued | 72,184,780 | 72,184,780 | 0 | ||||
Long-term Debt, Fair Value | $ 54,970 | $ 54,970 | $ 56,210 | ||||
Goodwill | $ 142 | $ 9 | |||||
Enable | |||||||
Business Acquisition [Line Items] | |||||||
Senior Notes | $ 3,180 | ||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 0.8595 | ||||||
Total consideration | 3,458 | $ 10 | |||||
Long-term Debt, Fair Value | 3,430 | ||||||
Goodwill | $ 138 | $ 138 | |||||
Enable | Series G Preferred Units [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Preferred Units, Issued | 384,780 | ||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 0.0265 | ||||||
Enable | Enable 2019 Term Loan Agreement | |||||||
Business Acquisition [Line Items] | |||||||
Line of Credit Facility, Current Borrowing Capacity | $ 800 | ||||||
Enable | Enable Five-Year Revolving Credit Facility | |||||||
Business Acquisition [Line Items] | |||||||
Line of Credit Facility, Current Borrowing Capacity | $ 35 | ||||||
SemGroup [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Goodwill | $ 295 | $ 265 |
Acquisitions and Related Tran_4
Acquisitions and Related Transactions Acquisitions (PreviousTransactions) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Dec. 31, 2020 | Dec. 05, 2019 | ||
Business Acquisition [Line Items] | ||||||
Goodwill impairment | $ 9 | $ 12 | $ 2,815 | |||
SemGroup [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Goodwill impairment | 244 | |||||
Other Asset Impairment Charges | $ 129 | |||||
Senior Notes | 1,375 | |||||
SemGroup Subsidiary | ||||||
Business Acquisition [Line Items] | ||||||
Senior Notes | $ 593 | |||||
SemGroup [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Long-term debt, less current maturities(1) | [1] | $ 2,576 | ||||
SemGroup [Member] | Common Class A | ||||||
Business Acquisition [Line Items] | ||||||
Common Stock, No Par Value | $ 0.01 | $ 0.01 | ||||
Distribution Made to Limited Partner, Unit Distribution, Dilution Per Unit | 6.80 | |||||
SemGroup [Member] | ET Common Units | ||||||
Business Acquisition [Line Items] | ||||||
Business Acquisition, Share Price | $ 0.7275 | $ 0.7275 | ||||
Preferred Units, Liquidation Spread, Percent | 101.00% | 101.00% | ||||
[1] | Long-term debt at December 5, 2019 includes SemGroup senior notes with an aggregate principal amount of $1.375Â billion and SemGroup subsidiary debt of $593Â million, all of which was redeemed in December 2019, subsequent to the close of the SemGroup Transaction. |
Acquisitions (Schedule Of Asset
Acquisitions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition Table) (Details) - USD ($) $ in Millions | Dec. 02, 2021 | Dec. 05, 2019 | Feb. 28, 2021 | Dec. 31, 2021 | Dec. 31, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | |
Business Acquisition [Line Items] | ||||||||
Goodwill | $ 142 | $ 9 | ||||||
SemGroup [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Total current assets | $ 794 | |||||||
Property, plant and equipment, net | 3,891 | |||||||
Investments in unconsolidated affiliates | 617 | |||||||
Intangible assets, net | 460 | |||||||
Goodwill | 295 | $ 265 | ||||||
Total assets acquired | 6,057 | |||||||
Total current liabilities | 629 | |||||||
Long-term debt, less current maturities(1) | [1] | 2,576 | ||||||
Other non-current liabilities | 197 | |||||||
Energy Transfer Canada Preferred shares | 241 | |||||||
Noncontrolling interest | 822 | |||||||
Total liabilities assumed | 3,643 | |||||||
Total consideration | 1,592 | |||||||
Total consideration, net of cash received | $ 6,057 | |||||||
Enable | ||||||||
Business Acquisition [Line Items] | ||||||||
Total current assets | $ 593 | |||||||
Property, plant and equipment, net | 7,076 | |||||||
Intangible assets, net | 440 | |||||||
Goodwill | 138 | $ 138 | ||||||
Total consideration | 3,519 | |||||||
Total assets acquired | 8,326 | |||||||
Total current liabilities | 488 | |||||||
Long-term debt, less current maturities(1) | [2] | 4,267 | ||||||
Other non-current liabilities | 18 | |||||||
Total liabilities assumed | 4,773 | |||||||
Cash received | 61 | |||||||
Noncontrolling interests | 34 | |||||||
Other non-current assets | 39 | |||||||
Total consideration | 3,458 | $ 10 | ||||||
Enable | Investments in Unconsolidated Affiliates | ||||||||
Business Acquisition [Line Items] | ||||||||
Investments in unconsolidated affiliates | $ 40 | |||||||
[1] | Long-term debt at December 5, 2019 includes SemGroup senior notes with an aggregate principal amount of $1.375Â billion and SemGroup subsidiary debt of $593Â million, all of which was redeemed in December 2019, subsequent to the close of the SemGroup Transaction. | |||||||
[2] | Long-term debt at December 2, 2021 includes Enable senior notes with an aggregate principal amount of $3.18Â billion in senior notes and a fair value of $3.43Â billion. It also includes $800Â million outstanding on the Enable 2019 Term Loan Agreement and $35Â million outstanding on the Enable Five-Year Revolving Credit Facility, both of which were repaid and terminated in December 2021, immediately subsequent to the close of the Enable Acquisition. |
Advances to and Investments i_3
Advances to and Investments in Unconsolidated Affiliates Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
Impairment of investment in unconsolidated affiliates | $ 0 | $ 129 | $ 0 | |
Impairment losses | 21 | 2,880 | 74 | |
Investments in unconsolidated affiliates | 2,947 | 3,060 | 3,460 | |
Equity in earnings of unconsolidated affiliates | 246 | 119 | 302 | |
FEP [Member] | ||||
Impairment losses | 208 | |||
Investments in unconsolidated affiliates | 0 | 4 | ||
Equity in earnings of unconsolidated affiliates | [1] | 0 | (139) | 59 |
White Cliffs | ||||
Impairment of investment in unconsolidated affiliates | 129 | |||
Investments in unconsolidated affiliates | 245 | 274 | ||
Equity in earnings of unconsolidated affiliates | $ 0 | $ 20 | $ 4 | |
Citrus [Member] | ||||
Interest ownership | 50.00% | |||
FGT [Member] | ||||
Interest ownership | 100.00% | |||
FEP [Member] | ||||
Interest ownership | 50.00% | |||
Midcontinent Express Pipeline, LLC [Member] | ||||
Interest ownership | 50.00% | |||
White Cliffs | ||||
Interest ownership | 51.00% | |||
[1] | For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million. |
Advances to and Investments i_4
Advances to and Investments in Unconsolidated Affiliates Investment in Affiliates (Carrying Values) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
Equity in earnings of unconsolidated affiliates | $ 246 | $ 119 | $ 302 | |
Investments in unconsolidated affiliates | 2,947 | 3,060 | 3,460 | |
Citrus [Member] | ||||
Equity in earnings of unconsolidated affiliates | 157 | 162 | 148 | |
Investments in unconsolidated affiliates | 1,792 | 1,867 | ||
FEP [Member] | ||||
Equity in earnings of unconsolidated affiliates | [1] | 0 | (139) | 59 |
Investments in unconsolidated affiliates | 0 | 4 | ||
MEP [Member] | ||||
Equity in earnings of unconsolidated affiliates | (17) | (6) | 15 | |
Investments in unconsolidated affiliates | 378 | 406 | ||
Other Affiliates [Member] | ||||
Equity in earnings of unconsolidated affiliates | 106 | 82 | 76 | |
White Cliffs | ||||
Equity in earnings of unconsolidated affiliates | 0 | 20 | $ 4 | |
Investments in unconsolidated affiliates | 245 | 274 | ||
Other | ||||
Investments in unconsolidated affiliates | $ 532 | $ 509 | ||
[1] | For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million. |
Investments in Affiliates (Summ
Investments in Affiliates (Summarized Balance Sheet Information) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Investment In Affiliates [Abstract] | ||||
Assets, Current | $ 10,537 | $ 6,317 | ||
Other non-current assets, net | 1,645 | 1,657 | ||
Assets | 105,963 | 95,144 | $ 98,973 | |
Current Liabilities | 10,835 | 5,923 | ||
Equity | 39,345 | 31,388 | 33,938 | $ 31,017 |
Liabilities and Equity | 105,963 | 95,144 | ||
Assets, Current | 10,537 | 6,317 | ||
Other non-current assets, net | 1,645 | 1,657 | ||
Assets | 105,963 | 95,144 | 98,973 | |
Current Liabilities | 10,835 | 5,923 | ||
Equity | 39,345 | 31,388 | $ 33,938 | $ 31,017 |
Liabilities and Equity | 105,963 | 95,144 | ||
Equity Method Investments [Member] | ||||
Investment In Affiliates [Abstract] | ||||
Assets, Current | 242 | 227 | ||
Property, plant and equipment, net | 7,239 | 7,339 | ||
Other non-current assets, net | 77 | 58 | ||
Assets | 7,558 | 7,624 | ||
Current Liabilities | 500 | 600 | ||
Non-current liabilities | 3,602 | 3,298 | ||
Equity | 3,456 | 3,726 | ||
Liabilities and Equity | 7,558 | 7,624 | ||
Assets, Current | 242 | 227 | ||
Property, plant and equipment, net | 7,239 | 7,339 | ||
Other non-current assets, net | 77 | 58 | ||
Assets | 7,558 | 7,624 | ||
Current Liabilities | 500 | 600 | ||
Non-current liabilities | 3,602 | 3,298 | ||
Equity | 3,456 | 3,726 | ||
Liabilities and Equity | $ 7,558 | $ 7,624 |
Investments in Affiliates (Su_2
Investments in Affiliates (Summarized Income Statement Information) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
Schedule of Equity Method Investments [Line Items] | ||||
Revenues | $ 67,417 | $ 38,954 | $ 54,213 | |
Net income | 6,687 | 140 | 4,825 | |
Equity in earnings of unconsolidated affiliates | 246 | 119 | 302 | |
Equity Method Investments [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Revenues | 1,003 | 1,243 | 1,192 | |
Equity Method Investments Summarized Financial Information, Operating Income | 459 | 6 | 683 | |
Net income | 282 | (199) | 443 | |
Citrus [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity in earnings of unconsolidated affiliates | 157 | 162 | 148 | |
FEP [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity in earnings of unconsolidated affiliates | [1] | 0 | (139) | 59 |
MEP [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity in earnings of unconsolidated affiliates | (17) | (6) | 15 | |
Other Affiliates [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity in earnings of unconsolidated affiliates | 106 | 82 | 76 | |
White Cliffs | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity in earnings of unconsolidated affiliates | $ 0 | $ 20 | $ 4 | |
[1] | For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million. |
Net Income Per Limited Partne_3
Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Earnings Per Share [Abstract] | |||
NET INCOME | $ 6,687 | $ 140 | $ 4,825 |
Less: Net income attributable to redeemable noncontrolling interests | 50 | 49 | 51 |
NET INCOME ATTRIBUTABLE TO PARTNERS | 5,470 | (648) | 3,518 |
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units | (2) | 0 | (1) |
Diluted income (loss) available to Limited Partners | $ 5,177 | $ (647) | $ 3,513 |
Weighted average limited partner units | 2,734.4 | 2,695.6 | 2,628 |
Basic | $ 1.89 | $ (0.24) | $ 1.34 |
Dilutive effect of unconverted unit awards and ET Series A Convertible Preferred Units | 5.1 | 0 | 9.6 |
Weighted average limited partner units, assuming dilutive effect of unvested unit awards | 2,739.5 | 2,695.6 | 2,637.6 |
Diluted | $ 1.89 | $ (0.24) | $ 1.33 |
Limited Partners’ interest in net income | $ 5,179 | $ (647) | $ 3,514 |
Debt Obligations Debt Obligat_2
Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
Debt Instrument [Line Items] | ||||
Other Long-term Debt | $ 3 | $ 3 | ||
Long-term Debt | 49,702 | 51,438 | ||
Current maturities of long-term debt | 680 | 21 | ||
Long-term debt, less current maturities | 49,022 | 51,417 | ||
Five Year Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Long-term Line of Credit | 2,940 | |||
Bakken Project [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Unamortized Discount (Premium), Net | (2) | (3) | ||
Deferred Finance Costs, Noncurrent, Net | (9) | (13) | ||
Long-term Debt | 2,489 | 2,484 | ||
Bakken Project [Member] | 3.625% Senior Notes due 2022 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 650 | 650 | ||
Long-term Debt, Description | 3.625% Senior Notes due April 1, 2022 | |||
Bakken Project [Member] | 3.90% Senior Notes due 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Long-term Debt, Description | 3.90% Senior Notes due April 1, 2024 | |||
Bakken Project [Member] | 4.625% Senior Notes due 2029 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 850 | 850 | ||
Long-term Debt, Description | 4.625% Senior Notes due April 1, 2029 | |||
Sunoco LP [Member] | ||||
Debt Instrument [Line Items] | ||||
Capital Lease Obligations | $ 100 | 103 | ||
Deferred Finance Costs, Noncurrent, Net | (26) | (27) | ||
Long-term Debt | 3,255 | 3,112 | ||
Sunoco LP [Member] | 6.00% Senior Notes due April 15, 2027 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 600 | 600 | ||
Long-term Debt, Description | 6.00% Senior Notes Due April 15, 2027 | |||
Sunoco LP [Member] | Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Line of Credit | $ 581 | 0 | ||
Long-term Debt, Description | Sunoco LP $1.50 billion Revolving Credit Facility due July 2023 | |||
Sunoco LP [Member] | 5.875% senior notes due 2028 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 400 | 400 | ||
Long-term Debt, Description | 5.875% Senior Notes Due March 15, 2028 | |||
Sunoco LP [Member] | 4.875% senior notes due 2023 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 0 | 436 | ||
Long-term Debt, Description | 4.875% Senior Notes Due January 15, 2023 | |||
Sunoco LP [Member] | 5.500% senior notes due 2026 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 0 | 800 | ||
Long-term Debt, Description | 5.50% Senior Notes Due February 15, 2026 | |||
Sunoco LP [Member] | 4.50% Senior Notes due May 15, 2029 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 800 | 800 | ||
Long-term Debt, Description | 4.50% Senior Notes due May 15, 2029 | |||
Sunoco LP [Member] | 4.50% Senior Notes due April 30, 2030 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 800 | 0 | ||
Long-term Debt, Description | 4.50% Senior Notes due April 30, 2030 | |||
Transwestern [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt | $ 400 | 400 | ||
Transwestern [Member] | 5.89% Senior Unsecured Notes, due May 24, 2022 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | [1] | $ 150 | 150 | |
Long-term Debt, Description | [1] | 5.89% Senior Notes due May 24, 2022(2) | ||
Transwestern [Member] | 5.66% Senior Unsecured Notes, due December 9, 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 175 | 175 | ||
Long-term Debt, Description | 5.66% Senior Notes due December 9, 2024 | |||
Transwestern [Member] | 6.16% Senior Unsecured Notes, due May 24, 2037 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 75 | 75 | ||
Long-term Debt, Description | 6.16% Senior Notes due May 24, 2037 | |||
Panhandle [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Unamortized Discount (Premium), Net | $ 8 | 10 | ||
Long-term Debt | 243 | 245 | ||
Panhandle [Member] | 7.60% Senior Notes, due February 1, 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 82 | 82 | ||
Long-term Debt, Description | 7.60% Senior Notes due February 1, 2024 | |||
Panhandle [Member] | 8.25% Senior Notes, due November 14, 2029 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 33 | 33 | ||
Long-term Debt, Description | 8.25% Senior Notes due November 15, 2029 | |||
Panhandle [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member] | ||||
Debt Instrument [Line Items] | ||||
Junior Subordinated Notes | $ 54 | 54 | ||
Long-term Debt, Description | Floating Rate Junior Subordinated Notes due November 1, 2066 | |||
Panhandle [Member] | 7.00% Senior Notes, due July 15, 2029 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 66 | 66 | ||
Long-term Debt, Description | 7.00% Senior Notes due July 15, 2029 | |||
USA Compression Partners, LP [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Line of Credit | $ 516 | 474 | ||
Deferred Finance Costs, Noncurrent, Net | (18) | (22) | ||
Long-term Debt | $ 1,973 | 1,927 | ||
Long-term Debt, Description | USAC $1.60 billion Revolving Credit Facility due December 2026 | |||
USA Compression Partners, LP [Member] | 6.875% Senior notes due April 2026 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 725 | 725 | ||
Long-term Debt, Description | 6.875% Senior Notes due April 1, 2026 | |||
USA Compression Partners, LP [Member] | 6.875% Senior Notes due September 2027 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 750 | 750 | ||
Long-term Debt, Description | 6.875% Senior Notes due September 1, 2027 | |||
SemGroup [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Unamortized Discount (Premium), Net | $ (1) | (2) | ||
Long-term Debt | 224 | 223 | ||
Senior Notes | $ 1,375 | |||
SemGroup [Member] | HFOTCO Tax Exempt Notes due 2050 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 225 | 225 | ||
Long-term Debt, Description | HFOTCO Tax Exempt Notes due 2050 | |||
ET [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Unamortized Discount (Premium), Net | $ 233 | (17) | ||
Deferred Finance Costs, Noncurrent, Net | (186) | (215) | ||
Long-term Debt | 40,717 | 42,726 | ||
ET [Member] | 5.875% Senior Notes due January 15, 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,127 | 1,127 | ||
Long-term Debt, Description | 5.875% Senior Notes due January 15, 2024 | |||
ET [Member] | 5.5% Senior Notes due June 1, 2027 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 956 | 956 | ||
Long-term Debt, Description | 5.50% Senior Notes due June 1, 2027 | |||
ET [Member] | 4.25% Senior Notes due March 15, 2023 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 995 | 995 | ||
Long-term Debt, Description | 4.25% Senior Notes due March 15, 2023 | |||
ET [Member] | 7.60% Senior Notes, due February 1, 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 277 | 277 | ||
Long-term Debt, Description | 7.60% Senior Notes due February 1, 2024 | |||
ET [Member] | 4.05% Senior Notes due March 2025 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Long-term Debt, Description | 4.05% Senior Notes due March 15, 2025 | |||
ET [Member] | 4.75% Senior Notes due January 2026 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Long-term Debt, Description | 4.75% Senior Notes due January 15, 2026 | |||
ET [Member] | 8.25% Senior Notes, due November 14, 2029 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 267 | 267 | ||
Long-term Debt, Description | 8.25% Senior Notes due November 15, 2029 | |||
ET [Member] | 4.90% Senior Notes due March 2035 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 500 | 500 | ||
Long-term Debt, Description | 4.90% Senior Notes due March 15, 2035 | |||
ET [Member] | 6.625% Senior Notes, due October 15, 2036 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 400 | 400 | ||
Long-term Debt, Description | 6.625% Senior Notes due October 15, 2036 | |||
ET [Member] | 5.80% Senior Notes due 2038 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 500 | 500 | ||
Long-term Debt, Description | 5.80% Senior Notes due June 15, 2038 | |||
ET [Member] | 7.5% Senior Notes, due July 1, 2038 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 550 | 550 | ||
Long-term Debt, Description | 7.50% Senior Notes due July 1, 2038 | |||
ET [Member] | Senior Notes 6.05% Due June 1, 2041 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 700 | 700 | ||
Long-term Debt, Description | 6.05% Senior Notes due June 1, 2041 | |||
ET [Member] | Senior Notes 6.50% Due February 1, 2042 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Long-term Debt, Description | 6.50% Senior Notes due February 1, 2042 | |||
ET [Member] | 5.15% Senior Notes due February 1, 2043 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 450 | 450 | ||
Long-term Debt, Description | 5.15% Senior Notes due February 1, 2043 | |||
ET [Member] | 5.95% Senior Notes due October 1, 2043 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 450 | 450 | ||
Long-term Debt, Description | 5.95% Senior Notes due October 1, 2043 | |||
ET [Member] | 5.15% Senior Notes due March 2045 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Long-term Debt, Description | 5.15% Senior Notes due March 15, 2045 | |||
ET [Member] | 6.125% Senior Notes due December 2045 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Long-term Debt, Description | 6.125% Senior Notes due December 15, 2045 | |||
ET [Member] | 5.30% Senior Notes due April 2047 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 900 | 900 | ||
Long-term Debt, Description | 5.30% Senior Notes due April 15, 2047 | |||
ET [Member] | 5.40% Senior Notes due October 1, 2047 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,500 | 1,500 | ||
Long-term Debt, Description | 5.40% Senior Notes due October 1, 2047 | |||
ET [Member] | 6.0% Senior Notes due 2048 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Long-term Debt, Description | 6.00% Senior Notes due June 15, 2048 | |||
ET [Member] | 6.25% Senior Notes due 2049 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,750 | 1,750 | ||
Long-term Debt, Description | 6.25% Senior Notes due April 15, 2049 | |||
ET [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member] | ||||
Debt Instrument [Line Items] | ||||
Junior Subordinated Notes | $ 546 | 546 | ||
ET [Member] | ETO Term Loan [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Line of Credit | 0 | 2,000 | ||
ET [Member] | 9.00% Debentures, due 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Subordinated Debt | $ 65 | 65 | ||
Long-term Debt, Description | 9.00% Debentures due November 1, 2024 | |||
ET [Member] | Senior Note 4.65% Due February 15, 2022 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 300 | 300 | ||
Long-term Debt, Description | 4.65% Senior Notes due February 15, 2022(2) | |||
ET [Member] | 3.45% Senior Notes due January 2023 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 350 | 350 | ||
Long-term Debt, Description | 3.45% Senior Notes due January 15, 2023 | |||
ET [Member] | 6.85% Senior Notes, due February 15, 2040 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 250 | 250 | ||
Long-term Debt, Description | 6.85% Senior Notes due February 15, 2040 | |||
ET [Member] | 4.25% Senior Notes due April 1, 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 500 | 500 | ||
Long-term Debt, Description | 4.25% Senior Notes due April 1, 2024 | |||
ET [Member] | 4.5% Senior Notes due 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 750 | 750 | ||
Long-term Debt, Description | 4.50% Senior Notes due April 15, 2024 | |||
ET [Member] | 5.95% Senior Notes due December 2025 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 400 | 400 | ||
Long-term Debt, Description | 5.95% Senior Notes due December 1, 2025 | |||
ET [Member] | 3.90% Senior Notes due July 15, 2026 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 550 | 550 | ||
Long-term Debt, Description | 3.90% Senior Notes due July 15, 2026 | |||
ET [Member] | 4.20% Senior Notes due April 2027 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 600 | 600 | ||
Long-term Debt, Description | 4.20% Senior Notes due April 15, 2027 | |||
ET [Member] | 4.00% Senior Notes due October 1, 2027 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 750 | 750 | ||
Long-term Debt, Description | 4.00% Senior Notes due October 1, 2027 | |||
ET [Member] | 4.95% Senior Notes due 2028 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Long-term Debt, Description | 4.95% Senior Notes due June 15, 2028 | |||
ET [Member] | 5.25% Senior Notes due 2029 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,500 | 1,500 | ||
Long-term Debt, Description | 5.25% Senior Notes due April 15, 2029 | |||
ET [Member] | Senior Note 6.10%, due February 15, 2042 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 300 | 300 | ||
Long-term Debt, Description | 6.10% Senior Notes due February 15, 2042 | |||
ET [Member] | 5.30% Senior Notes due April 1, 2044 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 700 | 700 | ||
Long-term Debt, Description | 5.30% Senior Notes due April 1, 2044 | |||
ET [Member] | 5.35% Senior Notes due May 15, 2045 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 800 | 800 | ||
Long-term Debt, Description | 5.35% Senior Notes due May 15, 2045 | |||
ET [Member] | 4.95% Senior Notes due January 2043 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 350 | 350 | ||
Long-term Debt, Description | 4.95% Senior Notes due January 15, 2043 | |||
ET [Member] | 5.875% Senior Notes due April 1, 2022 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 0 | 900 | ||
Long-term Debt, Description | 5.875% Senior Notes due March 1, 2022(1) | |||
ET [Member] | 4.5% Senior Notes due November 1, 2023 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 600 | 600 | ||
Long-term Debt, Description | 4.50% Senior Notes due November 1, 2023 | |||
ET [Member] | 4.9% Senior Notes due February 1, 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 350 | 350 | ||
Long-term Debt, Description | 4.90% Senior Notes due February 1, 2024 | |||
ET [Member] | Senior Notes 4.65% Due June 1, 2021 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | [2] | $ 0 | 800 | |
Long-term Debt, Description | [2] | 4.65% Senior Notes due June 1, 2021(1) | ||
ET [Member] | Senior Notes 5.20% Due February 1, 2022 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 0 | 1,000 | ||
Long-term Debt, Description | 5.20% Senior Notes due February 1, 2022(1) | |||
ET [Member] | 5.0% Senior Notes due October 1, 2022 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | [1] | $ 700 | 700 | |
Long-term Debt, Description | [1] | 5.00% Senior Notes due October 1, 2022(2) | ||
ET [Member] | 3.6% Senior Notes due February 1, 2023 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 800 | 800 | ||
Long-term Debt, Description | 3.60% Senior Notes due February 1, 2023 | |||
ET [Member] | 4.20% Senior Notes due 2023 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 500 | 500 | ||
Long-term Debt, Description | 4.20% Senior Notes due September 15, 2023 | |||
ET [Member] | 4.40% Senior Notes due April 2021 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | [2] | $ 0 | 600 | |
Long-term Debt, Description | [2] | 4.40% Senior Notes due April 1, 2021(1) | ||
ET [Member] | 2.9% Senior Notes due May 15, 2025 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,000 | 1,000 | ||
Long-term Debt, Description | 2.90% Senior Notes due May 15, 2025 | |||
ET [Member] | 3.75 Senior Notes due May 15, 2030 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 1,500 | 1,500 | ||
Long-term Debt, Description | 3.75% Senior Note due May 15, 2030 | |||
ET [Member] | 5.00% Senior Notes due May 15, 2050 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 2,000 | 2,000 | ||
Long-term Debt, Description | 5.00% Senior Notes due May 15, 2050 | |||
ET [Member] | Five Year Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Long-term Line of Credit | $ 2,937 | 3,103 | ||
ET [Member] | 5.00% Senior Notes due May 15, 2044 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | [3] | $ 531 | 0 | |
Long-term Debt, Description | [3] | 5.00% Senior Notes due May 15, 2044(3) | ||
ET [Member] | 3.90% Senior Notes due May 15, 2024 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 600 | 0 | ||
Long-term Debt, Description | 3.90% Senior Notes due May 15, 2024(3) | |||
ET [Member] | 4.40% Senior Notes due March 15, 2027 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 700 | 0 | ||
Long-term Debt, Description | 4.40% Senior Notes due March 15, 2027(3) | |||
ET [Member] | 4.95% Senior Notes due May 15, 2028 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | [3] | $ 800 | 0 | |
Long-term Debt, Description | [3] | 4.95% Senior Notes due May 15, 2028(3) | ||
ET [Member] | 4.15% Senior Notes due September 15, 2029 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | [3] | $ 547 | 0 | |
Long-term Debt, Description | [3] | 4.15% Senior Notes due September 15, 2029(3) | ||
ET [Member] | 4.25% Senior Notes due March 15, 2023 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 5 | 5 | ||
Long-term Debt, Description | 4.25% Senior Notes due March 15, 2023 | |||
ET [Member] | 5.875% Senior Notes due January 15, 2024 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 23 | 23 | ||
Long-term Debt, Description | 5.875% Senior Notes due January 15, 2024 | |||
ET [Member] | 5.5% Senior Notes due June 1, 2027 | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $ 44 | 44 | ||
Long-term Debt, Description | 5.50% Senior Notes due June 1, 2027 | |||
Energy Transfer Canada | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt | $ 398 | 318 | ||
Energy Transfer Canada | Energy Transfer Canada Revolver | ||||
Debt Instrument [Line Items] | ||||
Long-term Line of Credit | $ 7 | 57 | ||
Long-term Debt, Description | Energy Transfer Canada Revolving Credit Facility | |||
Energy Transfer Canada | Energy Transfer Canada Term Loan | ||||
Debt Instrument [Line Items] | ||||
Long-term Line of Credit | $ 249 | 261 | ||
Long-term Debt, Description | Energy Transfer Canada Term Loan A | |||
Energy Transfer Canada | Energy Transfer Canada KAPS Facility | ||||
Debt Instrument [Line Items] | ||||
Long-term Line of Credit | $ 142 | $ 0 | ||
Long-term Debt, Description | Energy Transfer Canada KAPS Facility | |||
[1] | As of December 31, 2021, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The $300 million principal amount of 4.65% Senior Notes were redeemed in February 2022 using proceeds from Energy Transfer’s Five-Year Credit Facility. | |||
[2] | These notes were redeemed in 2021. | |||
[3] | These notes were assumed by Energy Transfer in connection with the Enable Acquisition. |
Debt Obligations Debt Obligat_3
Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) $ in Millions | Dec. 31, 2021USD ($) |
Debt Obligations [Abstract] | |
2022 | $ 1,827 |
2023 | 3,859 |
2024 | 8,250 |
2025 | 2,407 |
2026 | 2,799 |
Thereafter | 30,561 |
Long-term Debt | $ 49,703 |
Debt Obligations (Debt Narrativ
Debt Obligations (Debt Narrative) (Details) $ in Millions, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2021USD ($) | Dec. 31, 2021CAD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | ||
Long-term Debt | $ 49,702 | $ 51,438 | |||
Unamortized Discounts, Premiums, Fair Value Adjustments and Deferred Debt Issuance Costs | $ (1) | ||||
USAC Credit Facility, due 2023 [Member] | |||||
Debt Instrument, Covenant Description | The credit facility is also subject to the following financial covenants, including covenants requiring USAC to maintain: •a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter, with EBITDA and interest expense annualized for the fiscal quarter most recently ended; •a ratio of total secured indebtedness to EBITDA not greater than 3.0 to 1.0 or less than 0.0 to 1.0, determined as of the last day of each fiscal quarter, with EBITDA annualized for the fiscal quarter most recently ended; and•a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter with EBITDA annualized for the fiscal quarter most recently ended, (i) 5.75 to 1 through the second fiscal quarter of 2022, (ii) 5.5 to 1 from the third quarter of 2022 through the third quarter of 2023, and (iii) 5.25 to 1 thereafter. In addition, USAC may increase the applicable ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum ratio exceed 5.5 to 1.0 for any fiscal quarter as a result of such increase. | ||||
Five Year Credit Facility | |||||
Line of Credit Facility, Current Borrowing Capacity | $ 5,000 | ||||
Letters of Credit Outstanding, Amount | 33 | ||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 2,030 | ||||
Line of Credit Facility, Interest Rate at Period End | 1.13% | 1.13% | |||
Outstanding borrowings | $ 2,940 | ||||
Long-term Commercial Paper, Noncurrent | $ 1,190 | ||||
Sunoco LP Credit Facility | |||||
Debt Instrument, Covenant Description | Sunoco LP’s Credit Facility requires Sunoco LP to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in certain specified acquisitions of not less than $50 million (as permitted under Sunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility also requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the Sunoco LP’s Credit Facility agreement) of not less than 2.25 to 1. | ||||
ET [Member] | |||||
Long-term Debt | $ 40,717 | 42,726 | |||
ET [Member] | ETO Term Loan [Member] | |||||
Outstanding borrowings | 0 | 2,000 | |||
ET [Member] | 4.25% Senior Notes due March 15, 2023 [Member] | |||||
Senior Notes | 995 | 995 | |||
ET [Member] | 5.5% Senior Notes due June 1, 2027 [Member] | |||||
Senior Notes | 956 | 956 | |||
ET [Member] | 5.35% Senior Notes due May 15, 2045 [Member] | |||||
Senior Notes | 800 | 800 | |||
ET [Member] | 3.26% Junior Subordinated Notes due November 1, 2066 [Member] | |||||
Junior Subordinated Notes | 546 | 546 | |||
ET [Member] | 4.25% Senior Notes due April 1, 2024 [Member] | |||||
Senior Notes | 500 | 500 | |||
ET [Member] | 5.875% Senior Notes due April 1, 2022 [Member] | |||||
Senior Notes | 0 | 900 | |||
ET [Member] | 5.875% Senior Notes due January 15, 2024 [Member] | |||||
Senior Notes | 1,127 | 1,127 | |||
ET [Member] | 5.0% Senior Notes due October 1, 2022 [Member] | |||||
Senior Notes | [1] | 700 | 700 | ||
ET [Member] | 4.40% Senior Notes due April 2021 [Member] | |||||
Senior Notes | [2] | 0 | 600 | ||
ET [Member] | 3.90% Senior Notes due July 15, 2026 [Member] | |||||
Senior Notes | 550 | 550 | |||
ET [Member] | 4.5% Senior Notes due 2024 [Member] | |||||
Senior Notes | 750 | 750 | |||
ET [Member] | 6.25% Senior Notes due 2049 [Member] | |||||
Senior Notes | 1,750 | 1,750 | |||
ET [Member] | 5.25% Senior Notes due 2029 [Member] | |||||
Senior Notes | 1,500 | 1,500 | |||
ET [Member] | 4.20% Senior Notes due 2023 [Member] | |||||
Senior Notes | 500 | 500 | |||
ET [Member] | 4.95% Senior Notes due 2028 [Member] | |||||
Senior Notes | 1,000 | 1,000 | |||
ET [Member] | 5.80% Senior Notes due 2038 [Member] | |||||
Senior Notes | 500 | 500 | |||
ET [Member] | 6.0% Senior Notes due 2048 [Member] | |||||
Senior Notes | 1,000 | 1,000 | |||
ET [Member] | Five Year Credit Facility | |||||
Outstanding borrowings | $ 2,937 | 3,103 | |||
Leverage Ratio Maximum | 5 | ||||
Maximum Leverage Ratio Permitted | 5.5 | ||||
Supplementary Leverage Ratio | 3.07 | 3.07 | |||
ET [Member] | Minimum [Member] | Five Year Credit Facility | |||||
Line of Credit Facility, Commitment Fee Percentage | 0.125% | ||||
ET [Member] | Maximum [Member] | Five Year Credit Facility | |||||
Line of Credit Facility, Commitment Fee Percentage | 0.30% | ||||
USA Compression Partners, LP [Member] | |||||
Long-term Debt | $ 1,973 | 1,927 | |||
Outstanding borrowings | 516 | 474 | |||
USA Compression Partners, LP [Member] | 6.875% Senior notes due April 2026 [Member] | |||||
Senior Notes | 725 | 725 | |||
USAC [Member] | USAC Credit Facility, due 2023 [Member] | |||||
Line of Credit Facility, Current Borrowing Capacity | 1,100 | ||||
Letters of Credit Outstanding, Amount | 0 | ||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 262 | ||||
Line of Credit Facility, Interest Rate at Period End | 2.68% | 2.68% | |||
Outstanding borrowings | $ 516 | ||||
Line of Credit Facility, Maximum Borrowing Capacity | 1,600 | ||||
Panhandle [Member] | |||||
Long-term Debt | 243 | 245 | |||
Panhandle [Member] | 3.26% Junior Subordinated Notes due November 1, 2066 [Member] | |||||
Junior Subordinated Notes | 54 | 54 | |||
Bakken Project [Member] | |||||
Long-term Debt | 2,489 | 2,484 | |||
Bakken Project [Member] | 3.625% Senior Notes due 2022 [Member] | |||||
Senior Notes | 650 | 650 | |||
Bakken Project [Member] | 3.90% Senior Notes due 2024 [Member] | |||||
Senior Notes | 1,000 | 1,000 | |||
Bakken Project [Member] | 4.625% Senior Notes due 2029 [Member] | |||||
Senior Notes | 850 | 850 | |||
Sunoco LP [Member] | |||||
Long-term Debt | 3,255 | $ 3,112 | |||
Senior Notes Tendered, Percentage | 56.00% | ||||
Sunoco LP [Member] | 4.875% senior notes due 2023 [Member] | |||||
Senior Notes | 0 | $ 436 | |||
Sunoco LP [Member] | 5.500% senior notes due 2026 [Member] | |||||
Senior Notes | 0 | 800 | |||
Sunoco LP [Member] | 5.875% senior notes due 2028 [Member] | |||||
Senior Notes | 400 | 400 | |||
Sunoco LP [Member] | Sunoco LP $1.5 billion Revolving Credit Facility due July 2023 [Member] | |||||
Line of Credit Facility, Current Borrowing Capacity | 1,500 | ||||
Letters of Credit Outstanding, Amount | 6 | ||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 913 | ||||
Line of Credit Facility, Interest Rate at Period End | 2.10% | 2.10% | |||
Outstanding borrowings | $ 581 | 0 | |||
Sunoco LP [Member] | 4.50% Senior Notes due 2030 | |||||
Senior Notes | $ 800 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 4.50% | 4.50% | |||
Energy Transfer Canada | |||||
Long-term Debt | $ 398 | 318 | |||
Line of Credit Facility, Maximum Borrowing Capacity | 197 | ||||
Energy Transfer Canada | Energy Transfer Canada Term Loan A | |||||
Line of Credit Facility, Maximum Borrowing Capacity | 276 | ||||
Energy Transfer Canada | Energy Transfer Canada Revolving Credit Facility | |||||
Line of Credit Facility, Maximum Borrowing Capacity | 414 | ||||
Energy Transfer Canada | Energy Transfer Canada KAPS Facility | |||||
Outstanding borrowings | 142 | 0 | |||
Long-term Construction Loan | 237 | ||||
Energy Transfer Canada | Energy Transfer Canada Revolver | |||||
Outstanding borrowings | 7 | 57 | |||
Energy Transfer Canada | Energy Transfer Canada Term Loan | |||||
Outstanding borrowings | 249 | 261 | |||
4.5% Senior Notes due 2029 | |||||
Senior Notes | $ 800 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 4.50% | ||||
4.875% senior notes due 2023 [Member] | |||||
Senior Notes | $ 1,000 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 4.875% | ||||
SemGroup [Member] | |||||
Senior Notes | $ 1,375 | ||||
Long-term Debt | 224 | $ 223 | |||
Accordion feature [Member] | Five Year Credit Facility | |||||
Line of Credit Facility, Current Borrowing Capacity | 6,000 | ||||
Accordion feature [Member] | USAC [Member] | USAC Credit Facility, due 2023 [Member] | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 200 | ||||
Eurodollar [Member] | ET [Member] | Minimum [Member] | Five Year Credit Facility | |||||
Debt Instrument, Basis Spread on Variable Rate | 1.125% | ||||
Eurodollar [Member] | ET [Member] | Maximum [Member] | Five Year Credit Facility | |||||
Debt Instrument, Basis Spread on Variable Rate | 2.00% | ||||
Base Rate | ET [Member] | Minimum [Member] | Five Year Credit Facility | |||||
Debt Instrument, Basis Spread on Variable Rate | 0.125% | ||||
Base Rate | ET [Member] | Maximum [Member] | Five Year Credit Facility | |||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||
Canada, Dollars | Energy Transfer Canada | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 250 | ||||
Canada, Dollars | Energy Transfer Canada | Energy Transfer Canada Term Loan A | |||||
Line of Credit Facility, Maximum Borrowing Capacity | 350 | ||||
Canada, Dollars | Energy Transfer Canada | Energy Transfer Canada Revolving Credit Facility | |||||
Line of Credit Facility, Maximum Borrowing Capacity | 525 | ||||
Canada, Dollars | Energy Transfer Canada | Energy Transfer Canada KAPS Facility | |||||
Long-term Construction Loan | $ 300 | ||||
Canada, Dollars | SemGroup [Member] | Energy Transfer Canada KAPS Facility | |||||
Outstanding borrowings | $ 179 | ||||
Canada, Dollars | SemGroup [Member] | Energy Transfer Canada Revolver | |||||
Outstanding borrowings | 9 | ||||
Canada, Dollars | SemGroup [Member] | Energy Transfer Canada Term Loan | |||||
Outstanding borrowings | $ 315 | ||||
[1] | As of December 31, 2021, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The $300 million principal amount of 4.65% Senior Notes were redeemed in February 2022 using proceeds from Energy Transfer’s Five-Year Credit Facility. | ||||
[2] | These notes were redeemed in 2021. |
Debt Obligations Debt Obligat_4
Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2021 | |
USAC Credit Facility, due 2023 [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Covenant Description | The credit facility is also subject to the following financial covenants, including covenants requiring USAC to maintain: •a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter, with EBITDA and interest expense annualized for the fiscal quarter most recently ended; •a ratio of total secured indebtedness to EBITDA not greater than 3.0 to 1.0 or less than 0.0 to 1.0, determined as of the last day of each fiscal quarter, with EBITDA annualized for the fiscal quarter most recently ended; and•a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter with EBITDA annualized for the fiscal quarter most recently ended, (i) 5.75 to 1 through the second fiscal quarter of 2022, (ii) 5.5 to 1 from the third quarter of 2022 through the third quarter of 2023, and (iii) 5.25 to 1 thereafter. In addition, USAC may increase the applicable ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum ratio exceed 5.5 to 1.0 for any fiscal quarter as a result of such increase. |
Redeemable Preferred Units (Det
Redeemable Preferred Units (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | |||
Apr. 30, 2018 | Dec. 31, 2021 | Jan. 31, 2021 | Dec. 31, 2020 | Apr. 02, 2018 | |
Redeemable noncontrolling interests | $ 783 | $ 762 | |||
Preferred Units, Issued | 72,184,780 | 0 | |||
Preferred Stock, Redemption Price Per Share | $ 868 | ||||
USAC [Member] | |||||
Redeemable noncontrolling interests | $ 477 | ||||
SemCAMS [Member] | |||||
Redeemable noncontrolling interests | $ 291 | ||||
Preferred Stock, Shares Outstanding | 300,000 | ||||
Energy Transfer Canada | |||||
Dividends, Preferred Stock, Cash | $ 6 | ||||
ET [Member] | |||||
Redeemable noncontrolling interests | $ 15 | ||||
Preferred Units [Member] | USAC [Member] | |||||
Preferred Units, Issued | 500,000 | ||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ 24.375 | ||||
Preferred Units [Member] | SemCAMS [Member] | |||||
Preferred Units, Issued | 367,521 | ||||
Canada, Dollars | |||||
Preferred Stock, Redemption Price Per Share | $ 1,100 | ||||
Canada, Dollars | Energy Transfer Canada | |||||
Dividends, Preferred Stock, Cash | $ 8 |
Equity (Narrative) (Details)
Equity (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions | Jan. 01, 2020 | Jul. 31, 2019 | Apr. 30, 2019 | Oct. 31, 2018 | Jul. 31, 2018 | Apr. 30, 2018 | Nov. 30, 2017 | Dec. 31, 2021 | Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Jan. 31, 2020 | Apr. 02, 2018 | ||
Issuance of Common Units (2) | [1] | 9,700,000 | 12,800,000 | 14,500,000 | |||||||||||||||||||||||
Stock Repurchase Program, Authorized Amount | $ 2,000 | $ 2,000 | |||||||||||||||||||||||||
Stock Repurchase Program, Remaining Authorized Repurchase Amount | $ 880 | $ 880 | |||||||||||||||||||||||||
Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding | 20.00% | 20.00% | |||||||||||||||||||||||||
Limited Partners' Capital Account, Units Outstanding | 3,082,497,494 | 2,702,352,154 | 2,689,600,000 | 2,619,400,000 | 3,082,497,494 | 2,702,352,154 | 2,689,600,000 | ||||||||||||||||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ 33 | ||||||||||||||||||||||||||
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan | 17,000,000 | 17,000,000 | |||||||||||||||||||||||||
Preferred Units, Issued | 72,184,780 | 0 | 72,184,780 | 0 | |||||||||||||||||||||||
Partners' Capital Account, Units, Treasury Units Purchased | 4,200,000 | 0 | 1,900,000 | ||||||||||||||||||||||||
Incentive Distribution Rights | 0.00% | 0.00% | |||||||||||||||||||||||||
Series A Preferred Units [Member] | |||||||||||||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | [2] | $ 31.25 | $ 0 | [3] | $ 31.25 | $ 0 | |||||||||||||||||||||
Units issued for cash | 0 | ||||||||||||||||||||||||||
Preferred Stock, Shares Outstanding | 950,000 | 950,000 | |||||||||||||||||||||||||
Series C Preferred Units [Member] | |||||||||||||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.4609 | 0.4609 | [3] | 0.4609 | 0.4609 | ||||||||||||||||||||||
Units issued for cash | 0 | ||||||||||||||||||||||||||
Preferred Stock, Shares Outstanding | 18,000,000 | 18,000,000 | |||||||||||||||||||||||||
Series D Preferred Units [Member] | |||||||||||||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.4766 | 0.4766 | [3] | 0.4766 | 0.4766 | ||||||||||||||||||||||
Units issued for cash | 0 | ||||||||||||||||||||||||||
Preferred Stock, Shares Outstanding | 17,800,000 | 17,800,000 | |||||||||||||||||||||||||
Series E Preferred Units [Member] | |||||||||||||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.4750 | 0.4750 | [3] | 0.4750 | 0.4750 | ||||||||||||||||||||||
Units issued for cash | 0 | ||||||||||||||||||||||||||
Preferred Stock, Shares Outstanding | 32,000,000 | 32,000,000 | |||||||||||||||||||||||||
Series F Preferred Units [Member] | |||||||||||||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | [2] | $ 0 | 33.7500 | [3] | 0 | 33.7500 | |||||||||||||||||||||
Units issued for cash | 0 | ||||||||||||||||||||||||||
Preferred Stock, Shares Outstanding | 500,000 | 500,000 | |||||||||||||||||||||||||
Series G Preferred Units [Member] | |||||||||||||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | [2] | $ 0 | 35.63 | [3] | 0 | 35.63 | |||||||||||||||||||||
Units issued for cash | 0 | ||||||||||||||||||||||||||
Preferred Stock, Shares Outstanding | 1,484,780 | 1,484,780 | |||||||||||||||||||||||||
Series B Preferred Units [Member] | |||||||||||||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | [2] | $ 33.13 | 0 | [3] | 33.13 | 0 | |||||||||||||||||||||
Units issued for cash | 0 | ||||||||||||||||||||||||||
Preferred Stock, Shares Outstanding | 550,000 | 550,000 | |||||||||||||||||||||||||
Series H Preferred Units | |||||||||||||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | [2] | $ 0 | 27.08 | [3] | 0 | 0 | |||||||||||||||||||||
Units issued for cash | 889,000,000 | ||||||||||||||||||||||||||
Preferred Stock, Shares Outstanding | 900,000 | 900,000 | |||||||||||||||||||||||||
ET [Member] | |||||||||||||||||||||||||||
Limited Partner interest in the Partnership, percentage | 99.90% | ||||||||||||||||||||||||||
Sunoco LP [Member] | |||||||||||||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.8255 | 0.8255 | 0.8255 | 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | ||||||||||||||
USAC [Member] | |||||||||||||||||||||||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 46,100,000 | 46,100,000 | |||||||||||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.5250 | $ 0.5250 | $ 0.5250 | $ 0.5250 | $ 0.5250 | $ 0.5250 | $ 0.5250 | $ 0.5250 | $ 0.5250 | $ 0.5250 | $ 0.5250 | $ 0.5250 | $ 0.5250 | ||||||||||||||
Limited Partners' Capital Account, Units Outstanding | 97,300,000 | 97,300,000 | |||||||||||||||||||||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ 1.8 | $ 1.9 | |||||||||||||||||||||||||
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 118,399 | 188,695 | |||||||||||||||||||||||||
Series A Preferred Units [Member] | |||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 6.25% | ||||||||||||||||||||||||||
Shares Issued, Price Per Share | $ 1,000 | ||||||||||||||||||||||||||
Preferred Units, Liquidation Spread, Percent | 4.028% | ||||||||||||||||||||||||||
Series C Preferred Units [Member] | |||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 7.375% | ||||||||||||||||||||||||||
Shares Issued, Price Per Share | $ 25 | ||||||||||||||||||||||||||
Preferred Units, Liquidation Spread, Percent | 4.53% | ||||||||||||||||||||||||||
Series B Preferred Units [Member] | |||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 6.625% | ||||||||||||||||||||||||||
Shares Issued, Price Per Share | $ 1,000 | ||||||||||||||||||||||||||
Preferred Units, Liquidation Spread, Percent | 4.155% | ||||||||||||||||||||||||||
Series D Preferred Units [Member] | |||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 7.625% | ||||||||||||||||||||||||||
Shares Issued, Price Per Share | $ 25 | $ 25 | |||||||||||||||||||||||||
Preferred Units, Liquidation Spread, Percent | 4.738% | ||||||||||||||||||||||||||
Series E Preferred Units [Member] | |||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 7.60% | ||||||||||||||||||||||||||
Shares Issued, Price Per Share | $ 25 | ||||||||||||||||||||||||||
Preferred Units, Liquidation Spread, Percent | 5.161% | ||||||||||||||||||||||||||
Series F Preferred Units [Member] | |||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 6.75% | ||||||||||||||||||||||||||
Shares Issued, Price Per Share | $ 1,000 | ||||||||||||||||||||||||||
Preferred Units, Liquidation Spread, Percent | 5.134% | ||||||||||||||||||||||||||
Series G Preferred Units [Member] | |||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 7.125% | ||||||||||||||||||||||||||
Shares Issued, Price Per Share | $ 1,000 | ||||||||||||||||||||||||||
Preferred Units, Liquidation Spread, Percent | 5.306% | ||||||||||||||||||||||||||
Class B Preferred Units [Member] | USAC [Member] | |||||||||||||||||||||||||||
Partners' Capital Account, Units, Converted | 6,397,965 | ||||||||||||||||||||||||||
Series H Preferred Units | |||||||||||||||||||||||||||
Preferred Stock, Dividend Rate, Percentage | 6.50% | ||||||||||||||||||||||||||
Shares Issued, Price Per Share | $ 1,000 | ||||||||||||||||||||||||||
Preferred Units, Liquidation Spread, Percent | 5.694% | ||||||||||||||||||||||||||
USAC [Member] | |||||||||||||||||||||||||||
Stock Issued During Period, Shares, Conversion of Units | 6,397,965 | ||||||||||||||||||||||||||
ETE Class A Units [Member] | ETE Merger [Member] | |||||||||||||||||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 763,021,449 | ||||||||||||||||||||||||||
Strike price of $17.03 [Member] | USAC [Member] | |||||||||||||||||||||||||||
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | 5,000,000 | ||||||||||||||||||||||||||
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ 17.03 | ||||||||||||||||||||||||||
Strike price of $19.59 [Member] | USAC [Member] | |||||||||||||||||||||||||||
Class of Warrant or Right, Number of Securities Called by Warrants or Rights | 10,000,000 | ||||||||||||||||||||||||||
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ 19.59 | ||||||||||||||||||||||||||
Equity Distribution Program [Member] | Sunoco LP [Member] | |||||||||||||||||||||||||||
Equity Distribution Agreements, Value of Units Available to be Issued | $ 295 | $ 295 | |||||||||||||||||||||||||
Units issued for cash | 0 | ||||||||||||||||||||||||||
[1] | Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings. | ||||||||||||||||||||||||||
[2] | (1) Series A, Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis. | ||||||||||||||||||||||||||
[3] | * Represents prorated initial distribution. |
Equity (Change In ETE Common Un
Equity (Change In ETE Common Units) (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | ||
Issuance of Common Units (2) | [1] | 9,700,000 | 12,800,000 | 14,500,000 | |
Outstanding | 3,082,497,494 | 2,702,352,154 | 2,689,600,000 | 2,619,400,000 | |
Issuance of restricted Common Units under long-term incentive plans | [2] | (374,600,000) | 0 | (57,600,000) | |
Common Units repurchased | (4,200,000) | 0 | (1,900,000) | ||
Number of Common Units, end of period | 3,082,497,494 | 2,702,352,154 | 2,689,600,000 | ||
Equity | $ 39,345 | $ 31,388 | $ 33,938 | $ 31,017 | |
Distributions to partners | (1,898) | (2,802) | (3,054) | ||
Units issued in connection with the Enable Acquisition(1) | [3] | 3,509 | 0 | $ 0 | |
Series A Preferred Units [Member] | |||||
Equity | 958 | 0 | |||
Preferred units conversion | $ 943 | ||||
Units issued for cash | 0 | ||||
Distributions to partners | $ (30) | ||||
Units issued in connection with the Enable Acquisition(1) | 0 | ||||
Other, net | 0 | ||||
Net income | 45 | ||||
Series B Preferred Units [Member] | |||||
Equity | 556 | 0 | |||
Preferred units conversion | $ 547 | ||||
Units issued for cash | 0 | ||||
Distributions to partners | $ (18) | ||||
Units issued in connection with the Enable Acquisition(1) | 0 | ||||
Other, net | 0 | ||||
Net income | 27 | ||||
Series C Preferred Units [Member] | |||||
Equity | 440 | 0 | |||
Preferred units conversion | $ 440 | ||||
Units issued for cash | 0 | ||||
Distributions to partners | $ (25) | ||||
Units issued in connection with the Enable Acquisition(1) | 0 | ||||
Other, net | 0 | ||||
Net income | 25 | ||||
Series D Preferred Units [Member] | |||||
Equity | 434 | 0 | |||
Preferred units conversion | $ 434 | ||||
Units issued for cash | 0 | ||||
Distributions to partners | $ (25) | ||||
Units issued in connection with the Enable Acquisition(1) | 0 | ||||
Other, net | 0 | ||||
Net income | 25 | ||||
Series E Preferred Units [Member] | |||||
Equity | 786 | 0 | |||
Preferred units conversion | $ 786 | ||||
Units issued for cash | 0 | ||||
Distributions to partners | $ (45) | ||||
Units issued in connection with the Enable Acquisition(1) | 0 | ||||
Other, net | 0 | ||||
Net income | 45 | ||||
Series F Preferred Units [Member] | |||||
Equity | 496 | 0 | |||
Preferred units conversion | $ 504 | ||||
Units issued for cash | 0 | ||||
Distributions to partners | $ (34) | ||||
Units issued in connection with the Enable Acquisition(1) | 0 | ||||
Other, net | 0 | ||||
Net income | 26 | ||||
Series G Preferred Units [Member] | |||||
Equity | 1,488 | 0 | |||
Preferred units conversion | $ 1,114 | ||||
Units issued for cash | 0 | ||||
Distributions to partners | $ (79) | ||||
Units issued in connection with the Enable Acquisition(1) | 392 | ||||
Other, net | 0 | ||||
Net income | 61 | ||||
Series H Preferred Units | |||||
Equity | 893 | 0 | |||
Preferred units conversion | $ 0 | ||||
Units issued for cash | 889,000,000 | ||||
Distributions to partners | $ (24) | ||||
Units issued in connection with the Enable Acquisition(1) | 0 | ||||
Other, net | (3) | ||||
Net income | 31 | ||||
Preferred Units [Member] | |||||
Equity | 6,051 | $ 0 | |||
Preferred units conversion | $ 4,768 | ||||
Units issued for cash | 889,000,000 | ||||
Distributions to partners | $ (280) | ||||
Units issued in connection with the Enable Acquisition(1) | 392 | ||||
Other, net | (3) | ||||
Net income | $ 285 | ||||
[1] | Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings. | ||||
[2] | In December 2019, Energy Transfer issued 57.6Â million Energy Transfer Common Units in connection with the SemGroup acquisition. In December 2021, Energy Transfer issued 374.6 million Energy Transfer Common Units in connection with the Enable Acquisition. | ||||
[3] | See Note 3 for additional information. |
Equity (Quarterly Distributions
Equity (Quarterly Distributions Of Available Cash) (Details) - $ / shares | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2021 | Sep. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2021 | |||
Parent Company [Member] | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.1750 | $ 0.1525 | $ 0.1525 | $ 0.1525 | $ 0.1525 | $ 0.1525 | $ 0.3050 | $ 0.3050 | $ 0.3050 | $ 0.3050 | $ 0.3050 | $ 0.3050 | $ 0.3050 | |||
USAC [Member] | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | 0.5250 | 0.5250 | 0.5250 | 0.5250 | 0.5250 | 0.5250 | 0.5250 | 0.5250 | 0.5250 | 0.5250 | 0.5250 | 0.5250 | 0.5250 | |||
Sunoco LP [Member] | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | 0.8255 | 0.8255 | 0.8255 | 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 | |||
Minimum Quarterly Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | $0.4375 | |||||||||||||||
First Target Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | $0.4375 to $0.503125 | |||||||||||||||
Second Target Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | $0.503125 to $0.546875 | |||||||||||||||
Third Target Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | $0.546875 to $0.656250 | |||||||||||||||
Thereafter [Member] | ||||||||||||||||
Distribution Payment Targets | Above $0.656250 | |||||||||||||||
Common Stock | Minimum Quarterly Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | 100% | |||||||||||||||
Common Stock | First Target Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | 100% | |||||||||||||||
Common Stock | Second Target Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | 85% | |||||||||||||||
Common Stock | Third Target Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | 75% | |||||||||||||||
Common Stock | Thereafter [Member] | ||||||||||||||||
Distribution Payment Targets | 50% | |||||||||||||||
IDRs [Member] | Minimum Quarterly Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | —% | |||||||||||||||
IDRs [Member] | First Target Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | —% | |||||||||||||||
IDRs [Member] | Second Target Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | 15% | |||||||||||||||
IDRs [Member] | Third Target Distribution [Member] | ||||||||||||||||
Distribution Payment Targets | 25% | |||||||||||||||
IDRs [Member] | Thereafter [Member] | ||||||||||||||||
Distribution Payment Targets | 50% | |||||||||||||||
Series A Preferred Units [Member] | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | [1] | 31.25 | 0 | [2] | 31.25 | 0 | ||||||||||
Series B Preferred Units [Member] | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | [1] | 33.13 | 0 | [2] | 33.13 | 0 | ||||||||||
Series C Preferred Units [Member] | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | 0.4609 | 0.4609 | [2] | 0.4609 | 0.4609 | |||||||||||
Series D Preferred Units [Member] | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | 0.4766 | 0.4766 | [2] | 0.4766 | 0.4766 | |||||||||||
Series E Preferred Units [Member] | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | 0.4750 | 0.4750 | [2] | 0.4750 | 0.4750 | |||||||||||
Series F Preferred Units [Member] | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | [1] | 0 | 33.7500 | [2] | 0 | 33.7500 | ||||||||||
Series G Preferred Units [Member] | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | [1] | 0 | 35.63 | [2] | 0 | 35.63 | ||||||||||
Series H Preferred Units | ||||||||||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | [1] | $ 0 | $ 27.08 | [2] | $ 0 | $ 0 | ||||||||||
[1] | (1) Series A, Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis. | |||||||||||||||
[2] | * Represents prorated initial distribution. |
Equity (Accumulated Other Compr
Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Partners' Capital Notes [Abstract] | ||
Available-for-sale securities | $ 19 | $ 18 |
Foreign currency translation adjustment | 13 | 7 |
Actuarial gain (loss) related to pensions and other postretirement benefits | 5 | (7) |
Investments in unconsolidated affiliates, net | (11) | (14) |
Total AOCI, net of tax | 26 | 4 |
Amounts attributable to noncontrolling interests | (3) | 2 |
Total AOCI included in partners’ capital, net of tax | $ 23 | $ 6 |
Equity Tax amounts in component
Equity Tax amounts in components of other comprehensive income (loss) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Statement of Comprehensive Income [Abstract] | ||
Available-for-sale securities | $ (1) | $ (1) |
Foreign currency translation adjustment | 6 | 8 |
Actuarial loss relating to pension and other postretirement benefits | 1 | 3 |
Other Comprehensive Income (Loss), Tax | $ 6 | $ 10 |
ETE Unit-Based Compensation Pla
ETE Unit-Based Compensation Plans (Details) - $ / shares shares in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Awards granted | 11.9 | |
Awards granted | $ 8.46 | |
Unvested awards | 36.1 | 29.4 |
Unvested awards | $ 9,490,000 | $ 11.26 |
Awards vested | (6.4) | |
Awards vested | $ 15.10 | |
Awards forfeited | (1.5) | |
Awards forfeited | $ 11.23 | |
Enable | ||
Awards granted | 2.7 | |
Awards granted | $ 8.32 |
Non-Cash Compensation Plans Sub
Non-Cash Compensation Plans Subsidiary Unit-Based Compensation Plans (Details) - $ / shares shares in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested awards | 36.1 | 29.4 | |
Unvested awards | $ 9,490,000 | $ 11.26 | |
Awards granted | 11.9 | ||
Awards granted | $ 8.46 | ||
Awards vested | (6.4) | ||
Awards vested | $ 15.10 | ||
Awards forfeited | 1.5 | ||
Awards forfeited | $ 11.23 | ||
Sunoco LP Unit Based Compensation Plans [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested awards | 2 | 2.1 | |
Unvested awards | $ 30.92 | $ 28.63 | |
Awards granted | 0.5 | ||
Awards granted | $ 37.72 | $ 28.63 | $ 30.70 |
Awards vested | (0.5) | ||
Awards vested | $ 27.06 | ||
Awards forfeited | 0.1 | ||
Awards forfeited | $ 28.57 | ||
USAC Unit Based Compensation Plans [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested awards | 2.2 | 2.1 | |
Unvested awards | $ 13.57 | $ 14.88 | |
Awards granted | 0.6 | ||
Awards granted | $ 14.92 | $ 12.55 | $ 15.88 |
Awards vested | (0.4) | ||
Awards vested | $ 15.13 | ||
Awards forfeited | 0.1 | ||
Awards forfeited | $ 14.50 |
Non-Cash Compensation Plans U_2
Non-Cash Compensation Plans Unit-based compensation Narrative (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Awards granted | $ 8.46 | ||
Unvested awards | 36.1 | 29.4 | |
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term | 3 years 4 months 24 days | ||
Awards granted | 11.9 | ||
ETE Long-Term Incentive Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 12.7 | ||
ET Unit Based Compensation Plans [Member] | |||
Awards granted | $ 6.29 | $ 12.51 | |
Fair Value Of Units As Of The Vesting Date | $ 52 | $ 51 | $ 47 |
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount | $ 208 | ||
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term | 2 years 10 months 24 days | ||
Subsidiary Unit Based Compensation [Member] | |||
Fair Value Of Units As Of The Vesting Date | $ 24 | $ 16 | $ 17 |
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount | $ 56 | ||
ET Cash Restricted Unit Plan [Member] | |||
Unvested awards | 8.6 | ||
Awards granted | 3.9 | 7.7 | |
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent | $ 3.1 |
Income Taxes Narrative (Details
Income Taxes Narrative (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Operating Loss Carryforwards [Line Items] | |||
Deferred Tax Liabilities, Gross | $ 4,452,000,000 | $ 4,375,000,000 | |
Net operating losses and other carryforwards | 803,000,000 | 1,047,000,000 | |
Valuation allowance | (34,000,000) | (134,000,000) | |
State | 24,000,000 | 32,000,000 | $ (2,000,000) |
Deferred Income Tax Expense (Benefit) | 141,000,000 | $ 210,000,000 | $ 217,000,000 |
Tax Credit Carryforward, Valuation Allowance | 9,000,000 | ||
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 56,000,000 | ||
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, After Tax | 51,000,000 | ||
Unrecognized Tax Benefits, Interest on Income Taxes Expense | 7,000,000 | ||
Income Tax Examination, Penalties and Interest Accrued | 17,000,000 | ||
Corporate Subsidiaries [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Deferred Tax Asset, Interest Carryforward | 79,000,000 | ||
Deferred Tax Assets, Operating Loss Carryforwards, State and Local | 116,000,000 | ||
Sunoco LP [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Estimated Litigation Liability | 530,000,000 | ||
Sunoco Property Company LLC [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 114,000,000 | ||
Sunoco Retail LLC | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 0 | ||
ETP Holdco | |||
Operating Loss Carryforwards [Line Items] | |||
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration | 1,100,000,000 | ||
Operating Loss Carryforwards | 3,100,000,000 | ||
CANADA | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 6,000,000 | ||
PENNSYLVANIA | |||
Operating Loss Carryforwards [Line Items] | |||
State | 67,000,000 | ||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies | 34,000,000 | ||
Net of federal tax benefits | PENNSYLVANIA | |||
Operating Loss Carryforwards [Line Items] | |||
State | 53,000,000 | ||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies | 27,000,000 | ||
Limited NOL Carryforward | ETP Holdco | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 338,000,000 | ||
Canada, Dollars | Corporate Subsidiaries [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Tax Credit Carryforward, Valuation Allowance | $ 25,000,000 |
Income Taxes Components of Inco
Income Taxes Components of Income Tax (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Current expense (benefit): | |||
Federal | $ 19 | $ (6) | $ (20) |
State | 24 | 32 | (2) |
Current Foreign Tax Expense (Benefit) | 0 | 1 | 0 |
Total | 43 | 27 | (22) |
Deferred expense (benefit): | |||
Federal | 246 | 176 | 174 |
State | (106) | 41 | 43 |
Deferred Foreign Income Tax Expense (Benefit) | 1 | (7) | 0 |
Total | 141 | 210 | 217 |
Total income tax expense | $ 184 | $ 237 | $ 195 |
Income Taxes Reconciliation of
Income Taxes Reconciliation of Income Tax Satutory Rate (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Income tax expense at United States statutory rate | $ 1,443 | $ 79 | $ 1,054 |
Increase (reduction) in income taxes resulting from: | |||
Partnership earnings not subject to tax | (1,211) | 88 | (866) |
Noncontrolling interests | 0 | 16 | 0 |
State tax, net of federal tax benefit | 85 | 58 | 12 |
Statutory rate change | (46) | 0 | 0 |
Valuation allowance | (63) | 0 | 0 |
Uncertain tax positions | (34) | 0 | 0 |
Dividend received deduction | (4) | 0 | (3) |
Foreign taxes | 1 | (7) | 0 |
Other | 13 | 3 | (2) |
Income tax expense | $ 184 | $ 237 | $ 195 |
Income Taxes Effects of Tempora
Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Deferred income tax assets: | ||
Net operating losses and other carryforwards | $ 803 | $ 1,047 |
Pension and other postretirement benefits | 0 | 0 |
Other | 35 | 34 |
Deferred Tax Assets, Gross | 838 | 1,081 |
Valuation allowance | (34) | (134) |
Net deferred income tax assets | 804 | 947 |
Deferred income tax liabilities: | ||
Property, plant and equipment | (314) | (298) |
Investments in affiliates | (4,042) | (3,994) |
Trademarks | (79) | (77) |
Other | (17) | (6) |
Deferred Tax Liabilities, Gross | 4,452 | 4,375 |
Deferred Tax Liabilities | $ (3,648) | $ (3,428) |
Income Taxes Components of Net
Income Taxes Components of Net Deferred Tax Liability (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Components of Net Deferred Income Tax [Abstract] | ||
Total deferred income tax assets | $ 838 | $ 1,081 |
Deferred Tax Liabilities, Net | (3,648) | (3,428) |
Valuation allowance | 34 | 134 |
Net deferred income tax assets | $ 804 | $ 947 |
Income Taxes Changes in Unrecog
Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Changes in Unrecognized Tax Benefits [Abstract] | |||
Balance at beginning of year | $ 90 | $ 94 | $ 624 |
Additions attributable to tax positions taken in prior years | 0 | 0 | 11 |
Reduction attributable to tax positions taken in prior years | (34) | 0 | (541) |
Lapse of statute | 0 | 4 | 0 |
Balance at end of year | $ 56 | $ 90 | $ 94 |
Regulatory Matters, Commitmen_3
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Sep. 30, 2016USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) | Dec. 31, 2019USD ($) | |
Operating Leases, Rent Expense | $ 48,000,000 | $ 47,000,000 | $ 45,000,000 | ||
Payments for Environmental Liabilities | 28,000,000 | 29,000,000 | |||
Total environmental liabilities | $ 306,000,000 | $ 293,000,000 | 306,000,000 | ||
Site Contingency, Number of Sites Needing Remediation | 34 | ||||
Loss Contingency, Damages Awarded, Value | 74,800,000 | $ 80,700,000 | |||
Loss Contingency, Damages Sought, Value | $ 410,000,000 | ||||
Loss Contingency, Estimate of Possible Loss | $ 550,000,000 | ||||
Number of litigation cases | 5 | ||||
Rover Pipeline | |||||
Litigation Settlement, Amount Awarded to Other Party | $ 40,000,000 | ||||
Punitive Damages [Member] | |||||
Loss Contingency, Damages Awarded, Value | 75,000,000 | ||||
Related To Deductibles [Member] | |||||
Loss Contingency Accrual | $ 101,000,000 | $ 144,000,000 | $ 101,000,000 |
Regulatory Matters, Commitmen_4
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) $ in Millions | Dec. 31, 2021USD ($) | Dec. 31, 2020USD ($) |
Environmental Remediation Obligations [Abstract] | ||
Current | $ 46 | $ 44 |
Non-current | 247 | 262 |
Total environmental liabilities | $ 293 | $ 306 |
Site Contingency, Number of Sites Needing Remediation | 34 |
Revenue Narrative (Details)
Revenue Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Sunoco LP [Member] | |||
Capitalized Contract Cost, Amortization | $ 21 | $ 18 | $ 17 |
Revenue Contracts with customer
Revenue Contracts with customers (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Jan. 01, 2019 | |
Contract with Customer, Liability | $ 459 | $ 309 | $ 367 | |
Additions | 849 | 788 | ||
Revenue recognized | $ (699) | (846) | ||
Sunoco LP [Member] | ||||
Accounts receivable from contracts with customers | 256 | $ 463 | ||
Contract asset | $ 121 | $ 157 |
Revenue from Contract with Cust
Revenue from Contract with Customer - Performance Obligation (Details) $ in Millions | Dec. 31, 2021USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 38,756 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 6,189 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2022 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 5,594 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2023 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 2 years |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 4,775 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2024 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 3 years |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 22,198 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2025 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 4 years |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2026 |
Lease Accounting Narrative (Det
Lease Accounting Narrative (Details) | Dec. 31, 2021 |
Real estate leases | |
Lessee, Operating Lease, Term of Contract | 40 years |
Minimum [Member] | |
Lessee, Operating Lease, Renewal Term | 1 year |
Minimum [Member] | Terminal facilities, tank cars, office space, land and equipment | |
Lessee, Operating Lease, Term of Contract | 5 years |
Maximum [Member] | |
Lessee, Operating Lease, Renewal Term | 20 years |
Maximum [Member] | Terminal facilities, tank cars, office space, land and equipment | |
Lessee, Operating Lease, Term of Contract | 15 years |
Lease Accounting - Components o
Lease Accounting - Components of Leases on BS (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Lessee, Lease, Description [Line Items] | ||
Operating lease current liabilities | $ 47 | $ 53 |
Accrued and other current liabilities | 3,071 | 2,775 |
Non-current operating lease liabilities | 814 | 837 |
Property, plant and equipment, net | 81,607 | 75,107 |
Current maturities of long-term debt | 680 | 21 |
Long-term debt, less current maturities | 49,022 | 51,417 |
Other non-current liabilities | 1,323 | 1,152 |
Operating Leases [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Lease right-of-use assets, net | 826 | 863 |
Operating lease current liabilities | 47 | 53 |
Accrued and other current liabilities | 1 | 1 |
Non-current operating lease liabilities | 814 | 837 |
Finance Leases [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Accrued and other current liabilities | 1 | 1 |
Property, plant and equipment, net | 1 | 1 |
Lease right-of-use assets, net | 12 | 3 |
Current maturities of long-term debt | 3 | 1 |
Long-term debt, less current maturities | 9 | 6 |
Other non-current liabilities | $ 1 | $ 1 |
Lease Accounting - Components_2
Lease Accounting - Components of Lease Expense (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Cost | $ 105 | $ 106 |
Interest on lease liabilities | 1 | 1 |
Lease, Cost | 111 | 109 |
Lease costs, gross | 156 | 157 |
Finance Leases [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Lease, Cost | 2 | 4 |
Cost of goods sold | ||
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Cost | 10 | 14 |
Operating expenses | ||
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Cost | 78 | 75 |
Short-term lease cost | 40 | 31 |
Variable lease cost | 9 | 16 |
Selling, general and administrative | ||
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Cost | 17 | 17 |
Depreciation, depletion and amortization | ||
Lessee, Lease, Description [Line Items] | ||
Amortization of lease assets | 1 | 3 |
Other Revenue [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Sublease Income | $ 45 | $ 48 |
Lease Accounting - Remaining te
Lease Accounting - Remaining term and rate (Details) | Dec. 31, 2021 | Dec. 31, 2020 |
Leases [Abstract] | ||
Operating leases | 19 years | 22 years |
Finance leases | 29 years | 9 years |
Operating leases | 5.00% | 5.00% |
Finance leases | 4.00% | 8.00% |
Lease Accounting - Cash flow (D
Lease Accounting - Cash flow (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Lessee, Lease, Description [Line Items] | |||
Net cash provided by operating activities | $ 11,162 | $ 7,361 | $ 8,056 |
Lease assets obtained in exchange for new finance lease liabilities | 9 | 0 | |
Lease assets obtained in exchange for new operating lease liabilities | 9 | 42 | |
Operating Leases [Member] | |||
Lessee, Lease, Description [Line Items] | |||
Net cash provided by operating activities | $ (147) | $ (117) |
Lease Accounting - Lease Maturi
Lease Accounting - Lease Maturities (Details) $ in Millions | Dec. 31, 2021USD ($) |
Lessee, Lease, Description [Line Items] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | |
2022 | $ 94 |
2023 | 87 |
2024 | 82 |
2025 | 78 |
2026 | 75 |
Thereafter | 5 |
Thereafter | 1,079 |
Lease Liabilities, Due | 1,495 |
Less: present value discount | 613 |
Less: present value discount | 6 |
Less: present value discount | 619 |
Lease, Liabilities | 876 |
Lease Right of Use Assets, Net | |
Lessee, Lease, Description [Line Items] | |
2022 | 90 |
2022 | 4 |
2023 | 86 |
2023 | 1 |
2024 | 82 |
2024 | 0 |
2025 | 78 |
2025 | 0 |
2026 | 75 |
2026 | 0 |
Thereafter | 1,064 |
Thereafter | 15 |
Total lease payments | 1,475 |
Total lease payments | 20 |
Operating Lease, Liability | 862 |
Finance Lease, Liability | $ 14 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |
Lessee, Lease, Description [Line Items] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2022 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |
Lessee, Lease, Description [Line Items] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2023 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | |
Lessee, Lease, Description [Line Items] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2024 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | |
Lessee, Lease, Description [Line Items] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2025 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | |
Lessee, Lease, Description [Line Items] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2026 |
Lease Accounting - Lessor (Deta
Lease Accounting - Lessor (Details) $ in Millions | Dec. 31, 2021USD ($) |
2022 | $ 84 |
2023 | 47 |
2024 | 3 |
2025 | 2 |
2026 | 1 |
Thereafter | 5 |
Total undiscounted cash flows | $ 142 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2022 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2023 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2024 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2025 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year | 2026 |
Derivative Assets And Liabili_3
Derivative Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details) | Dec. 31, 2021MB_blsBBtuMWbarrels | Dec. 31, 2020BBtuMB_blsMWbarrels | |
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | 106,333 | ||
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | 63,898 | 53,575 | |
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | 29,173 | ||
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | 5,950 | 11,861 | |
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | [1] | 66,665 | 44,225 |
Natural Gas [Member] | Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | 40,533 | 30,113 | |
Natural Gas [Member] | Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | 40,533 | 30,113 | |
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | 11,208 | ||
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | 6,738 | ||
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | 585 | 1,603 | |
Natural Gas [Member] | Long [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | 40,533 | 30,113 | |
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | MW | 30,932 | ||
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | MW | 604,920 | ||
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | MW | 7,859 | ||
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | MW | 2,343,293 | ||
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forward Swaps [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | MW | 653,000 | 1,392,400 | |
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | MW | 18,706 | ||
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | MW | 519,071 | ||
Natural Gas Liquids [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | MB_bls | 5,840 | ||
Natural Gas Liquids [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | MB_bls | 8,493 | ||
Refined Products [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | MB_bls | 3,349 | 2,765 | |
Crude Oil [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member] | |||
Derivative, Nonmonetary Notional Amount, Volume | barrels | 3,672 | 0 | |
[1] | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Derivative Assets And Liabili_4
Derivative Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) - Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member] - Forward-Starting Swaps [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
July 2021 [Member] | ||
Description of Interest Rate Derivative Activities | Forward-starting to pay a fixed rate of 3.55% and receive a floating rate | |
Derivative, Notional Amount | $ 0 | $ 400 |
July 2022 [Member] | ||
Description of Interest Rate Derivative Activities | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | |
Derivative, Notional Amount | $ 400 | 400 |
July 2023 | ||
Description of Interest Rate Derivative Activities | Forward-starting to pay a fixed rate of 3.78% and receive a floating rate | |
Derivative, Notional Amount | $ 200 | 0 |
July 2024 | ||
Description of Interest Rate Derivative Activities | Forward-starting to pay a fixed rate of 3.88% and receive a floating rate | |
Derivative, Notional Amount | $ 200 | $ 0 |
Derivative Assets And Liabili_5
Derivative Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Asset Derivatives | $ 272 | $ 168 |
Liability Derivatives | (598) | (717) |
Designated as Hedging Instrument [Member] | ||
Asset Derivatives | 46 | 25 |
Liability Derivatives | (3) | (32) |
Not Designated as Hedging Instrument [Member] | ||
Asset Derivatives | 226 | 143 |
Liability Derivatives | (595) | (685) |
Broker cleared derivative contracts [Member] | ||
Asset Derivatives | 219 | 115 |
Liability Derivatives | (159) | (198) |
Commodity Derivatives [Member] | Not Designated as Hedging Instrument [Member] | ||
Asset Derivatives | 53 | 53 |
Liability Derivatives | (52) | (71) |
Commodity Derivatives (Margin Deposits) [Member] | Designated as Hedging Instrument [Member] | ||
Asset Derivatives | 46 | 25 |
Liability Derivatives | (3) | (32) |
Commodity Derivatives (Margin Deposits) [Member] | Not Designated as Hedging Instrument [Member] | ||
Asset Derivatives | 173 | 90 |
Liability Derivatives | (156) | (166) |
Interest Rate Derivatives [Member] | Not Designated as Hedging Instrument [Member] | ||
Asset Derivatives | 0 | 0 |
Liability Derivatives | $ (387) | $ (448) |
Derivative Assets And Liabili_6
Derivative Assets And Liabilities Derivative Assets and Lianilities (Offsetting Agreements Netting Table) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 |
Asset Derivatives | $ 272 | $ 168 |
Derivative Liabilities | (598) | (717) |
Derivative Asset, Fair Value, Amount Offset Against Collateral | (43) | (44) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 43 | 44 |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | (150) | (64) |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 150 | 64 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 79 | 60 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 405 | 609 |
Without offsetting agreements [Member] | ||
Asset Derivatives | 0 | 0 |
Derivative Liabilities | (387) | (448) |
OTC Contracts [Member] | ||
Asset Derivatives | 53 | 53 |
Derivative Liabilities | (52) | (71) |
Broker cleared derivative contracts [Member] | ||
Asset Derivatives | 219 | 115 |
Derivative Liabilities | $ (159) | $ (198) |
Derivative Assets And Liabili_7
Derivative Assets And Liabilities (Derivative Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Amount of Gain/(Loss) Recognized in Income on Derivatives | $ (86) | $ (229) | $ (323) |
Gains (losses) on interest rate derivatives | 61 | (203) | (241) |
Non Trading [Member] | Commodity Derivatives [Member] | Cost of goods sold | |||
Amount of Gain/(Loss) Recognized in Income on Derivatives | (141) | (34) | (100) |
Trading [Member] | Commodity Derivatives [Member] | Trading Revenue [Member] | |||
Amount of Gain/(Loss) Recognized in Income on Derivatives | 0 | 0 | (3) |
Trading [Member] | Commodity Derivatives [Member] | Cost of goods sold | |||
Amount of Gain/(Loss) Recognized in Income on Derivatives | $ (6) | $ 8 | $ 21 |
Retirement Benefits (Narrative)
Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Retirement Benefits [Line Items] | |||
Defined Contribution Plan, Cost | $ 65 | $ 35 | $ 66 |
Pension Benefits | |||
Retirement Benefits [Line Items] | |||
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year | $ 5 | ||
Large Cap US Equitiies | 100.00% | 100.00% | |
Other Postretirement Benefits | |||
Retirement Benefits [Line Items] | |||
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year | $ 8 | ||
Minimum [Member] | Other Postretirement Benefits | Equity [Member] | |||
Retirement Benefits [Line Items] | |||
Defined Benefit Plan, Plan Assets, Investment within Plan Asset Category, Percentage | 25.00% | ||
Minimum [Member] | Other Postretirement Benefits | Fixed Income Investments [Member] | |||
Retirement Benefits [Line Items] | |||
Defined Benefit Plan, Plan Assets, Investment within Plan Asset Category, Percentage | 65.00% | ||
Maximum [Member] | Other Postretirement Benefits | Equity [Member] | |||
Retirement Benefits [Line Items] | |||
Defined Benefit Plan, Plan Assets, Investment within Plan Asset Category, Percentage | 35.00% | ||
Maximum [Member] | Other Postretirement Benefits | Fixed Income Investments [Member] | |||
Retirement Benefits [Line Items] | |||
Defined Benefit Plan, Plan Assets, Investment within Plan Asset Category, Percentage | 75.00% |
Retirement Benefits (Obligation
Retirement Benefits (Obligations and Funded Status) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Change in benefit obligation: | ||
Settlements | $ 0 | $ 0 |
Change in plan assets: | ||
Settlements | 0 | 0 |
Pension Benefits | ||
Change in benefit obligation: | ||
Defined Benefit Plan, Benefit Obligation | 55 | 52 |
Service cost | 0 | 0 |
Interest cost | 2 | 3 |
Defined Benefit Plan, Benefit Obligation | 55 | |
Change in plan assets: | ||
Defined Benefit Plan, Plan Assets, Amount | 45 | |
Defined Benefit Plan, Plan Assets, Amount | 44 | 45 |
Amounts recognized in the consolidated balance sheets consist of: | ||
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position | (10) | |
Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: | ||
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax | 0 | |
Other Postretirement Benefits | ||
Change in benefit obligation: | ||
Defined Benefit Plan, Benefit Obligation | 208 | 208 |
Service cost | 1 | 1 |
Interest cost | 4 | 5 |
Benefits paid, net | (16) | (16) |
Actuarial (gain) loss and other | (2) | 10 |
Defined Benefit Plan, Benefit Obligation | 195 | 208 |
Change in plan assets: | ||
Defined Benefit Plan, Plan Assets, Amount | 291 | 270 |
Return on plan assets and other | 26 | 28 |
Employer contributions | 10 | 9 |
Benefits paid, net | (16) | (16) |
Defined Benefit Plan, Plan Assets, Amount | 311 | 291 |
Amount underfunded (overfunded) at end of period | (116) | (83) |
Amounts recognized in the consolidated balance sheets consist of: | ||
Non-current assets | 138 | 108 |
Current liabilities | (2) | (2) |
Non-current liabilities | (20) | (23) |
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position | 116 | 83 |
Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: | ||
Net actuarial gain (loss) | (27) | (18) |
Prior service cost | 19 | 21 |
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax | (8) | 3 |
Funded Plans [Member] | Pension Benefits | ||
Change in benefit obligation: | ||
Defined Benefit Plan, Benefit Obligation | 55 | |
Interest cost | 1 | 2 |
Benefits paid, net | (2) | (2) |
Actuarial (gain) loss and other | (2) | 5 |
Settlements | (2) | (2) |
Defined Benefit Plan, Benefit Obligation | 50 | 55 |
Change in plan assets: | ||
Defined Benefit Plan, Plan Assets, Amount | 45 | 43 |
Return on plan assets and other | 2 | 5 |
Employer contributions | 1 | 1 |
Benefits paid, net | (2) | (2) |
Settlements | (2) | (2) |
Defined Benefit Plan, Plan Assets, Amount | 44 | 45 |
Amount underfunded (overfunded) at end of period | 6 | 10 |
Amounts recognized in the consolidated balance sheets consist of: | ||
Non-current assets | 0 | 0 |
Current liabilities | 0 | 0 |
Non-current liabilities | (6) | (10) |
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position | (6) | |
Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: | ||
Net actuarial gain (loss) | 0 | 0 |
Prior service cost | 0 | 0 |
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax | 0 | |
Unfunded Plans [Member] | ||
Change in benefit obligation: | ||
Settlements | 0 | 0 |
Change in plan assets: | ||
Settlements | 0 | 0 |
Unfunded Plans [Member] | Pension Benefits | ||
Change in benefit obligation: | ||
Defined Benefit Plan, Benefit Obligation | 31 | 34 |
Service cost | 0 | 0 |
Interest cost | 1 | 1 |
Benefits paid, net | (4) | (5) |
Actuarial (gain) loss and other | (2) | 1 |
Defined Benefit Plan, Benefit Obligation | 26 | 31 |
Change in plan assets: | ||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 |
Return on plan assets and other | 0 | 0 |
Employer contributions | 0 | 0 |
Benefits paid, net | 0 | 0 |
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 |
Amount underfunded (overfunded) at end of period | 26 | 31 |
Amounts recognized in the consolidated balance sheets consist of: | ||
Non-current assets | 0 | 0 |
Current liabilities | (4) | (4) |
Non-current liabilities | (22) | (27) |
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position | (26) | (31) |
Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: | ||
Net actuarial gain (loss) | 1 | 2 |
Prior service cost | 0 | 0 |
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax | $ 1 | $ 2 |
Retirement Benefits (Accumulate
Retirement Benefits (Accumulated Benefit Obligation In Excess of Plan Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Accumulated benefit obligation | $ 55 | $ 52 | |
Fair value of plan assets | $ 44 | 45 | |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Accumulated benefit obligation | 195 | 208 | 208 |
Fair value of plan assets | 311 | 291 | 270 |
Funded Plans [Member] | Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligation | 50 | 55 | |
Accumulated benefit obligation | 50 | 55 | |
Fair value of plan assets | 44 | 45 | 43 |
Unfunded Plans [Member] | Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligation | 26 | 31 | |
Accumulated benefit obligation | 26 | 31 | 34 |
Fair value of plan assets | $ 0 | $ 0 | $ 0 |
Retirement Benefits (Net Period
Retirement Benefits (Net Periodic Benefit Costs Schedule) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | $ 0 | $ 0 |
Interest cost | 2 | 3 |
Expected return on plan assets | (2) | (2) |
Prior service cost amortization | 0 | 0 |
Net periodic benefit cost | 0 | 1 |
Other Postretirement Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 1 | 1 |
Interest cost | 4 | 5 |
Expected return on plan assets | (11) | (11) |
Prior service cost amortization | 19 | 19 |
Net periodic benefit cost | $ 13 | $ 14 |
Retirement Benefits (Benefit As
Retirement Benefits (Benefit Assumptions) (Details) | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2020 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Health care cost trend rate | 7.14% | 7.30% |
Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.95% | 4.82% |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 2.79% | 2.40% |
Discount rate | 2.57% | 3.05% |
Tax exempt accounts | 4.76% | 4.57% |
Other Postretirement Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 2.24% | 2.04% |
Discount rate | 2.18% | 2.94% |
Tax exempt accounts | 7.00% | 7.00% |
Taxable accounts | 4.75% | 4.75% |
Retirement Benefits (Fair Value
Retirement Benefits (Fair Value of Plan Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Accumulated benefit obligation | $ 195 | $ 208 | $ 208 |
Fair value of plan assets | 311 | 291 | 270 |
Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Accumulated benefit obligation | 55 | 52 | |
Fair value of plan assets | 44 | 45 | |
Cash and Cash Equivalents [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 22 | 18 | |
Cash and Cash Equivalents [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 1 | 1 | |
Mutual Fund [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 175 | 202 | |
Mutual Fund [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 24 | 20 | |
Fixed Income Securities [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 114 | 71 | |
Fixed Income Securities [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 19 | 24 | |
Level 1 [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 197 | 220 | |
Level 1 [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 25 | 21 | |
Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 22 | 18 | |
Level 1 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 1 | 1 | |
Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 175 | 202 | |
Level 1 [Member] | Mutual Fund [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 24 | 20 | |
Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 1 [Member] | Fixed Income Securities [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 2 [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 114 | 71 | |
Level 2 [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 19 | 24 | |
Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 2 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 2 [Member] | Mutual Fund [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 114 | 71 | |
Level 2 [Member] | Fixed Income Securities [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 19 | 24 | |
Level 3 [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 3 [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 3 [Member] | Cash and Cash Equivalents [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 3 [Member] | Mutual Fund [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Level 3 [Member] | Fixed Income Securities [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Funded Plans [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Projected benefit obligation | 50 | 55 | |
Accumulated benefit obligation | 50 | 55 | |
Fair value of plan assets | 44 | 45 | 43 |
Unfunded Plans [Member] | Pension Benefits | |||
Fair Value of Plan Assets [Line Items] | |||
Projected benefit obligation | 26 | 31 | |
Accumulated benefit obligation | 26 | 31 | 34 |
Fair value of plan assets | $ 0 | $ 0 | $ 0 |
Retirement Benefits (Benefit Pa
Retirement Benefits (Benefit Payments) (Details) $ in Millions | Dec. 31, 2021USD ($) |
Other Postretirement Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
2022 | $ 18 |
2023 | 17 |
2024 | 16 |
2025 | 15 |
2026 | 14 |
2027 – 2031 | 57 |
Defined Benefit Plan, Funded Plan | Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
2022 | 4 |
2023 | 3 |
2024 | 3 |
2025 | 2 |
2026 | 2 |
2027 – 2031 | 11 |
Defined Benefit Plan, Unfunded Plan | Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
2022 | 4 |
2023 | 4 |
2024 | 3 |
2025 | 3 |
2026 | 2 |
2027 – 2031 | $ 7 |
Reportable Segments Revenue (De
Reportable Segments Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Revenue from External Customer [Line Items] | |||
Revenues | $ (67,417) | $ (38,954) | $ (54,213) |
Intersegment Eliminations [Member] | |||
Revenue from External Customer [Line Items] | |||
Revenues | (13,423) | (5,884) | (5,951) |
Investment in USAC | |||
Revenue from External Customer [Line Items] | |||
Revenues | (633) | (667) | (698) |
All Other | |||
Revenue from External Customer [Line Items] | |||
Revenues | (3,476) | (1,838) | (1,689) |
Crude Oil Transportation and Services | |||
Revenue from External Customer [Line Items] | |||
Revenues | (17,446) | (11,679) | (18,447) |
NGL and Refined Products Transportation and Services | |||
Revenue from External Customer [Line Items] | |||
Revenues | (19,961) | (10,513) | (11,641) |
Midstream | |||
Revenue from External Customer [Line Items] | |||
Revenues | (11,316) | (5,026) | (6,031) |
Interstate Transportation and Storage | |||
Revenue from External Customer [Line Items] | |||
Revenues | (1,841) | (1,861) | (1,963) |
Intrastate Transportation and Storage | |||
Revenue from External Customer [Line Items] | |||
Revenues | (8,571) | (2,544) | (3,099) |
Investment in Sunoco LP | |||
Revenue from External Customer [Line Items] | |||
Revenues | (17,596) | (10,710) | (16,596) |
Intersegment [Member] | Investment in USAC | |||
Revenue from External Customer [Line Items] | |||
Revenues | (12) | (12) | (20) |
Intersegment [Member] | All Other | |||
Revenue from External Customer [Line Items] | |||
Revenues | (411) | (464) | (81) |
Intersegment [Member] | Crude Oil Transportation and Services | |||
Revenue from External Customer [Line Items] | |||
Revenues | (4) | (5) | 0 |
Intersegment [Member] | NGL and Refined Products Transportation and Services | |||
Revenue from External Customer [Line Items] | |||
Revenues | (2,972) | (2,012) | (1,721) |
Intersegment [Member] | Midstream | |||
Revenue from External Customer [Line Items] | |||
Revenues | (8,696) | (3,082) | (3,751) |
Intersegment [Member] | Interstate Transportation and Storage | |||
Revenue from External Customer [Line Items] | |||
Revenues | (39) | (20) | (22) |
Intersegment [Member] | Intrastate Transportation and Storage | |||
Revenue from External Customer [Line Items] | |||
Revenues | (1,264) | (232) | (350) |
Intersegment [Member] | Investment in Sunoco LP | |||
Revenue from External Customer [Line Items] | |||
Revenues | (25) | (57) | (6) |
External Customers [Member] | Investment in USAC | |||
Revenue from External Customer [Line Items] | |||
Revenues | (621) | (655) | (678) |
External Customers [Member] | All Other | |||
Revenue from External Customer [Line Items] | |||
Revenues | (3,065) | (1,374) | (1,608) |
External Customers [Member] | Crude Oil Transportation and Services | |||
Revenue from External Customer [Line Items] | |||
Revenues | (17,442) | (11,674) | (18,447) |
External Customers [Member] | NGL and Refined Products Transportation and Services | |||
Revenue from External Customer [Line Items] | |||
Revenues | (16,989) | (8,501) | (9,920) |
External Customers [Member] | Midstream | |||
Revenue from External Customer [Line Items] | |||
Revenues | (2,620) | (1,944) | (2,280) |
External Customers [Member] | Interstate Transportation and Storage | |||
Revenue from External Customer [Line Items] | |||
Revenues | (1,802) | (1,841) | (1,941) |
External Customers [Member] | Intrastate Transportation and Storage | |||
Revenue from External Customer [Line Items] | |||
Revenues | (7,307) | (2,312) | (2,749) |
External Customers [Member] | Investment in Sunoco LP | |||
Revenue from External Customer [Line Items] | |||
Revenues | $ (17,571) | $ (10,653) | $ (16,590) |
Reportable Segments (Operating
Reportable Segments (Operating Segments) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Cost of Goods and Services Sold | $ (50,395) | $ (25,487) | $ (39,801) |
Depreciation, depletion and amortization | 3,817 | 3,678 | 3,147 |
Equity in earnings of unconsolidated affiliates | 246 | 119 | 302 |
Intersegment Eliminations [Member] | |||
Cost of Goods and Services Sold | (13,360) | (5,829) | (5,885) |
Intrastate Transportation and Storage | |||
Cost of Goods and Services Sold | (4,769) | (1,478) | (1,909) |
Depreciation, depletion and amortization | 191 | 185 | 184 |
Equity in earnings of unconsolidated affiliates | 20 | 18 | 18 |
Investment in Sunoco LP | |||
Cost of Goods and Services Sold | (16,246) | (9,654) | (15,380) |
Depreciation, depletion and amortization | 177 | 189 | 181 |
Interstate Transportation and Storage | |||
Cost of Goods and Services Sold | (11) | 0 | 0 |
Depreciation, depletion and amortization | 457 | 411 | 387 |
Equity in earnings of unconsolidated affiliates | 140 | 17 | 222 |
Midstream | |||
Cost of Goods and Services Sold | (8,569) | (2,598) | (3,577) |
Depreciation, depletion and amortization | 1,190 | 1,140 | 1,066 |
Equity in earnings of unconsolidated affiliates | 24 | 24 | 20 |
NGL and Refined Products Transportation and Services | |||
Cost of Goods and Services Sold | (16,248) | (7,139) | (8,393) |
Depreciation, depletion and amortization | 778 | 667 | 613 |
Equity in earnings of unconsolidated affiliates | 51 | 60 | 53 |
Crude Oil Transportation and Services | |||
Cost of Goods and Services Sold | (14,759) | (8,838) | (14,832) |
Depreciation, depletion and amortization | 588 | 640 | 437 |
Equity in earnings of unconsolidated affiliates | 10 | (2) | (1) |
All Other | |||
Cost of Goods and Services Sold | (3,068) | (1,527) | (1,504) |
Depreciation, depletion and amortization | 197 | 207 | 48 |
Equity in earnings of unconsolidated affiliates | 1 | 2 | (10) |
Investment in USAC | |||
Cost of Goods and Services Sold | (85) | (82) | (91) |
Depreciation, depletion and amortization | $ 239 | $ 239 | $ 231 |
Reportable Segments Reportable
Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Segment Reporting Information [Line Items] | |||
Segment Adjusted EBITDA | $ 13,046 | $ 10,531 | $ 11,140 |
Depreciation, depletion and amortization | (3,817) | (3,678) | (3,147) |
Interest expense, net of interest capitalized | (2,267) | (2,327) | (2,331) |
Impairment losses | (21) | (2,880) | (74) |
Gains (losses) on interest rate derivatives | 61 | (203) | (241) |
Share-based Payment Arrangement, Noncash Expense | (111) | (121) | (113) |
Non-cash compensation expense | (162) | 71 | 5 |
Losses on extinguishments of debt | (38) | (75) | (18) |
Adjusted EBITDA related to unconsolidated affiliates | 190 | (82) | 79 |
Impairment of investments in unconsolidated affiliates | 0 | (129) | 0 |
Impairment of investments in unconsolidated affiliates | 523 | 628 | 626 |
Equity in earnings of unconsolidated affiliates | 246 | 119 | 302 |
Other, net | (57) | (79) | 54 |
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest | 6,871 | 377 | 5,020 |
Income tax expense (benefit) from continuing operations | (184) | (237) | (195) |
NET INCOME | 6,687 | 140 | 4,825 |
Intrastate Transportation and Storage | |||
Segment Reporting Information [Line Items] | |||
Segment Adjusted EBITDA | 3,483 | 863 | 999 |
Depreciation, depletion and amortization | (191) | (185) | (184) |
Equity in earnings of unconsolidated affiliates | 20 | 18 | 18 |
Investment in Sunoco LP | |||
Segment Reporting Information [Line Items] | |||
Segment Adjusted EBITDA | 754 | 739 | 665 |
Depreciation, depletion and amortization | (177) | (189) | (181) |
Investment in USAC | |||
Segment Reporting Information [Line Items] | |||
Segment Adjusted EBITDA | 398 | 414 | 420 |
Depreciation, depletion and amortization | (239) | (239) | (231) |
Corporate and Other [Member] | |||
Segment Reporting Information [Line Items] | |||
Segment Adjusted EBITDA | 177 | 105 | 98 |
Interstate Transportation and Storage | |||
Segment Reporting Information [Line Items] | |||
Segment Adjusted EBITDA | 1,515 | 1,680 | 1,792 |
Depreciation, depletion and amortization | (457) | (411) | (387) |
Impairment losses | (58) | ||
Equity in earnings of unconsolidated affiliates | 140 | 17 | 222 |
Midstream | |||
Segment Reporting Information [Line Items] | |||
Segment Adjusted EBITDA | 1,868 | 1,670 | 1,602 |
Depreciation, depletion and amortization | (1,190) | (1,140) | (1,066) |
Equity in earnings of unconsolidated affiliates | 24 | 24 | 20 |
NGL and Refined Products Transportation and Services | |||
Segment Reporting Information [Line Items] | |||
Segment Adjusted EBITDA | 2,828 | 2,802 | 2,666 |
Depreciation, depletion and amortization | (778) | (667) | (613) |
Equity in earnings of unconsolidated affiliates | 51 | 60 | 53 |
Crude Oil Transportation and Services | |||
Segment Reporting Information [Line Items] | |||
Segment Adjusted EBITDA | 2,023 | 2,258 | 2,898 |
Depreciation, depletion and amortization | (588) | (640) | (437) |
Equity in earnings of unconsolidated affiliates | $ 10 | $ (2) | $ (1) |
Reportable Segments (Assets Seg
Reportable Segments (Assets Segments) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Assets | $ 105,963 | $ 95,144 | $ 98,973 |
Intrastate Transportation and Storage | |||
Assets | 7,322 | 6,308 | 6,648 |
Interstate Transportation and Storage | |||
Assets | 17,774 | 17,582 | 18,111 |
Midstream | |||
Assets | 21,960 | 18,583 | 20,332 |
NGL and Refined Products Transportation and Services | |||
Assets | 28,160 | 21,423 | 19,145 |
Crude Oil Transportation and Services | |||
Assets | 19,649 | 17,960 | 22,933 |
Investment in Sunoco LP | |||
Assets | 5,815 | 5,267 | 5,438 |
Investment in USAC | |||
Assets | 2,768 | 2,949 | 3,730 |
Corporate and Other [Member] | |||
Assets | $ 2,515 | $ 5,072 | $ 2,636 |
Reporting Segments (Additions T
Reporting Segments (Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | ||
Segment Reporting Information [Line Items] | ||||
Property, Plant and Equipment, Additions | [1] | $ 2,158 | $ 3,759 | $ 5,268 |
Investment in Sunoco LP | ||||
Segment Reporting Information [Line Items] | ||||
Property, Plant and Equipment, Additions | [1] | 174 | 124 | 148 |
Intrastate Transportation and Storage | ||||
Segment Reporting Information [Line Items] | ||||
Property, Plant and Equipment, Additions | [1] | 52 | 49 | 124 |
Interstate Transportation and Storage | ||||
Segment Reporting Information [Line Items] | ||||
Property, Plant and Equipment, Additions | [1] | 159 | 150 | 375 |
Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Property, Plant and Equipment, Additions | [1] | 484 | 487 | 827 |
NGL and Refined Products Transportation and Services | ||||
Segment Reporting Information [Line Items] | ||||
Property, Plant and Equipment, Additions | [1] | 751 | 2,403 | 2,976 |
Crude Oil Transportation and Services | ||||
Segment Reporting Information [Line Items] | ||||
Property, Plant and Equipment, Additions | [1] | 343 | 291 | 403 |
Investment in USAC | ||||
Segment Reporting Information [Line Items] | ||||
Property, Plant and Equipment, Additions | [1] | 60 | 119 | 200 |
All Other | ||||
Segment Reporting Information [Line Items] | ||||
Property, Plant and Equipment, Additions | [1] | $ 135 | $ 136 | $ 215 |
[1] | Excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis). |
Reportable Segments (Advances t
Reportable Segments (Advances to and investments in affiliates) (Details) - USD ($) $ in Millions | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Segment Reporting Information [Line Items] | |||
Investments in unconsolidated affiliates | $ 2,947 | $ 3,060 | $ 3,460 |
Intrastate Transportation and Storage | |||
Segment Reporting Information [Line Items] | |||
Investments in unconsolidated affiliates | 110 | 89 | 88 |
Interstate Transportation and Storage | |||
Segment Reporting Information [Line Items] | |||
Investments in unconsolidated affiliates | 2,209 | 2,278 | 2,524 |
Midstream | |||
Segment Reporting Information [Line Items] | |||
Investments in unconsolidated affiliates | 101 | 110 | 112 |
NGL and Refined Products Transportation and Services | |||
Segment Reporting Information [Line Items] | |||
Investments in unconsolidated affiliates | 476 | 509 | 461 |
Crude Oil Transportation and Services | |||
Segment Reporting Information [Line Items] | |||
Investments in unconsolidated affiliates | 0 | 22 | 242 |
All Other | |||
Segment Reporting Information [Line Items] | |||
Investments in unconsolidated affiliates | $ 51 | $ 52 | $ 33 |