DEI Document
DEI Document - shares | 9 Months Ended | |
Sep. 30, 2018 | Nov. 02, 2018 | |
Entity Information [Line Items] | ||
Entity Registrant Name | Energy Transfer LP | |
Entity Central Index Key | 1,276,187 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 2,617,100,880 | |
Entity Emerging Growth Company | false | |
Entity Small Business | false |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
ASSETS | ||
Cash and cash equivalents | $ 398 | $ 336 |
Accounts receivable, net | 4,408 | 4,504 |
Accounts receivable from related companies | 80 | 53 |
Inventories | 2,066 | 2,022 |
Derivative assets | 97 | 24 |
Income taxes receivable | 169 | 136 |
Other current assets | 303 | 295 |
Current assets held for sale | 6 | 3,313 |
Total current assets | 7,527 | 10,683 |
Property, plant and equipment | 77,819 | 71,177 |
Accumulated depreciation and depletion | (12,176) | (10,089) |
Property, Plant and Equipment, Net | 65,643 | 61,088 |
Advances to and investments in unconsolidated affiliates | 2,656 | 2,705 |
Other non-current assets, net | 1,106 | 886 |
Intangible assets, net | 6,013 | 6,116 |
Goodwill | 5,242 | 4,768 |
Total assets | 88,187 | 86,246 |
LIABILITIES AND EQUITY | ||
Accounts payable | 3,986 | 4,685 |
Accounts payable to related companies | 58 | 31 |
Derivative liabilities | 344 | 111 |
Income taxes payable | 88 | 0 |
Accrued and other current liabilities | 3,088 | 2,582 |
Current maturities of long-term debt | 2,655 | 413 |
Current liabilities held for sale | 0 | 75 |
Total current liabilities | 10,219 | 7,897 |
Long-term debt, less current maturities | 42,117 | 43,671 |
Non-current derivative liabilities | 58 | 145 |
Deferred income taxes | 3,008 | 3,315 |
Other non-current liabilities | 1,253 | 1,217 |
Commitments and contingencies | ||
Redeemable noncontrolling interests | 499 | 21 |
Limited Partners: | ||
Series A Convertible Preferred Units | 0 | 450 |
Common Unitholders | (1,099) | (1,643) |
General Partner | (4) | (3) |
Accumulated other comprehensive income (loss) | 0 | 0 |
Total partners’ deficit | (1,103) | (1,196) |
Noncontrolling interest | 32,136 | 31,176 |
Total equity | 31,033 | 29,980 |
Total liabilities and equity | $ 88,187 | $ 86,246 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | [1] | Sep. 30, 2018 | Sep. 30, 2017 | [1] | |
Sunoco LP Series A Preferred Units redemption | $ 18 | $ 5 | $ 14 | $ 0 | ||
REVENUES: | ||||||
Total revenues | 14,514 | 9,984 | 40,514 | 29,072 | ||
COSTS AND EXPENSES: | ||||||
Cost of products sold | 11,093 | 7,341 | 31,681 | 22,018 | ||
Operating expenses | 784 | 918 | 2,280 | 2,167 | ||
Depreciation, depletion and amortization | 750 | 642 | 2,109 | 1,877 | ||
Selling, general and administrative | 184 | 142 | 515 | 480 | ||
Impairment losses | 0 | 10 | 0 | 99 | ||
Total costs and expenses | 12,811 | 9,053 | 36,585 | 26,641 | ||
OPERATING INCOME | 1,703 | 931 | 3,929 | 2,431 | ||
OTHER INCOME (EXPENSE): | ||||||
Interest expense, net of interest capitalized | (535) | (490) | (1,511) | (1,440) | ||
Equity in earnings of unconsolidated affiliates | 87 | 92 | 258 | 228 | ||
Losses on extinguishments of debt | 0 | 0 | (106) | (25) | ||
Gains (losses) on interest rate derivatives | 45 | (8) | 117 | (28) | ||
Other, net | 23 | 54 | 83 | 133 | ||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) | 1,341 | 584 | 2,784 | 1,299 | ||
Income tax expense (benefit) from continuing operations | (52) | (157) | 6 | (86) | ||
INCOME FROM CONTINUING OPERATIONS | 1,393 | 741 | 2,778 | 1,385 | ||
Income (loss) from discontinued operations, net of income taxes | (2) | 17 | (265) | (187) | ||
NET INCOME | 1,391 | 758 | 2,513 | 1,198 | ||
Less: Net income attributable to noncontrolling interest | 1,008 | 506 | 1,412 | 495 | ||
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest | 12 | 0 | 24 | 0 | ||
NET INCOME ATTRIBUTABLE TO PARTNERS | 371 | 252 | 1,077 | 703 | ||
General Partner’s interest in net income | 1 | 1 | 3 | 2 | ||
Convertible Unitholders' interest in income | 0 | 11 | 33 | 25 | ||
Limited Partners’ interest in net income | $ 370 | $ 240 | $ 1,041 | $ 676 | ||
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT: | ||||||
Basic | $ 0.32 | $ 0.22 | $ 0.94 | $ 0.63 | ||
Diluted | 0.32 | 0.22 | 0.94 | 0.62 | ||
NET INCOME PER LIMITED PARTNER UNIT: | ||||||
Basic | 0.32 | 0.22 | 0.93 | 0.62 | ||
Diluted | $ 0.32 | $ 0.22 | $ 0.93 | $ 0.61 | ||
Natural gas sales [Member] | ||||||
REVENUES: | ||||||
Revenue from Contract with Customer, Including Assessed Tax | $ 1,026 | $ 1,098 | $ 3,112 | $ 3,132 | ||
NGL sales [Member] | ||||||
REVENUES: | ||||||
Revenue from Contract with Customer, Including Assessed Tax | 2,695 | 1,749 | 6,866 | 4,782 | ||
Oil and Gas [Member] | ||||||
REVENUES: | ||||||
Revenue from Contract with Customer, Including Assessed Tax | 3,841 | 2,381 | 11,336 | 7,268 | ||
Natural Gas, Midstream [Member] | ||||||
REVENUES: | ||||||
Revenue from Contract with Customer, Including Assessed Tax | 1,781 | 1,068 | 4,878 | 3,244 | ||
Oil and Gas, Refining and Marketing [Member] | ||||||
REVENUES: | ||||||
Revenue from Contract with Customer, Including Assessed Tax | 4,955 | 3,080 | 13,583 | 8,998 | ||
Product and Service, Other [Member] | ||||||
REVENUES: | ||||||
Revenue from Contract with Customer, Including Assessed Tax | $ 216 | $ 608 | $ 739 | $ 1,648 | ||
[1] | As adjusted. See Note 1. |
Consolidated Statements Of Comp
Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | [1] | Sep. 30, 2018 | Sep. 30, 2017 | [1] | |
Statement of Comprehensive Income [Abstract] | ||||||
Net income | $ 1,391 | $ 758 | $ 2,513 | $ 1,198 | ||
Other comprehensive income, net of tax: | ||||||
Change in value of available-for-sale securities | 2 | 2 | 0 | 5 | ||
Actuarial gain (loss) relating to pension and other postretirement benefit plans | 0 | 5 | (2) | 2 | ||
Change in other comprehensive income from unconsolidated affiliates | 2 | 0 | 9 | (1) | ||
Other comprehensive income (loss), net of tax | 4 | 7 | 7 | 6 | ||
Comprehensive income | 1,395 | 765 | 2,520 | 1,204 | ||
Less: Comprehensive income attributable to noncontrolling interest | 1,024 | 513 | 1,443 | 501 | ||
Comprehensive income attributable to partners | $ 371 | $ 252 | $ 1,077 | $ 703 | ||
[1] | As adjusted. See Note 1. |
Consolidated Statement Of Equit
Consolidated Statement Of Equity - 9 months ended Sep. 30, 2018 - USD ($) $ in Millions | Total | Series A Convertible Preferred Units [Member] | Common Unitholders | General Partner | Noncontrolling Interest |
Balance, December 31, 2017 at Dec. 31, 2017 | $ 29,980 | $ 450 | $ (1,643) | $ (3) | $ 31,176 |
Distributions to partners | (886) | 0 | (883) | (3) | 0 |
Distributions to noncontrolling interest | (2,742) | 0 | 0 | 0 | (2,742) |
Distributions reinvested | 0 | 115 | (115) | 0 | 0 |
Subsidiary units repurchased | (24) | (7) | (119) | 0 | 102 |
Subsidiary units issued | 938 | 0 | 1 | 0 | 937 |
Capital contributions received from noncontrolling interests | 438 | 0 | 0 | 0 | 438 |
Other comprehensive income, net of tax | 7 | 0 | 0 | 0 | 7 |
Acquisition of USAC | 832 | 0 | 0 | 0 | 832 |
Series A Convertible Preferred Units conversion | 0 | (589) | 589 | 0 | 0 |
Other, net | 55 | (2) | 30 | (1) | 28 |
Net income, excluding amounts attributable to redeemable noncontrolling interests | 2,489 | 33 | 1,041 | 3 | 1,412 |
Balance, September 30, 2018 at Sep. 30, 2018 | 31,033 | 0 | (1,099) | (4) | 32,136 |
Cumulative effect adjustment due to change in accounting principle (see Note 1) | $ (54) | $ 0 | $ 0 | $ 0 | $ (54) |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Millions | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | ||
OPERATING ACTIVITIES | |||
Net income, excluding amounts attributable to redeemable noncontrolling interests | $ 2,513 | $ 1,198 | [1] |
Reconciliation of net income to net cash provided by operating activities: | |||
Loss from discontinued operations | 265 | 187 | [1] |
Depreciation, depletion and amortization | 2,109 | 1,877 | [1] |
Deferred income taxes | 1 | (64) | [1] |
Non-cash compensation expense | 82 | 76 | [1] |
Impairment losses | 0 | 99 | [1] |
Losses on extinguishments of debt | (106) | (25) | [1] |
Equity in earnings of unconsolidated affiliates | (258) | (228) | [1] |
Distributions from unconsolidated affiliates | 220 | 211 | [1] |
Inventory valuation adjustments | (50) | (8) | [1] |
Distributions on unvested awards | (36) | (24) | [1] |
Other non-cash | (80) | (131) | [1] |
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation | 423 | 192 | [1] |
Net cash provided by operating activities | 5,295 | 3,410 | [1] |
INVESTING ACTIVITIES | |||
Cash received from Bakken Pipeline Transaction | 0 | 2,000 | [1] |
Cash received in USAC acquisition (net of cash paid) | 461 | 0 | [1] |
Cash paid for other acquisitions (net of cash received) | (233) | (573) | [1] |
Capital expenditures (excluding allowance for equity funds used during construction) | (5,175) | (6,126) | [1] |
Contributions in aid of construction costs | 95 | 25 | [1] |
Contributions to unconsolidated affiliate | 13 | 230 | [1] |
Distributions from unconsolidated affiliates in excess of cumulative earnings | 62 | 115 | [1] |
Proceeds from the sale of other assets | 40 | 37 | [1] |
Other | 0 | (33) | [1] |
Net cash used in by investing activities | (4,763) | (4,785) | [1] |
FINANCING ACTIVITIES | |||
Proceeds from borrowings | 22,126 | 23,988 | [1] |
Repayments of long-term debt | (23,323) | (22,536) | [1] |
Cash paid on affiliate notes | 0 | (255) | [1] |
Subsidiary units repurchased | (24) | 0 | [1] |
Units issued for cash | 0 | 568 | [1] |
Subsidiary units and warrants issued for cash | 1,403 | 1,635 | [1] |
Distributions to partners | (886) | (752) | [1] |
Payments of Ordinary Dividends, Preferred Stock and Preference Stock | (12) | 0 | |
Debt issuance costs | (188) | (85) | [1] |
Distributions to noncontrolling interests | (2,742) | (2,156) | [1] |
Capital contributions from noncontrolling interest | 438 | 919 | [1] |
Redemption of ETP Convertible Preferred Units | 0 | (53) | [1] |
Other, net | 0 | 30 | [1] |
Net cash (used in) provided by financing activities | (3,208) | 1,303 | [1] |
DISCONTINUED OPERATIONS | |||
Operating activities | (480) | 139 | [1] |
Investing activities | 3,207 | (57) | [1] |
Changes in cash included in current assets held for sale | 11 | (2) | [1] |
Net increase in cash and cash equivalents of discontinued operations | 2,738 | 80 | [1] |
Increase in cash and cash equivalents | 62 | 8 | [1] |
Cash and cash equivalents, beginning of period | 336 | 467 | [1] |
Cash and cash equivalents, end of period | $ 398 | $ 475 | [1] |
[1] | As adjusted. See Note 1. |
Operations And Organization
Operations And Organization | 9 Months Ended |
Sep. 30, 2018 | |
Operations And Organization [Abstract] | |
Operations And Organization | ORGANIZATION AND BASIS OF PRESENTATION Organization Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer LP (formerly Energy Transfer Equity, L.P., as discussed below) and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis. The consolidated financial statements of ETE presented herein include the results of operations of: • the Parent Company; • our controlled subsidiaries, ETP, Sunoco LP and, beginning April 2018, USAC; • consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that owned general partner interests and IDRs in ETP and Sunoco LP, and the general partner interests in USAC; and • our wholly-owned subsidiary, Lake Charles LNG. Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities. On September 30, 2018 , our interests in ETP, Sunoco LP and USAC consisted of 100% of the respective general partner interests and IDRs in ETP and Sunoco LP, as well as approximately 27.5 million ETP common units, approximately 2.3 million Sunoco LP common units, and approximately 20.5 million USAC common units. Additionally, ETE owned 100 ETP Class I Units, which were not entitled to any distributions. ETE-ETP Merger and Name Change In October 2018, Energy Transfer Equity, L.P. (“ETE”) and Energy Transfer Partners, L.P. (“ETP”) completed the merger of ETP with a wholly-owned subsidiary of ETE in a unit-for-unit exchange (the “ETE-ETP Merger”). In connection with the transaction, ETP unitholders (other than ETE and its subsidiaries) received 1.28 common units of ETE for each common unit of ETP they owned. Immediately prior to the closing of the ETE-ETP Merger, the following also occurred: • the IDRs in ETP were converted into 1,168,205,710 ETP common units; and • the general partner interest in ETP was converted to a non-economic general partner interest and ETP issued 18,448,341 ETP common units to ETP GP. Following the closing of the ETE-ETP Merger, ETE changed its name to “Energy Transfer LP” and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on Friday, October 19, 2018. In addition, ETP changed its name to “Energy Transfer Operating, L.P.” For purposes of maintaining clarity, the following references are used herein: • References to “ETP” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the ETE-ETP Merger and Energy Transfer Operating, L.P. subsequent to the close of the ETE-ETP Merger ; and • References to “ETE” refer to the entity named Energy Transfer Equity, L.P. prior to the close of the ETE-ETP Merger and Energy Transfer LP subsequent to the close of the ETE-ETP Merger . Business Operations The Parent Company’s principal sources of cash flow have been derived from its direct and indirect investments in ETP, Sunoco LP, USAC and Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 16 for stand-alone financial information apart from that of the consolidated partnership information included herein. Our financial statements reflect the following reportable business segments: • Investment in ETP, including the consolidated operations of ETP; • Investment in Sunoco LP, including the consolidated operations of Sunoco LP; • Investment in USAC, including the consolidated operations of USAC; • Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and • Corporate and Other, including the following: • activities of the Parent Company; and • the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 , filed with the SEC on February 23, 2018 . In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. For prior periods reported herein, certain other prior period amounts were reclassified to conform to the 2018 presentation. Additionally, there are reclassifications of certain balances to assets and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity. Change in Accounting Policy Inventory Accounting Change During the fourth quarter of 2017, we elected to change our method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined product and NGL associated with the legacy Sunoco Logistics business. Our management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity. As a result of this change in accounting policy, the consolidated statement of operations and comprehensive income in prior periods have been retrospectively adjusted, as follows: Three Months Ended Nine Months Ended September 30, 2017 September 30, 2017 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted Cost of products sold $ 7,295 $ 46 $ 7,341 $ 22,005 $ 13 $ 22,018 Operating income 977 (46 ) 931 2,444 (13 ) 2,431 Income before income tax expense 630 (46 ) 584 1,312 (13 ) 1,299 Net income 804 (46 ) 758 1,211 (13 ) 1,198 Net loss attributable to noncontrolling interest 552 (46 ) 506 508 (13 ) 495 Comprehensive income 811 (46 ) 765 1,217 (13 ) 1,204 * Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 2. As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows: Nine Months Ended September 30, 2017 As Originally Reported* Effect of Change As Adjusted Net income $ 1,211 $ (13 ) $ 1,198 Inventory Valuation Adjustments (38 ) 30 (8 ) Net change in operating assets and liabilities (change in inventories) 209 (17 ) 192 * Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 2. Revenue Recognition Standard In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”) , which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018. Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to decreases in revenue (with offsetting decreases to cost of sales) resulting from recognition of non-cash consideration as revenue when received and as cost of sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related to certain of our operations, as well as contracts deemed to be in-substance supply agreements in our midstream operations. In addition to the evaluation performed, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard. The Partnership has elected to apply the modified retrospective method to adopt the new standard. Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018. For contracts in scope of the new revenue standard as of January 1, 2018, the Partnership recognized a cumulative effect adjustment to retained earnings to account for the differences in timing of revenue recognition. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods. The adjustments to the opening balance sheet primarily relate to a change in timing of revenue recognition for variable consideration at Sunoco LP, such as incentives paid to customers, as well as a change in timing of revenue recognition for franchise fee revenue. Historically, an asset was recognized related to the contract incentives which was amortized over the life of the agreement. Under the new standard, the timing of the recognition of incentives changed due to application of the expected value method to estimate variable consideration. Additionally, under the new standard the change in timing of franchise fee revenue is due to the treatment of revenue recognition from the symbolic license over the term of the agreement. The cumulative effect of the changes made to the Partnership’s consolidated balance sheet for the adoption of ASU 2014-09 was as follows: Balance at December 31, 2017 Adjustments due to ASC 606 Balance at January 1, 2018 Assets: Other current assets $ 295 $ 8 $ 303 Property and Equipment, net 61,088 — 61,088 Other non-current assets, net 886 39 925 Intangible assets, net 6,116 (100 ) 6,016 Liabilities and Equity: Other non-current liabilities $ 1,217 $ 1 $ 1,218 Noncontrolling interest 31,176 (54 ) 31,122 The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales, and operating expenses. Additionally, changes in timing of revenue recognition have required the creation of contract asset or contract liability balances, as well as certain balance sheet reclassifications. In accordance with the requirements of ASC Topic 606, the disclosure below shows the impact of adopting the new standard on the consolidated statement of operations and the consolidated balance sheet. Three Months Ended Nine Months Ended September 30, 2018 September 30, 2018 As Reported Balances Without Adoption of ASC 606 Effect of Change: Higher/(Lower) As Reported Balances Without Adoption of ASC 606 Effect of Change: Higher/(Lower) Revenues: Natural gas sales $ 1,026 $ 1,026 $ — $ 3,112 $ 3,112 $ — NGL sales 2,695 2,686 9 6,866 6,839 27 Crude sales 3,841 3,838 3 11,336 11,326 10 Gathering, transportation and other fees 1,781 1,985 (204 ) 4,878 5,415 (537 ) Refined product sales 4,955 4,968 (13 ) 13,583 13,619 (36 ) Other 216 216 — 739 739 — Costs and expenses: Cost of products sold $ 11,093 $ 11,298 $ (205 ) $ 31,681 $ 32,221 $ (540 ) Operating expenses 784 773 11 2,280 2,248 32 Depreciation and amortization 750 758 (8 ) 2,109 2,130 (21 ) September 30, 2018 As Reported Balances Without Adoption of ASC 606 Effect of Change: Higher/(Lower) Assets: Other current assets $ 303 $ 292 $ 11 Property and Equipment, net 65,643 65,643 — Intangible assets, net 6,013 6,135 (122 ) Other non-current assets, net 1,106 1,055 51 Liabilities and Equity: Other non-current liabilities $ 1,253 $ 1,252 $ 1 Noncontrolling interest 32,136 32,197 (61 ) Additional disclosures related to revenue are included in Note 12 . Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates. Recent Accounting Pronouncements ASU 2016-02 In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report information about the amount, timing, and uncertainty of cash flows arising from a lease. The update requires lessees to record virtually all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the existing lease guidance in Topic 840. The Partnership plans to elect the package of transition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment to retained earnings. The Partnership has performed several procedures to evaluate the impact of the adoption of this standard on the financial statements and disclosures and address the implications of Topic 842 on future lease arrangements. The procedures include reviewing all forms of leases, performing a completeness assessment over the lease population, establishing processes and controls to timely identify new and modified lease agreements, educating its employees on these new processes and controls and implementing a third-party supported lease accounting information system to account for our leases in accordance with the new standard. However, we are still in the process of quantifying this impact. We expect that upon adoption most of the Partnership’s lease commitments will be recognized as right of use assets and lease obligations. ASU 2017-12 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. ASU 2018-02 In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income , which allows a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material. |
Acquisitions
Acquisitions | 9 Months Ended |
Sep. 30, 2018 | |
ACQUISITIONS AND DIVESTITURE [Abstract] | |
Acquisitions | ACQUISITIONS AND OTHER INVESTING TRANSACTIONS ETE-ETP Merger and Related Contribution of Assets to ETP Immediately prior to the closing of the ETE-ETP Merger discussed in Note 1 , ETE contributed the following to ETP: • 2,263,158 common units representing limited partner interests in Sunoco LP to ETP in exchange for 2,874,275 ETP common units; • 100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETP in exchange for 42,812,389 ETP common units; • 12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETP in exchange for 16,134,903 ETP common units; and • a 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC to ETP in exchange for 37,557,815 ETP common units. ETE will continue to consolidate each of these entities in its consolidated financial statements subsequent to the ETE-ETP Merger, and these transactions will not impact the carrying values of the related assets and liabilities. USAC Transactions On April 2, 2018, ETE acquired a controlling interest in USAC, a publicly traded partnership that provides compression services in the United States. Specifically ETE acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC (“USAC GP”), the general partner of USAC, and (ii) 12,466,912 USAC common units representing limited partner interests in USAC for cash consideration equal to $250 million (the “USAC Transaction”). Concurrently, USAC cancelled its incentive distribution rights and converted its economic general partner interest into a non-economic general partner interest in exchange for the issuance of 8,000,000 USAC common units to USAC GP. Concurrent with these transactions, ETP contributed to USAC all of the issued and outstanding membership interests of CDM for aggregate consideration of approximately $1.7 billion , consisting of (i) 19,191,351 USAC common units, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“USAC Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The USAC Class B Units are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019. Prior to the CDM Contribution, the CDM entities were indirect wholly-owned subsidiaries of ETP. Beginning April 2018, ETE’s consolidated financial statements reflected USAC as a consolidated subsidiary. Summary of Assets Acquired and Liabilities Assumed We accounted for the USAC Transaction 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 fair values as of the acquisition date. The total purchase price was allocated as follows: At April 2, 2018 Total current assets $ 786 Property, plant and equipment 1,332 Other non-current assets 15 Goodwill (1) 366 Intangible assets 222 2,721 Total current liabilities 110 Long-term debt, less current maturities 1,527 Other non-current liabilities 2 1,639 Noncontrolling interest 832 Total consideration 250 Cash received (2) 711 Total consideration, net of cash received (2) $ (461 ) (1) None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations. (2) Cash received represents cash and cash equivalents held by USAC as of the acquisition date. The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. HPC ETP previously owned a 49.99% interest in HPC, which owns RIGS. In April 2018, ETP acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in the Partnership’s consolidated financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in the Partnership’s consolidated financial statements. Sunoco LP Retail Store and Real Estate Sales On January 23, 2018, Sunoco LP completed the disposition of assets pursuant to the purchase agreement with 7-Eleven, Inc. (the “7-11 Transaction”). As a result of the 7-11 Transaction, previously eliminated wholesale motor fuel sales to Sunoco LP’s retail locations are reported as wholesale motor fuel sales to third parties. Also, the related accounts receivable from such sales are no longer eliminated from the Partnership’s consolidated balance sheets and are reported as accounts receivable. In connection with the 7-11 Transaction, Sunoco LP entered into a Distributor Motor Fuel Agreement dated as of January 23, 2018 (“Supply Agreement”), with 7-Eleven and SEI Fuel (collectively, “Distributor”). The Supply Agreement consists of a 15-year take-or-pay fuel supply arrangement under which Sunoco LP has agreed to supply approximately 2.0 billion gallons of fuel annually plus additional aggregate growth volumes of up to 500 million gallons to be added incrementally over the first four years. For the period from January 1, 2018 through January 22, 2018 and the three and nine months ended September 30, 2017 , Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of $199 million , $926 million and $2.4 billion , respectively, which were eliminated in consolidation. Sunoco LP payments on trade receivables of $1 billion and $2.6 billion from 7-Eleven in the three and nine months ended September 30, 2018 subsequent to the closing of the sale. On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties are being sold through a sealed-bid. Of the 97 properties, 50 have been sold, one is under contract to be sold, and five continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which are operated by a commission agent. The Partnership has concluded that it meets the accounting requirements for reporting the financial position, results of operations and cash flows of Sunoco LP’s retail divestment as discontinued operations. The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet: September 30, 2018 December 31, 2017 Carrying amount of assets classified as held for sale: Cash and cash equivalents $ — $ 21 Inventories — 149 Other current assets — 16 Property, plant and equipment, net 6 1,851 Goodwill — 796 Intangible assets, net — 477 Other non-current assets, net — 3 Total assets classified as held for sale in the Consolidated Balance Sheet $ 6 $ 3,313 Carrying amount of liabilities classified as held for sale: Other current and non-current liabilities $ — $ 75 Total liabilities classified as held for sale in the Consolidated Balance Sheet $ — $ 75 The results of operations associated with discontinued operations are presented in the following table: Three Months Ended Nine Months Ended 2018 2017 2018 2017 REVENUES $ — $ 1,802 $ 349 $ 5,145 COSTS AND EXPENSES Cost of products sold — 1,482 305 4,274 Operating expenses — 182 61 566 Depreciation, depletion and amortization — (5 ) — 31 Impairment losses — 34 — 265 Selling, general and administrative — 57 7 126 Total costs and expenses — 1,750 373 5,262 OPERATING LOSS — 52 (24 ) (117 ) Interest expense, net — 13 2 21 Loss on extinguishment of debt and other — — 20 — Other, net — (8 ) 61 — INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE — 47 (107 ) (138 ) Income tax expense 2 30 158 49 INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES $ (2 ) $ 17 $ (265 ) $ (187 ) INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE ATTRIBUTABLE TO ETE $ — $ 1 $ (10 ) $ (6 ) |
Cash And Cash Equivalents
Cash And Cash Equivalents | 9 Months Ended |
Sep. 30, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Cash And Cash Equivalents | CASH AND CASH EQUIVALENTS 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. Non-cash investing and financing activities were as follows: Nine Months Ended 2018 2017 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 1,059 $ 1,237 Losses from subsidiary common unit transactions (125 ) (57 ) NON-CASH FINANCING ACTIVITIES: Contribution of property, plant and equipment from noncontrolling interest $ — $ 988 Conversion of Series A Convertible Preferred Units to common units 589 — |
Inventories (Notes)
Inventories (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Inventory, Net [Abstract] | |
Inventories | INVENTORIES Inventories consisted of the following: September 30, 2018 December 31, 2017 Natural gas, NGLs, and refined products $ 1,072 $ 1,120 Crude oil 643 551 Spare parts and other 351 351 Total inventories $ 2,066 $ 2,022 We utilize commodity derivatives to manage price volatility associated with its natural gas inventories. 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. USAC’s inventory consists of serialized and non-serialized parts used primarily in the repair of compression units. All inventory is stated at the lower of cost or net realizable value. The cost of serialized parts inventory is determined using the specific identification cost method, while the cost of non-serialized parts inventory is determined using the weighted average cost method. Purchases of these assets are considered operating activities on the Consolidated Statements of Cash Flows. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASURES 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 consolidated debt obligations as of September 30, 2018 were $45.54 billion and $44.77 billion , respectively. As of December 31, 2017 , the aggregate fair value and carrying amount of our consolidated debt obligations were $45.62 billion and $44.08 billion , respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs used for similar liabilities. We have commodity derivatives and interest rate derivatives 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 nine months ended September 30, 2018 , no transfers were made between any levels within the fair value hierarchy. The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2018 and December 31, 2017 based on inputs used to derive their fair values: Fair Value Measurements at Fair Value Total Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 48 $ 48 $ — Swing Swaps IFERC 1 — 1 Fixed Swaps/Futures 25 25 — Forward Physical Contracts 12 — 12 Power: Forwards 36 — 36 Options — Puts 1 1 — NGLs — Forwards/Swaps 476 476 — Refined Products — Futures 4 4 — Total commodity derivatives 603 554 49 Other non-current assets 28 18 10 Total assets $ 631 $ 572 $ 59 Liabilities: Interest rate derivatives $ (97 ) $ — $ (97 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (89 ) (89 ) — Swing Swaps IFERC (1 ) — (1 ) Fixed Swaps/Futures (26 ) (26 ) — Forward Physical Contracts (7 ) — (7 ) Power: Forwards (30 ) — (30 ) Futures (1 ) (1 ) — NGLs — Forwards/Swaps (522 ) (522 ) — Refined Products — Futures (10 ) (10 ) — Crude — Forwards/Swaps (191 ) (191 ) — Total commodity derivatives (877 ) (839 ) (38 ) Total liabilities $ (974 ) $ (839 ) $ (135 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 11 $ 11 $ — Swing Swaps IFERC 13 — 13 Fixed Swaps/Futures 70 70 — Forward Physical Contracts 8 — 8 Power — Forwards 23 — 23 NGLs — Forwards/Swaps 191 191 — Refined Products — Futures 1 1 — Crude: Forwards/Swaps 2 2 — Futures 2 2 — Total commodity derivatives 321 277 44 Other non-current assets 21 14 7 Total assets $ 342 $ 291 $ 51 Liabilities: Interest rate derivatives $ (219 ) $ — $ (219 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (24 ) (24 ) — Swing Swaps IFERC (15 ) (1 ) (14 ) Fixed Swaps/Futures (57 ) (57 ) — Forward Physical Contracts (2 ) — (2 ) Power — Forwards (22 ) — (22 ) NGLs — Forwards/Swaps (186 ) (186 ) — Refined Products — Futures (28 ) (28 ) — Crude: Forwards/Swaps (6 ) (6 ) — Futures (1 ) (1 ) — Total commodity derivatives (341 ) (303 ) (38 ) Total liabilities $ (560 ) $ (303 ) $ (257 ) |
Net Income per Limited Partner
Net Income per Limited Partner Unit | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Net Income Per Limited Partner Unit | NET INCOME PER LIMITED PARTNER UNIT A reconciliation of income and weighted average units used in computing basic and diluted income per unit is as follows: Three Months Ended Nine Months Ended 2018 2017* 2018 2017* Income from continuing operations $ 1,393 $ 741 $ 2,778 $ 1,385 Less: Net income attributable to redeemable noncontrolling interests 12 — 24 — Less: Income from continuing operations attributable to noncontrolling interest 1,010 491 1,667 676 Income from continuing operations, net of noncontrolling interest 371 250 1,087 709 Less: Convertible Unitholders’ interest in income — 11 33 25 Less: General Partner’s interest in income 1 1 3 2 Income from continuing operations available to Limited Partners $ 370 $ 238 $ 1,051 $ 682 Basic Income from Continuing Operations per Limited Partner Unit: Weighted average limited partner units 1,158.2 1,079.1 1,117.7 1,077.9 Basic income from continuing operations per Limited Partner unit $ 0.32 $ 0.22 $ 0.94 $ 0.63 Basic income (loss) from discontinued operations per Limited Partner unit $ 0.00 $ 0.00 $ (0.01 ) $ (0.01 ) Diluted Income from Continuing Operations per Limited Partner Unit: Income from continuing operations available to Limited Partners $ 370 $ 238 $ 1,051 $ 682 Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders — 11 33 25 Diluted income from continuing operations available to Limited Partners $ 370 $ 249 $ 1,084 $ 707 Weighted average limited partner units 1,158.2 1,079.1 1,117.7 1,077.9 Dilutive effect of unconverted unit awards and Convertible Units — 69.2 40.5 69.5 Diluted weighted average limited partner units 1,158.2 1,148.3 1,158.2 1,147.4 Diluted income from continuing operations per Limited Partner unit $ 0.32 $ 0.22 $ 0.94 $ 0.62 Diluted income (loss) from discontinued operations per Limited Partner unit $ 0.00 $ 0.00 $ (0.01 ) $ (0.01 ) * As adjusted. See Note 1. |
Debt Obligations
Debt Obligations | 9 Months Ended |
Sep. 30, 2018 | |
Debt Obligations [Abstract] | |
Debt Obligations | DEBT OBLIGATIONS Parent Company Indebtedness The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by all of its and certain of its subsidiaries’ tangible and intangible assets. ETE Revolving Credit Facility As of September 30, 2018 , borrowings of $898 million were outstanding under the Parent Company revolving credit facility. In connection with the closing of the ETE-ETP Merger, on October 19, 2018, the Partnership repaid in full all outstanding borrowings under the facility and the facility was terminated. Subsidiary Indebtedness ETP Senior Notes Offering and Redemption In June 2018, ETP issued the following senior notes: • $500 million aggregate principal amount of 4.20% senior notes due 2023 ; • $1.00 billion aggregate principal amount of 4.95% senior notes due 2028 ; • $500 million aggregate principal amount of 5.80% senior notes due 2038 ; and • $1.00 billion aggregate principal amount of 6.00% senior notes due 2048. The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal on the senior notes is payable upon maturity and interest is paid semi-annually. The senior notes rank equally in right of payment with ETP’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETP may incur. The notes of each series will initially be fully and unconditionally guaranteed by ETP’s subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of ETP’s other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes. The $2.96 billion net proceeds from the offering were used to repay borrowings outstanding under ETP’s revolving credit facility, for general partnership purposes and to redeem all of the following senior notes: • ETP’s $650 million aggregate principal amount of 2.50% senior notes due June 15, 2018; • Panhandle’s $400 million aggregate principal amount of 7.00% senior notes due June 15, 2018; and • ETP’s $600 million aggregate principal amount of 6.70% senior notes due July 1, 2018. The aggregate amount paid to redeem these notes was approximately $1.65 billion . ETP Five-Year Credit Facility ETP’s revolving credit facility (the “ETP Five-Year Credit Facility”) previously allowed for unsecured borrowings up to $4.00 billion and matured in December 2022. On October 19, 2018, the ETP Five-Year Credit Facility was amended to increase the borrowing capacity by $1.00 billion , to $5.00 billion , and to extend the maturity date to December 1, 2023. The ETP 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 September 30, 2018 , the ETP Five-Year Credit Facility had $1.78 billion outstanding, of which $1.57 billion was commercial paper. The amount available for future borrowings was $2.06 billion after taking into account letters of credit of $163 million , but before taking into account the additional capacity from the October 19, 2018 amendment. The weighted average interest rate on the total amount outstanding as of September 30, 2018 was 3.00% . ETP 364-Day Facility ETP’s 364-day revolving credit facility (the “ETP 364-Day Facility”) previously allowed for unsecured borrowings up to $1.00 billion and matured on November 30, 2018. On October 19, 2018, the ETP 364-Day Facility was amended to extend the maturity date to November 29, 2019. As of September 30, 2018 , the ETP 364-Day Facility had no outstanding borrowings. Bakken Credit Facility In August 2016, ETP and Phillips 66 completed project-level financing of the Bakken pipeline. The $2.50 billion credit facility matures in August 2019 (the “Bakken Credit Facility”). As of September 30, 2018 , the Bakken Credit Facility had $2.50 billion of outstanding borrowings, all of which has been reflected in current maturities of long-term debt on the Partnership’s consolidated balance sheet . The weighted average interest rate on the total amount outstanding as of September 30, 2018 was 3.85% . Sunoco LP Senior Notes and Term Loan On January 23, 2018, Sunoco LP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in aggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the closing of the asset purchase agreement with 7-Eleven to: • redeem in full its existing senior notes, comprised of $800 million in aggregate principal amount of 6.250% senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023; • repay in full and terminate its term loan; • pay all closing costs in connection with the 7-Eleven transaction; • redeem the outstanding Sunoco LP Series A Preferred Units; and • repurchase 17,286,859 Sunoco LP common units owned by ETP. Sunoco LP Credit Facility Sunoco LP maintains a $1.50 billion revolving credit agreement. In July 2018, Sunoco LP amended its revolving credit agreement, including extending the expiration to July 2023 (which may be extended in accordance with the terms of the credit agreement). Borrowings under the amended revolving credit agreement were used to pay off Sunoco LP’s existing revolving credit facility which was entered into in September 2014. As of September 30, 2018 , the Sunoco LP credit facility had $493 million outstanding borrowings and $8 million in standby letters of credit. The unused availability on the revolver at September 30, 2018 was $999 million . USAC Credit Facility USAC currently has a $1.6 billion revolving credit facility, which matures on April 2, 2023 and permits up to $400 million of future increases in borrowing capacity. As of September 30, 2018, USAC had $1.0 billion of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of September 30, 2018 , USAC had $578 million of availability under its credit facility. USAC Senior Notes USAC has outstanding $725 million aggregate principal amount of senior notes that mature on April 1, 2026 . The notes accrue interest from March 23, 2018 at the rate of 6.875% per year. Interest on the notes will be payable semi-annually in arrears on each April 1 and October 1, commencing on October 1, 2018. Compliance with Our Covenants We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2018 . |
Redeemable Noncontrolling Inter
Redeemable Noncontrolling Interest (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Temporary Equity Disclosure [Abstract] | |
Redeemable Noncontrolling Interest [Text Block] | REDEEMABLE NONCONTROLLING INTERESTS Certain redeemable noncontrolling interest in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of September 30, 2018 include (i) a balance of $477 million related to the USAC Preferred Units described below and (ii) a balance of $22 million related to noncontrolling interest holders in one of ETP’s consolidated subsidiaries that have the option to sell their interests to ETP. USAC Series A Preferred Units On April 2, 2018, USAC issued 500,000 USAC Preferred Units at a price of $1,000 per USAC Preferred Unit, for total gross proceeds of $500 million in a private placement. 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 will be convertible into USAC common units at the election of the holders beginning in 2021. 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, at any time on or after the tenth anniversary of the issue date, 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. |
Equity
Equity | 9 Months Ended |
Sep. 30, 2018 | |
Partners' Capital Notes [Abstract] | |
Equity | EQUITY ETE The changes in ETE common units and ETE Series A Convertible Preferred Units during the nine months ended September 30, 2018 were as follows: Number of ETE Series A Convertible Preferred Units Number of Common Units Outstanding at December 31, 2017 329.3 1,079.1 Conversion of ETE Series A Convertible Preferred Units to common units (329.3 ) 79.1 Outstanding at September 30, 2018 — 1,158.2 In October 2018, ETE issued 1.46 billion ETE Common Units in connection with the ETE-ETP Merger. ETE Equity Distribution Program In March 2017, the Partnership entered into an equity distribution agreement relating to at-the-market offerings of its common units with an aggregate offering price up to $1 billion . As of September 30, 2018 , there have been no sales of common units under the equity distribution agreement. ETE Series A Convertible Preferred Units In May 2018, the Partnership converted its 329.3 million Series A Convertible Preferred Units into approximately 79.1 million common units in accordance with the terms of our partnership agreement. ETE Class A Units In connection with the ETE-ETP Merger, the Partnership issued 647,745,099 Class A units (“ETE Class A Units”) representing limited partner interests in the Partnership to LE GP, LLC (“LE GP”), the general partner of ETE. The number of ETE Class A Units issued allows LE GP and its affiliates to retain a voting interest in the Partnership that is identical to their voting interest in the Partnership prior to the completion of the Merger. The ETE Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, ETE’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 ETE Class A Units additional ETE 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 ETE Class A Units are not entitled to distributions and otherwise have no economic attributes. Repurchase Program During the nine months ended September 30, 2018 , ETE did not repurchase any ETE common units under its current buyback program. As of September 30, 2018 , $936 million remained available to repurchase under the current program. Subsidiary Equity Transactions The Parent Company accounts for the difference between the carrying amount of its investment in ETP, Sunoco LP, and USAC and the underlying book value arising from the issuance or redemption of units by ETP, Sunoco LP, and USAC (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the nine months ended September 30, 2018 , we recognized a decrease in partners’ capital of $125 million . ETP Equity Distribution Program During the nine months ended September 30, 2018 , there were no ETP common units issued under ETP’s equity distribution agreements. In connection with the ETE-ETP Merger, the equity distribution program was terminated in October 2018. ETP Distribution Reinvestment Program In July 2017, ETP initiated a new distribution reinvestment plan. During the nine months ended September 30, 2018 , distributions of $57 million were reinvested under ETP’s distribution reinvestment plan. In connection with the ETE-ETP Merger, the distribution reinvestment program was terminated in October 2018. ETP Preferred Units ETP issued 950,000 ETP Series A Preferred Units and 550,000 ETP Series B Preferred Units in November 2017 and has issued additional preferred units in 2018, as discussed below. Subsequent to the ETE-ETP Merger, all of ETP’s Series A, Series B, Series C and Series D Preferred Units remain outstanding. ETP Series C Preferred Units Issuance In April 2018, ETP issued 18 million of its 7.375% ETP Series C Preferred Units at a price of $25 p er unit, resulting in total gross proceeds of $450 million . The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes. Distributions on the ETP 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 ETP 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 ETP Series C Preferred Units are redeemable at ETP’s option on or after May 15, 2023 at a redemption price of $25 per ETP Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. ETP Series D Preferred Units Issuance In July 2018, ETP issued 17.8 million of its 7.625% ETP Series D Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $445 million . The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes. Distributions on the ETP 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 ETP 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 4.378% per annum. The ETP Series D Preferred Units are redeemable at ETP’s option on or after August 15, 2023 at a redemption price of $25 per ETP Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Sunoco LP Common Unit Transactions On February 7, 2018, subsequent to the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million . ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility. Sunoco LP Series A Preferred Units On January 25, 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million . The redemption amount includes the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions. USAC 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 Class B Units The USAC Class B Units, all of which are owned by ETP, are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will 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 will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019. USAC Distribution Reinvestment Program During the six months ended September 30, 2018 , distributions of $0.4 million were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 24,261 USAC common units. Parent Company Cash Distributions Distributions declared and/or paid subsequent to December 31, 2017 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2017 (1) February 8, 2018 February 20, 2018 $ 0.3050 March 31, 2018 (1) May 7, 2018 May 21, 2018 0.3050 June 30, 2018 August 6, 2018 August 20, 2018 0.3050 September 30, 2018 November 8, 2018 November 19, 2018 0.3050 (1) Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forgo their cash distributions on all or a portion of their common units, and in lieu of receiving cash distributions on these common units for each such quarter, such unitholder received Series A Convertible Preferred Units, and (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Series A Convertible Preferred Unit. The quarter ended March 31, 2018 was the final quarter of participation in the plan. Distributions declared and/or paid with respect to our Series A Convertible Preferred Units subsequent to December 31, 2017 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2017 February 8, 2018 February 20, 2018 $ 0.1100 March 31, 2018 May 7, 2018 May 21, 2018 0.1100 ETP Cash Distributions Distributions declared and/or paid by ETP subsequent to December 31, 2017 but prior to the closing of the ETE-ETP Merger as discussed in Note 1 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2017 February 8, 2018 February 14, 2018 $ 0.5650 March 31, 2018 May 7, 2018 May 15, 2018 0.5650 June 30, 2018 August 6, 2018 August 14, 2018 0.5650 Distributions on ETP’s preferred units declared and paid by ETP subsequent to December 31, 2017 were as follows: Period Ended Record Date Payment Date Rate ETP Series A Preferred Units December 31, 2017 February 1, 2018 February 15, 2018 $ 15.451 June 30, 2018 August 1, 2018 August 15, 2018 31.250 ETP Series B Preferred Units December 31, 2017 February 1, 2018 February 15, 2018 16.378 June 30, 2018 August 1, 2018 August 15, 2018 33.125 ETP Series C Preferred Units June 30, 2018 August 1, 2018 August 15, 2018 0.5634 September 30, 2018 November 1, 2018 November 15, 2018 0.4609 ETP Series D Preferred Units September 30, 2018 November 1, 2018 November 15, 2018 0.5931 Sunoco LP Cash Distributions The following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2017 : Quarter Ended Record Date Payment Date Rate December 31, 2017 February 6, 2018 February 14, 2018 $ 0.8255 March 31, 2018 May 7, 2018 May 15, 2018 0.8255 June 30, 2018 August 7, 2018 August 15, 2018 0.8255 September 30, 2018 November 6, 2018 November 14, 2018 0.8255 USAC Cash Distributions Subsequent to the USAC Transactions described in Note 2, ETE and its wholly-owned subsidiaries own an aggregate 20,466,912 USAC common units, and ETP owns 19,191,351 USAC common units and 6,397,965 USAC Class B units. As of September 30, 2018 , USAC had 89,966,676 common units outstanding. USAC currently has a non-economic general partner interest and no outstanding incentive distribution rights. The following are distributions declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018: Quarter Ended Record Date Payment Date Rate March 31, 2018 May 1, 2018 May 11, 2018 $ 0.5250 June 30, 2018 July 30, 2018 August 10, 2018 0.5250 September 30, 2018 October 29, 2018 November 09, 2018 0.5250 Accumulated Other Comprehensive Income The following table presents the components of AOCI, net of tax: September 30, 2018 December 31, 2017 Available-for-sale securities (1) $ 6 $ 8 Foreign currency translation adjustment (5 ) (5 ) Actuarial loss related to pensions and other postretirement benefits (7 ) (5 ) Investments in unconsolidated affiliates, net 14 5 Subtotal 8 3 Amounts attributable to noncontrolling interest (8 ) (3 ) Total AOCI, net of tax $ — $ — (1) Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities , which resulted in the reclassification of $2 million from ETP’s accumulated other comprehensive income related to available-for-sale securities to ETP’s common unitholders. The amount is reflected as a change in noncontrolling interest in the Partnership’s consolidated financial statements. |
Income Taxes (Notes)
Income Taxes (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | INCOME TAXES The Partnership’s effective tax rate differs 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. For the three and nine months ended September 30, 2018 , the Partnership’s income tax benefit also reflected $113 million and $164 million , respectively, of deferred benefit adjustments as the result of a state statutory rate reduction. Sunoco, Inc. historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the Internal Revenue Service (“IRS”) excluding these government incentive payments from federal taxable income. The IRS denied the amended returns and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and the Federal Circuit affirmed the CFC’s ruling on November 1, 2018. Sunoco, Inc. is considering seeking further review of this decision. Due to the uncertainty surrounding the litigation, a reserve of $530 million was previously established for the full amount of the pending refund claims. |
Regulatory Matters, Commitments
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | 9 Months Ended |
Sep. 30, 2018 | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES FERC Audit In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The FERC approved an audit report in October 2018. In response to the findings in the audit report, the Company expects to make certain changes to its processes, policies and procedures; however, the Company does not expect the findings to result in any changes to its financial statements. Commitments In the normal course of business, ETP 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. ETP 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. ETP’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: Three Months Ended Nine Months Ended 2018 2017 2018 2017 Rental expense (1) $ 43 $ 49 $ 117 $ 130 Less: Sublease rental income (11 ) (7 ) (28 ) (19 ) Rental expense, net $ 32 $ 42 $ 89 $ 111 (1) Includes contingent rentals totaling $1 million and $3 million for three months ended September 30, 2018 and 2017 , respectively and $3 million and $13 million for the nine months ended September 30, 2018 and 2017 , respectively. 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. Dakota Access Pipeline On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access, LLC (“Dakota Access”) to make two crossings of the Missouri River in North Dakota. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River. On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“the Court”) against the USACE and challenged the legality of these permits and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case was pending, which the court denied on September 9, 2016. Dakota Access intervened in the case. The Cheyenne River Sioux Tribe (“CRST”) also intervened. The SRST filed an amended complaint and added claims based on treaties between the SRST and the CRST and the United States and statutes governing the use of government property. In February 2017, in response to a presidential memorandum, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. The CRST moved for a preliminary injunction and temporary restraining order (“TRO”) to block operation of the pipeline, which was denied, and raised claims based on the religious rights of the CRST. The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes. On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court concluded that the USACE had not violated trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. On May 3, 2018, the District Court ordered the USACE to file a status report by June 8, 2018 informing the Court when the USACE expects the remand process to be complete. On June 8, 2018, the USACE filed a status report stating that they will conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they will need until August 31, 2018 to finish the remand process. On August 31, 2018, the USACE informed the Court that it had completed the remand process and that it had determined that the three issues remanded by the Court had been correctly decided. The USACE indicated that a document detailing its remand analysis would be filed after a “confidentiality review.” Following the submission by USACE of its detailed remand analysis, it is expected that the Court will make a determination regarding the three discrete issues covered by the remand order. On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent third-party to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The assessment report was filed with the Court. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access filed the revised plan with the Court. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first and second reports were filed with the court on December 29, 2017 and February 28, 2018, respectfully. In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. On March 19, 2018, the District Court denied YST’s motion for partial summary judgment and instead granted judgment in favor of Dakota Access pipeline and the USACE on the claims raised in YST’s motion. The Court concluded that YST’s NHPA claims are moot because construction of the pipeline is complete and that the government’s review process did not violate NEPA or the various treaties cited by the YST. On February 8, 2018, the Court docketed a motion by CRST to “compel meaningful consultation on remand.” SRST then made a similar motion for “clarification re remand process and remand conditions.” The motions seek an order from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access pipeline and the USACE opposed both motions. On April 16, 2018, the Court denied both motions. While ETP believes that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome. ETP cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project. Mont Belvieu Incident On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) 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 have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses. MTBE Litigation Sunoco, Inc. and/or Sunoco, Inc. (R&M) (now known as Sunoco (R&M), LLC) 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 September 30, 2018 , Sunoco, Inc. is a defendant in six cases, including one case each initiated by the States of Maryland, Vermont 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 Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. In late July 2018, the Court in the Vermont matter denied Plaintiff’s motion to amend its complaint to add specific allegations regarding some of the sites the court previously dismissed. In early September 2018, Sunoco, Inc. participated in a defense group effort to resolve the case without further litigation. A settlement in principle to resolve the remaining statewide Vermont Case was reached in September 2018. 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 Purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency-ETP merger (the “Regency Merger”). All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint 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; ETE, ETP, ETP GP, and the members of Regency’s board of directors (“Defendants”). The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC (the “Regency Defendants”). On March 6, 2018, the Regency Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint. Trial is currently set for September 23-27, 2019. The Regency Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger. Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million , consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. ETP’s petition for review remains under consideration by the Texas Supreme Court. ETE-ETP Merger Litigation On September 17, 2018, William D. Warner (“Plaintiff”), a purported ETP unitholder, filed a putative class action asserting violations of various provisions of the Securities Exchange Act of 1934 and various rules promulgated thereunder in connection with the ETE-ETP Merger against ETP, Kelcy L. Warren, Michael K. Grimm, Marshall S. McCrea, Matthew S. Ramsey, David K. Skidmore, and W. Brett Smith (“Defendants”). Plaintiff specifically alleges that the Form S-4 Registration Statement issued in connection with the ETE-ETP Merger omits and/or misrepresents material information. Defendants believe the allegations have no merit and intend to defend vigorously against them. On October 26, 2018, Plaintiff and Defendants entered into a stipulation staying Defendants’ response deadlines until the designation of a lead plaintiff/lead counsel structure in accordance with the Private Securities Litigation Reform Act. Litigation Filed By or Against Williams On April 6, 2016, The Williams Companies, Inc. (“Williams”) filed a complaint against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the issuance of the Partnership’s Series A Convertible Preferred Units (the “Issuance”) and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance. On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the ETE-Williams merger agreement (the “Merger Agreement”) by (a) blocking ETE’s attempts to complete a public offering of the Series A Convertible Preferred Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause. On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”) (the “Second Delaware Williams Litigation”). In general, Williams alleged that 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) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions. ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016. After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee, and Defendants filed amended counterclaims and affirmative defenses. In response, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June trial, and as a result, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending. On December 1, 2017, the Court issued a Memorandum Opinion granting Williams’ motion to dismiss in part and denying Williams’ motion to dismiss in part. Trial is set for May 20, 2019. Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them. Unitholder Litigation Relating to the Issuance On April 12, 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in the Delaware Court of Chancery (the “Issuance Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, later joined the Issuance Litigation. The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to holders of the Series A Convertible Preferred Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance. On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance. The matter was tried in front of Vice Chancellor Glasscock on February 19-21, 2018. Post-trial arguments were heard on April 16, 2018. In a post-trial opinion dated May 17, 2018, the Court found that one provision of the Issuance breached ETE’s partnership agreement but that this breach caused no damages. The Court denied Plaintiffs’ requests for injunctive relief and declined to award damages other than nominal damages. Plaintiffs subsequently filed a motion seeking $8.5 million in attorneys’ fees and expenses from the Issuance Defendants, which the Issuance Defendants have opposed. The Issuance Defendants cannot predict the outcome of the Issuance Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendants predict the amount of time and expense that will be required to resolve the Issuance Litigation. The Issuance Defendants believe the Issuance Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Issuance. Bayou Bridge On January 11, 2018, environmental groups and a trade association filed suit against the USACE in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the USACE’s issuance of permits authorizing the construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. They asked the district court to vacate these permits and to enjoin construction of the project through the Basin until the USACE corrects alleged deficiencies in its decision-making process. ETP, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26, 2018. On March 27, 2018, Bayou Bridge filed an answer to the complaint. On January 29, 2018, Plaintiffs filed motions for a preliminary injunction and TRO. United States District Court Judge Shelly Dick denied the TRO on January 30, 2018, but subsequently granted the preliminary injunction on February 23, 2018. On February 26, 2018, Bayou Bridge filed a notice of appeal and a motion to stay the February 23, 2018 preliminary injunction order. On February 27, 2018, Judge Dick issued an opinion that clarified her February 23, 2018 preliminary injunction order and denied Bayou Bridge’s February 26, 2018 motion to stay as moot. On March 1, 2018, Bayou Bridge filed a new notice of appeal and motion to stay the February 27, 2018 preliminary injunction order in the district court. On March 5, 2018, the district court denied the March 1, 2018 motion to stay the February 27, 2018 order. On March 2, 2018, Bayou Bridge filed a motion to stay the preliminary injunction in the Fifth Circuit. On March 15, 2018, the Fifth Circuit granted a stay of injunction pending appeal and found that Bayou Bridge “is likely to succeed on the merits of its claim that the district court abused its discretion in granting a preliminary injunction.” Oral arguments were heard on the merits of the appeal, that is, whether the district court erred in granting the preliminary injunction in the Fifth Circuit on April 30, 2018. The district court has stayed the merits case pending decision of the Fifth Circuit. On May 10, 2018, the District Court stayed the litigation pending a decision from the Fifth Circuit. On July 6, 2018, the Fifth Circuit vacated the Preliminary Injunction and remanded the case back to the District Court. Construction is ongoing. On August 14, 2018, Plaintiffs sought leave of court to amend their complaint to add an “as applied” challenge to the USACE’s application of the Louisiana Rapid Assessment Method to Bayou Bridge’s permits. Defendants’ filed motions in opposition on September 11, 2018. On September 11, 2018, Plaintiffs filed a motion for partial summary judgment on the issue of the USACE’s analysis of the risks of an oil spill once the pipeline is in operation. At an October 2, 2018 scheduling conference, the USACE agreed to lodge the administrative record for Plaintiff’s original complaint, which it has done. Summary judgment briefing will be concluded by the Spring of 2019. Rover On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and Pretec Directional Drilling, LLC (“Pretec”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. Laney Directional Drilling Co., Atlas Trenchless, LLC, Mears Group, Inc., D&G Directional Drilling, Inc. d/b/a D&G Directional Drilling, LLC, and B&T Directional Drilling, Inc. (collectively, with Rover and Pretec, “Defendants”) were added as defendants on April 17, 2018 and July 18, 2018. Ohio EPA alleges that the Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the Defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that the Defendants caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Rover and other Defendants filed several motions to dismiss and Ohio EPA filed a motion in opposition. In January 2018, Ohio EPA sent a letter to the FERC to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the Rover Pipeline construction. Rover sent a January 24 response to the FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting its drilling operations in accordance with specified procedures that had been approved by the FERC and reviewed by the Ohio EPA. In addition, although the HDD operations were crossing the same resource as that which led to an inadvertent release of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concern that the drilling fluids could deprive organisms in the wetland of oxygen. Rover, however, has now fully remediated the site, a fact with which Ohio EPA concurs. Other Litigation and Contingencies 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 of September 30, 2018 and December 31, 2017 , accruals of approximately $62 million and $53 million , respectively, were reflected on our consolidated balance sheets related to these contingent obligations. 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. 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 prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. On April 25, 2018, and as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against Sunoco Pipeline L.P. (“SPLP”) before the Pennsylvania Public Utility Commission (“PUC”). Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1,” “ME2” or “ME2x”) in West Whiteland Township (“the Township”) are unreasonable, unsafe, inadequate, and insufficient for, among other reasons, selecting an improper and unsafe route through densely populated portions of the Township with homes, schools, and infrastructure and causing inadvertent returns and sinkholes during construction because of unstable geology in the Township; (ii) SPLP failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increases the risk of damage to the existing co-located ME1 pipeline; and (iv) ME1, ME2 and ME2x are not public utility facilities. Based on these allegations, Senator Dinniman’s Complaint seeks emergency relief by way of an order (i) prohibiting construction of ME2 and ME2x in the Township; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and (ii) prohibiting the construction of ME2 and ME2x and the operation of ME1 until SPLP fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in which they sit; (iv) requiring SPLP to release to the public its written integrity management plan and risk analysis for these pipelines; and (v) finding that these pipelines are not public utility facilities. In short, the relief, if granted, would continue the suspension of operation of ME1 and suspend further construction of ME2 and ME2x in the Township. Following a hearing on May 7, 2018 and 10, 2018, Administrative Law Judge Elizabeth H. Barnes (“ALJ”) issued an Order on May 24, 2018 that granted Senator Dinniman’s petition for interim emergency relief and required SPLP to shut down ME1, to discontinue construction of ME2 and ME2x within the Township, and required SPLP to provide various types of information and perform various geotechnical |
Revenue (Notes)
Revenue (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue [Abstract] | |
Revenue from Contract with Customer [Text Block] | REVENUE The following disclosures discuss the Partnership’s revised revenue recognition policies upon the adoption of ASU 2014-09 on January 1, 2018, as discussed in Note 1 . These policies were applied to the current period only, and the amounts reflected in the Partnership’s consolidated financial statements for the three and nine months ended September 30, 2017 , were recorded under the Partnership’s previous accounting policies. Disaggregation of revenue The major types of revenue within our reportable segment, are as follows: • Investment in ETP • intrastate transportation and storage • interstate transportation and storage • midstream • NGL and refined products transportation and services • crude oil transportation and services • all other • Investment in Sunoco LP • fuel distribution and marketing • all other • Investment in USAC • contract operations • retail parts and services • station installations • Investment in Lake Charles LNG • terminal services Note 15 depicts the disaggregation of revenue amounts by type for each of our reportable segments, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017. ETP’s intrastate transportation and storage revenue ETP’s intrastate transportation and storage 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. ETP’s interstate transportation and storage revenue ETP’s interstate transportation and storage 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 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 withdrawn 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. ETP’s midstream revenue ETP’s midstream revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported for our customers. The various types of revenue contracts our midstream operations enter 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, processes the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent amount 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 retains 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 NGL’s 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 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 statement of operations; therefore, identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream operations 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. ETP’s NGL and refined products transportation and services revenue ETP’s NGL and refined products 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. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of our NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606. ETP’s crude oil transportation and services revenue ETP’s crude oil operations provide 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. 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. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of our crude oil at market rates. These contracts were not affected by ASC 606. ETP’s all other revenue ETP’s other operations primarily include 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. There were no material changes to the manner in which revenues related to these operations are recorded under the new standard. 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 determine 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. USAC’s station installations revenue USAC’s revenue from station installations is earned on stations USAC builds on behalf of, and sell to, its customers and such revenue is recognized over time as services are provided. A station typically consists of compressor equipment combined with other equipment ancillary to compression, such as slug catchers, pipe racks, tanks, dehydration units, valves, and control rooms, which together assist in the treating, processing, pressurization and transportation of natural gas. USAC’s performance enhances an asset that the customer controls and does not create an asset with alternative use to USAC. Revenue is recognized over time based on the progress-toward-completion method and progress is measured using the efforts-expended input method. In applying the efforts-expended input method, USAC uses the percentage of total completed workflows to date relative to estimated total workflows to determine the amount of revenue and profit to recognize for each contract. The amount of consideration USAC receives and revenue it recognizes varies in accordance with each contractual agreement negotiated with its customers. The progress-toward-completion method of revenue recognition requires USAC to make estimates of contract revenues and costs to complete its projects. In making such estimates, management judgments are required to evaluate significant assumptions including the cost of materials and labor, expected labor productivity, the impact of potential variances in schedule completion, the amount of net contract revenues and the impact of any penalties, claims, change orders, or performance incentives. USAC’s payment terms vary in accordance with each contractual agreement negotiated with its customers. The term between invoicing and when payment is due is not significant. USAC retains the right to payment for performance completed to date at any point during the contract term. There are no material obligations for returns, refunds, or warranties. Lake Charles LNG revenue 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. 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 fee for a right to use our assets, 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. The Partnership recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license. As of September 30, 2018 , the Partnership had $383 million in deferred revenues representing the current value of our future performance obligations. The balances of receivables from contracts with customers listed in the table below include both current trade receivables and long-term receivables, net of allowance for doubtful accounts. The allowance for receivables represents Sunoco LP’s best estimate of the probable losses associated with potential customer defaults. Sunoco LP determines the allowance based on historical experience and on a specific identification basis. The opening and closing balances of Sunoco LP’s contract assets and contract liabilities are as follows: Balance at January 1, 2018 Balance at September 30, 2018 Increase Contract Balances Contract Asset $ 51 $ 66 $ 15 Accounts receivable from contracts with customers 445 582 137 Contract Liability 1 1 — The amount of revenue recognized for the three and nine months ended September 30, 2018 that was included in the deferred revenue liability balance as of January 1, 2018 was $12 million and $75 million , respectively. 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 the service is provided. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contacts, 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 September 30, 2018 , the aggregate amount of transaction price |
Derivative Assets And Liabiliti
Derivative Assets And Liabilities | 9 Months Ended |
Sep. 30, 2018 | |
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 operations and operational gas sales on our interstate transportation and storage operations. 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 operations 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 and transportation costs in our retail marketing operations. 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 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 operations 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 operations, 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: September 30, 2018 December 31, 2017 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures 358 2018-2019 1,078 2018 Basis Swaps IFERC/NYMEX (1) 69,685 2018-2020 48,510 2018-2020 Options – Puts (17,273 ) 2019 13,000 2018 Power (Megawatt): Forwards 429,720 2018-2019 435,960 2018-2019 Futures 309,123 2018-2019 (25,760 ) 2018 Options — Puts 157,435 2018-2019 (153,600 ) 2018 Options — Calls 321,240 2018-2019 137,600 2018 (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (7,705 ) 2018-2021 4,650 2018-2020 Swing Swaps IFERC 69,145 2018-2019 87,253 2018-2019 Fixed Swaps/Futures (1,834 ) 2018-2020 (4,390 ) 2018-2019 Forward Physical Contracts (54,151 ) 2018-2020 (145,105 ) 2018-2020 NGL (MBbls) – Forwards/Swaps (4,937 ) 2019 (2,493 ) 2018-2019 Crude (MBbls) – Forwards/Swaps 35,228 2018-2019 9,237 2018-2019 Refined Products (MBbls) – Futures (1,507 ) 2018-2019 (3,901 ) 2018-2019 Corn (thousand bushels) (3,100 ) 2018-2019 1,870 2018 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (21,475 ) 2018-2019 (39,770 ) 2018 Fixed Swaps/Futures (21,475 ) 2018-2019 (39,770 ) 2018 Hedged Item — Inventory 21,475 2018-2019 39,770 2018 (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 anticipated debt issuances. The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: Notional Amount Outstanding Term Type (1) September 30, 2018 December 31, 2017 July 2018 (2) Forward-starting to pay a fixed rate of 3.76% and receive a floating rate $ — $ 300 July 2019 (2) Forward-starting to pay a fixed rate of 3.56% and receive a floating rate 400 300 July 2020 (2) Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400 400 July 2021 (2) Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400 — December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 1,200 March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300 300 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date. Credit Risk 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 our 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, we may at times require collateral under certain circumstances to mitigate credit risk as necessary. We also implements the use of industry standard commercial agreements which allow for the netting of positive and negative 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 counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, motor fuel distributors, municipalities, utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic factors or regulatory changes that could impact its 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. We have maintenance margin deposits with certain counterparties in the OTC market, primarily 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 September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ — $ 14 $ (6 ) $ (2 ) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 477 262 (537 ) (281 ) Commodity derivatives 126 45 (334 ) (58 ) Interest rate derivatives — — (97 ) (219 ) 603 307 (968 ) (558 ) Total derivatives $ 603 $ 321 $ (974 ) $ (560 ) 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 September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 Derivatives without offsetting agreements Derivative liabilities $ — $ — $ (97 ) $ (219 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 126 45 (334 ) (58 ) Broker cleared derivative contracts Other current assets (liabilities) 477 276 (543 ) (283 ) Total gross derivatives 603 321 (974 ) (560 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (29 ) (21 ) 29 21 Counterparty netting Other current assets (liabilities) (477 ) (263 ) 477 263 Total net derivatives $ 97 $ 37 $ (468 ) $ (276 ) We disclose the non-exchange traded financial derivative instruments as price risk management 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 date. The following tables summarize the amounts recognized with respect to our derivative financial instruments: Location of Gain Recognized in Income on Derivatives Amount of Gain Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Three Months Ended Nine Months Ended 2018 2017 2018 2017 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ — $ 2 $ 9 $ 4 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives Three Months Ended Nine Months Ended 2018 2017 2018 2017 Derivatives not designated as hedging instruments: Commodity derivatives — Trading Cost of products sold $ 3 $ (5 ) $ 36 $ 21 Commodity derivatives — Non-trading Cost of products sold 21 (25 ) (345 ) (6 ) Interest rate derivatives Gains (losses) on interest rate derivatives 45 (8 ) 117 (28 ) Embedded derivatives Other, net — — — 1 Total $ 69 $ (38 ) $ (192 ) $ (12 ) |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Sep. 30, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | RELATED PARTY TRANSACTIONS Revenues reported in our consolidated statements of operations included sales with affiliates of $103 million and $105 million during the three months ended September 30, 2018 and 2017 , respectively, and $325 million and $201 million during the nine months ended September 30, 2018 and 2017 , respectively. |
Reportable Segments
Reportable Segments | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting [Abstract] | |
Reportable Segments | REPORTABLE SEGMENTS Our financial statements reflect the following reportable business segments: • Investment in ETP, including the consolidated operations of ETP; • Investment in Sunoco LP, including the consolidated operations of Sunoco LP; • Investment in USAC, including the consolidated operations of USAC; • Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and • Corporate and Other, including the following: • activities of the Parent Company; and • the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. The Investment in USAC segment reflects the results of USAC beginning April 2018, the date that ETE obtained control of USAC. Also beginning April 2018, ETP holds an equity method investment in USAC, the equity in earnings from which is eliminated in ETE’s consolidated financial statements. The CDM entities were consolidated subsidiaries of ETP prior to April 2018 and are consolidated subsidiaries of USAC beginning April 2018. Therefore, the results of the CDM entities are included in the Investment in ETP segment prior to April 2018 and in the Investment in USAC segment thereafter. We define Segment Adjusted EBITDA as 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, non-cash impairment charges, losses on extinguishments of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. The following tables present financial information by segment: Three Months Ended Nine Months Ended 2018 2017* 2018 2017* Segment Adjusted EBITDA: Investment in ETP $ 2,329 $ 1,784 $ 6,261 $ 4,774 Investment in Sunoco LP 208 199 457 574 Investment in USAC 90 — 185 — Investment in Lake Charles LNG 43 43 131 131 Corporate and Other (9 ) (3 ) (17 ) (25 ) Adjustments and Eliminations (84 ) (74 ) (176 ) (211 ) Total 2,577 1,949 6,841 5,243 Depreciation, depletion and amortization (750 ) (642 ) (2,109 ) (1,877 ) Interest expense, net of interest capitalized (535 ) (490 ) (1,511 ) (1,440 ) Impairment losses — (10 ) — (99 ) Gains (losses) on interest rate derivatives 45 (8 ) 117 (28 ) Non-cash compensation expense (27 ) (29 ) (82 ) (76 ) Unrealized gains (losses) on commodity risk management activities 97 (76 ) (255 ) 22 Gains on disposal of assets 18 5 14 — Losses on extinguishments of debt — — (106 ) (25 ) Inventory valuation adjustments (7 ) 50 50 8 Equity in earnings of unconsolidated affiliates 87 92 258 228 Adjusted EBITDA related to unconsolidated affiliates (179 ) (205 ) (503 ) (554 ) Adjusted EBITDA related to discontinued operations — (76 ) 25 (179 ) Other, net 15 24 45 76 Income from continuing operations before income tax (expense) benefit 1,341 584 2,784 1,299 Income tax (expense) benefit from continuing operations 52 157 (6 ) 86 Income from continuing operations 1,393 741 2,778 1,385 Income (loss) from discontinued operations, net of income taxes (2 ) 17 (265 ) (187 ) Net income $ 1,391 $ 758 $ 2,513 $ 1,198 * As adjusted. See Note 1. September 30, 2018 December 31, 2017 Assets: Investment in ETP $ 79,156 $ 77,965 Investment in Sunoco LP 5,148 8,344 Investment in USAC 3,814 — Investment in Lake Charles LNG 1,746 1,646 Corporate and Other 625 598 Adjustments and Eliminations (2,302 ) (2,307 ) Total assets $ 88,187 $ 86,246 Three Months Ended Nine Months Ended 2018 2017* 2018 2017* Revenues: Investment in ETP: Revenues from external customers $ 9,538 $ 6,876 $ 26,921 $ 20,168 Intersegment revenues 103 97 410 276 9,641 6,973 27,331 20,444 Investment in Sunoco LP: Revenues from external customers 4,760 3,058 13,114 8,755 Intersegment revenues 1 6 3 9 4,761 3,064 13,117 8,764 Investment in USAC: Revenues from external customers 166 — 331 — Intersegment revenues 3 — 5 — 169 — 336 — Investment in Lake Charles LNG: Revenues from external customers 50 49 148 148 Adjustments and Eliminations (107 ) (102 ) (418 ) (284 ) Total revenues $ 14,514 $ 9,984 $ 40,514 $ 29,072 * As adjusted. See Note 1. The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP, Sunoco LP, USAC and Lake Charles LNG. Investment in ETP Three Months Ended Nine Months Ended 2018 2017* 2018 2017* Intrastate transportation and storage $ 846 $ 729 $ 2,424 $ 2,196 Interstate transportation and storage 390 220 1,026 652 Midstream 537 665 1,571 1,863 NGL and refined products transportation and services 2,948 1,989 7,878 5,874 Crude oil transportation and services 4,422 2,714 12,942 7,749 All Other 498 656 1,490 2,110 Total revenues 9,641 6,973 27,331 20,444 Less: Intersegment revenues 103 97 410 276 Revenues from external customers $ 9,538 $ 6,876 $ 26,921 $ 20,168 * As adjusted. See Note 1. The amounts included in ETP’s NGL and refined products transportation and services operation and the crude oil transportation and services operation have been retrospectively adjusted as a result of the Sunoco Logistics Merger. Investment in Sunoco LP Three Months Ended Nine Months Ended 2018 2017 2018 2017 Fuel distribution and marketing $ 4,494 $ 2,467 $ 11,983 $ 7,082 All other 267 597 1,134 1,682 Total revenues 4,761 3,064 13,117 8,764 Less: Intersegment revenues 1 6 3 9 Revenues from external customers $ 4,760 $ 3,058 $ 13,114 $ 8,755 Investment in USAC Three Months Ended Nine Months Ended 2018 2017 2018 2017 Contract operations $ 163 $ — $ 323 $ — Retail parts and services 5 — 11 — Station installations revenue 1 — 2 — Total revenues 169 — 336 — Less: Intersegment revenues 3 — 5 — Revenues from external customers $ 166 $ — $ 331 $ — USAC’s revenues for all periods presented were related to the compression services business. Investment in Lake Charles LNG Lake Charles LNG’s revenues for all periods presented were related to LNG terminalling. |
Supplemental Financial Statemen
Supplemental Financial Statement Information | 9 Months Ended |
Sep. 30, 2018 | |
Supplemental Financial Statement Information | |
Supplemental Financial Statement Information | SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis: BALANCE SHEETS (unaudited) September 30, 2018 December 31, 2017 ASSETS Current assets: Cash and cash equivalents $ 1 $ 1 Accounts receivable from related companies 100 65 Other current assets 1 1 Total current assets 102 67 Property, plant and equipment, net 27 27 Advances to and investments in unconsolidated affiliates 6,045 6,082 Goodwill 9 9 Other non-current assets, net 7 8 Total assets $ 6,190 $ 6,193 LIABILITIES AND PARTNERS’ DEFICIT Current liabilities: Accounts payable to related companies $ 42 $ — Interest payable 78 66 Accrued and other current liabilities 9 4 Total current liabilities 129 70 Long-term debt, less current maturities 6,415 6,700 Long-term notes payable – related companies 747 617 Other non-current liabilities 2 2 Commitments and contingencies Partners’ deficit: Limited Partners: Series A Convertible Preferred Units — 450 Common Unitholders (1,099 ) (1,643 ) General Partner (4 ) (3 ) Total partners’ deficit (1,103 ) (1,196 ) Total liabilities and partners’ deficit $ 6,190 $ 6,193 STATEMENTS OF OPERATIONS (unaudited) Three Months Ended Nine Months Ended 2018 2017 2018 2017 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES $ (9 ) $ (3 ) $ (20 ) $ (25 ) OTHER INCOME (EXPENSE): Interest expense, net (89 ) (88 ) (265 ) (257 ) Equity in earnings of unconsolidated affiliates 469 343 1,359 1,012 Losses on extinguishments of debt — — — (25 ) Other, net — — 3 (2 ) NET INCOME 371 252 1,077 703 Convertible Unitholders’ interest in income — 11 33 25 General Partner’s interest in net income 1 1 3 2 Limited Partners’ interest in net income $ 370 $ 240 $ 1,041 $ 676 STATEMENTS OF CASH FLOWS (unaudited) Nine Months Ended 2018 2017 NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 993 $ 620 CASH FLOWS FROM INVESTING ACTIVITIES Contributions to unconsolidated affiliate (250 ) (861 ) Capital expenditures — (1 ) Contributions in aid of construction costs — 7 Sunoco LP Series A Preferred Units redemption 303 — Net cash provided by (used in) investing activities 53 (855 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from borrowings 413 2,116 Principal payments on debt (703 ) (1,795 ) Proceeds from affiliate 130 131 Distributions to partners (886 ) (752 ) Units issued for cash — 568 Debt issuance costs — (35 ) Net cash provided by (used in) financing activities (1,046 ) 233 CHANGE IN CASH AND CASH EQUIVALENTS — (2 ) CASH AND CASH EQUIVALENTS, beginning of period 1 2 CASH AND CASH EQUIVALENTS, end of period $ 1 $ — |
Operations And Organization Acc
Operations And Organization Accounting policy (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Basis of Accounting, Policy [Policy Text Block] | Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 , filed with the SEC on February 23, 2018 . In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. For prior periods reported herein, certain other prior period amounts were reclassified to conform to the 2018 presentation. Additionally, there are reclassifications of certain balances to assets and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity. |
Accounting Changes and Error Corrections [Text Block] | Inventory Accounting Change During the fourth quarter of 2017, we elected to change our method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined product and NGL associated with the legacy Sunoco Logistics business. Our management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity |
Use of Estimates, Policy [Policy Text Block] | Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates. |
New Accounting Pronouncements, Policy [Policy Text Block] | Recent Accounting Pronouncements ASU 2016-02 In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report information about the amount, timing, and uncertainty of cash flows arising from a lease. The update requires lessees to record virtually all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the existing lease guidance in Topic 840. The Partnership plans to elect the package of transition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment to retained earnings. The Partnership has performed several procedures to evaluate the impact of the adoption of this standard on the financial statements and disclosures and address the implications of Topic 842 on future lease arrangements. The procedures include reviewing all forms of leases, performing a completeness assessment over the lease population, establishing processes and controls to timely identify new and modified lease agreements, educating its employees on these new processes and controls and implementing a third-party supported lease accounting information system to account for our leases in accordance with the new standard. However, we are still in the process of quantifying this impact. We expect that upon adoption most of the Partnership’s lease commitments will be recognized as right of use assets and lease obligations. ASU 2017-12 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. ASU 2018-02 In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income , which allows a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material. |
Cash And Cash Equivalents Cash
Cash And Cash Equivalents Cash and Cash Equivalents (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Cash and Cash Equivalents [Abstract] | |
Cash and Cash Equivalents, Unrestricted Cash and Cash Equivalents, Policy [Policy Text Block] | 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. |
Inventories Inventories (Polici
Inventories Inventories (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Inventory Disclosure [Abstract] | |
Inventory, Policy [Policy Text Block] | We utilize commodity derivatives to manage price volatility associated with its natural gas inventories. 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. USAC’s inventory consists of serialized and non-serialized parts used primarily in the repair of compression units. All inventory is stated at the lower of cost or net realizable value. The cost of serialized parts inventory is determined using the specific identification cost method, while the cost of non-serialized parts inventory is determined using the weighted average cost method. Purchases of these assets are considered operating activities on the Consolidated Statements of Cash Flows. |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value Measurements (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurement, Policy [Policy Text Block] | 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 consolidated debt obligations as of September 30, 2018 were $45.54 billion and $44.77 billion , respectively. As of December 31, 2017 , the aggregate fair value and carrying amount of our consolidated debt obligations were $45.62 billion and $44.08 billion , respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs used for similar liabilities. We have commodity derivatives and interest rate derivatives 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 nine months ended September 30, 2018 , no transfers were made between any levels within the fair value hierarchy. |
Equity Equity (Policies)
Equity Equity (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Equity [Abstract] | |
Consolidation, Subsidiary Stock Issuances, Policy [Policy Text Block] | Subsidiary Equity Transactions The Parent Company accounts for the difference between the carrying amount of its investment in ETP, Sunoco LP, and USAC and the underlying book value arising from the issuance or redemption of units by ETP, Sunoco LP, and USAC (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the nine months ended September 30, 2018 , we recognized a decrease in partners’ capital of $125 million . |
Revenue Revenue (Policies)
Revenue Revenue (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue Recognition, Revenue Reductions [Policy Text Block] | 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 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 the Sunoco LP recognized for the three and nine months ended September 30, 2018 was $4 million and $10 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. |
Revenue Recognition, Policy [Policy Text Block] | Disaggregation of revenue The major types of revenue within our reportable segment, are as follows: • Investment in ETP • intrastate transportation and storage • interstate transportation and storage • midstream • NGL and refined products transportation and services • crude oil transportation and services • all other • Investment in Sunoco LP • fuel distribution and marketing • all other • Investment in USAC • contract operations • retail parts and services • station installations • Investment in Lake Charles LNG • terminal services Note 15 depicts the disaggregation of revenue amounts by type for each of our reportable segments, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017. ETP’s intrastate transportation and storage revenue ETP’s intrastate transportation and storage 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. ETP’s interstate transportation and storage revenue ETP’s interstate transportation and storage 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 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 withdrawn 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. ETP’s midstream revenue ETP’s midstream revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported for our customers. The various types of revenue contracts our midstream operations enter 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, processes the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent amount 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 retains 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 NGL’s 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 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 statement of operations; therefore, identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream operations 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. ETP’s NGL and refined products transportation and services revenue ETP’s NGL and refined products 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. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of our NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606. ETP’s crude oil transportation and services revenue ETP’s crude oil operations provide 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. 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. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of our crude oil at market rates. These contracts were not affected by ASC 606. ETP’s all other revenue ETP’s other operations primarily include 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. There were no material changes to the manner in which revenues related to these operations are recorded under the new standard. 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 determine 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. USAC’s station installations revenue USAC’s revenue from station installations is earned on stations USAC builds on behalf of, and sell to, its customers and such revenue is recognized over time as services are provided. A station typically consists of compressor equipment combined with other equipment ancillary to compression, such as slug catchers, pipe racks, tanks, dehydration units, valves, and control rooms, which together assist in the treating, processing, pressurization and transportation of natural gas. USAC’s performance enhances an asset that the customer controls and does not create an asset with alternative use to USAC. Revenue is recognized over time based on the progress-toward-completion method and progress is measured using the efforts-expended input method. In applying the efforts-expended input method, USAC uses the percentage of total completed workflows to date relative to estimated total workflows to determine the amount of revenue and profit to recognize for each contract. The amount of consideration USAC receives and revenue it recognizes varies in accordance with each contractual agreement negotiated with its customers. The progress-toward-completion method of revenue recognition requires USAC to make estimates of contract revenues and costs to complete its projects. In making such estimates, management judgments are required to evaluate significant assumptions including the cost of materials and labor, expected labor productivity, the impact of potential variances in schedule completion, the amount of net contract revenues and the impact of any penalties, claims, change orders, or performance incentives. USAC’s payment terms vary in accordance with each contractual agreement negotiated with its customers. The term between invoicing and when payment is due is not significant. USAC retains the right to payment for performance completed to date at any point during the contract term. There are no material obligations for returns, refunds, or warranties. Lake Charles LNG revenue 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. |
Revenue Recognition, Deferred Revenue [Policy Text Block] | 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 fee for a right to use our assets, 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. The Partnership recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license. As of September 30, 2018 , the Partnership had $383 million in deferred revenues representing the current value of our future performance obligations. The balances of receivables from contracts with customers listed in the table below include both current trade receivables and long-term receivables, net of allowance for doubtful accounts. The allowance for receivables represents Sunoco LP’s best estimate of the probable losses associated with potential customer defaults. Sunoco LP determines the allowance based on historical experience and on a specific identification basis. |
Derivative Assets And Liabili_2
Derivative Assets And Liabilities Derivative Assets and Liabilities (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Concentration Risk, Credit Risk, Policy [Policy Text Block] | Credit Risk 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 our 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, we may at times require collateral under certain circumstances to mitigate credit risk as necessary. We also implements the use of industry standard commercial agreements which allow for the netting of positive and negative 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 counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, motor fuel distributors, municipalities, utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic factors or regulatory changes that could impact its 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. We have maintenance margin deposits with certain counterparties in the OTC market, primarily 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. |
Derivatives, Policy [Policy Text Block] | 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 operations and operational gas sales on our interstate transportation and storage operations. 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 operations 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 and transportation costs in our retail marketing operations. 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 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 operations 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 operations, 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. |
Operations And Organization Ope
Operations And Organization Operations and Organization (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Operations and Organizations Tables [Abstract] | |
Schedule of Change in Accounting Estimate [Table Text Block] | Three Months Ended Nine Months Ended September 30, 2017 September 30, 2017 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted Cost of products sold $ 7,295 $ 46 $ 7,341 $ 22,005 $ 13 $ 22,018 Operating income 977 (46 ) 931 2,444 (13 ) 2,431 Income before income tax expense 630 (46 ) 584 1,312 (13 ) 1,299 Net income 804 (46 ) 758 1,211 (13 ) 1,198 Net loss attributable to noncontrolling interest 552 (46 ) 506 508 (13 ) 495 Comprehensive income 811 (46 ) 765 1,217 (13 ) 1,204 * Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 2. As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows: Nine Months Ended September 30, 2017 As Originally Reported* Effect of Change As Adjusted Net income $ 1,211 $ (13 ) $ 1,198 Inventory Valuation Adjustments (38 ) 30 (8 ) Net change in operating assets and liabilities (change in inventories) 209 (17 ) 192 * Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 2. |
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block] | The cumulative effect of the changes made to the Partnership’s consolidated balance sheet for the adoption of ASU 2014-09 was as follows: Balance at December 31, 2017 Adjustments due to ASC 606 Balance at January 1, 2018 Assets: Other current assets $ 295 $ 8 $ 303 Property and Equipment, net 61,088 — 61,088 Other non-current assets, net 886 39 925 Intangible assets, net 6,116 (100 ) 6,016 Liabilities and Equity: Other non-current liabilities $ 1,217 $ 1 $ 1,218 Noncontrolling interest 31,176 (54 ) 31,122 The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales, and operating expenses. Additionally, changes in timing of revenue recognition have required the creation of contract asset or contract liability balances, as well as certain balance sheet reclassifications. In accordance with the requirements of ASC Topic 606, the disclosure below shows the impact of adopting the new standard on the consolidated statement of operations and the consolidated balance sheet. Three Months Ended Nine Months Ended September 30, 2018 September 30, 2018 As Reported Balances Without Adoption of ASC 606 Effect of Change: Higher/(Lower) As Reported Balances Without Adoption of ASC 606 Effect of Change: Higher/(Lower) Revenues: Natural gas sales $ 1,026 $ 1,026 $ — $ 3,112 $ 3,112 $ — NGL sales 2,695 2,686 9 6,866 6,839 27 Crude sales 3,841 3,838 3 11,336 11,326 10 Gathering, transportation and other fees 1,781 1,985 (204 ) 4,878 5,415 (537 ) Refined product sales 4,955 4,968 (13 ) 13,583 13,619 (36 ) Other 216 216 — 739 739 — Costs and expenses: Cost of products sold $ 11,093 $ 11,298 $ (205 ) $ 31,681 $ 32,221 $ (540 ) Operating expenses 784 773 11 2,280 2,248 32 Depreciation and amortization 750 758 (8 ) 2,109 2,130 (21 ) September 30, 2018 As Reported Balances Without Adoption of ASC 606 Effect of Change: Higher/(Lower) Assets: Other current assets $ 303 $ 292 $ 11 Property and Equipment, net 65,643 65,643 — Intangible assets, net 6,013 6,135 (122 ) Other non-current assets, net 1,106 1,055 51 Liabilities and Equity: Other non-current liabilities $ 1,253 $ 1,252 $ 1 Noncontrolling interest 32,136 32,197 (61 ) Additional disclosures related to revenue are included in Note 12 . |
Acquisitions (Tables)
Acquisitions (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Disposal Groups, Including Discontinued Operations [Table Text Block] | The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet: September 30, 2018 December 31, 2017 Carrying amount of assets classified as held for sale: Cash and cash equivalents $ — $ 21 Inventories — 149 Other current assets — 16 Property, plant and equipment, net 6 1,851 Goodwill — 796 Intangible assets, net — 477 Other non-current assets, net — 3 Total assets classified as held for sale in the Consolidated Balance Sheet $ 6 $ 3,313 Carrying amount of liabilities classified as held for sale: Other current and non-current liabilities $ — $ 75 Total liabilities classified as held for sale in the Consolidated Balance Sheet $ — $ 75 The results of operations associated with discontinued operations are presented in the following table: Three Months Ended Nine Months Ended 2018 2017 2018 2017 REVENUES $ — $ 1,802 $ 349 $ 5,145 COSTS AND EXPENSES Cost of products sold — 1,482 305 4,274 Operating expenses — 182 61 566 Depreciation, depletion and amortization — (5 ) — 31 Impairment losses — 34 — 265 Selling, general and administrative — 57 7 126 Total costs and expenses — 1,750 373 5,262 OPERATING LOSS — 52 (24 ) (117 ) Interest expense, net — 13 2 21 Loss on extinguishment of debt and other — — 20 — Other, net — (8 ) 61 — INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE — 47 (107 ) (138 ) Income tax expense 2 30 158 49 INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES $ (2 ) $ 17 $ (265 ) $ (187 ) INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE ATTRIBUTABLE TO ETE $ — $ 1 $ (10 ) $ (6 ) |
USA Compression Partners, LP [Member] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | accounted for the USAC Transaction 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 fair values as of the acquisition date. The total purchase price was allocated as follows: At April 2, 2018 Total current assets $ 786 Property, plant and equipment 1,332 Other non-current assets 15 Goodwill (1) 366 Intangible assets 222 2,721 Total current liabilities 110 Long-term debt, less current maturities 1,527 Other non-current liabilities 2 1,639 Noncontrolling interest 832 Total consideration 250 Cash received (2) 711 Total consideration, net of cash received (2) $ (461 ) (1) None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations. (2) Cash received represents cash and cash equivalents held by USAC as of the acquisition date. |
Cash And Cash Equivalents (Tabl
Cash And Cash Equivalents (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule Of Non-Cash Investing and Non-Cash Financing Activities | Non-cash investing and financing activities were as follows: Nine Months Ended 2018 2017 NON-CASH INVESTING ACTIVITIES: Accrued capital expenditures $ 1,059 $ 1,237 Losses from subsidiary common unit transactions (125 ) (57 ) NON-CASH FINANCING ACTIVITIES: Contribution of property, plant and equipment from noncontrolling interest $ — $ 988 Conversion of Series A Convertible Preferred Units to common units 589 — |
Inventories (Tables)
Inventories (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Inventory, Net [Abstract] | |
Schedule Of Inventory | Inventories consisted of the following: September 30, 2018 December 31, 2017 Natural gas, NGLs, and refined products $ 1,072 $ 1,120 Crude oil 643 551 Spare parts and other 351 351 Total inventories $ 2,066 $ 2,022 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Measurements [Abstract] | |
Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis | The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2018 and December 31, 2017 based on inputs used to derive their fair values: Fair Value Measurements at Fair Value Total Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 48 $ 48 $ — Swing Swaps IFERC 1 — 1 Fixed Swaps/Futures 25 25 — Forward Physical Contracts 12 — 12 Power: Forwards 36 — 36 Options — Puts 1 1 — NGLs — Forwards/Swaps 476 476 — Refined Products — Futures 4 4 — Total commodity derivatives 603 554 49 Other non-current assets 28 18 10 Total assets $ 631 $ 572 $ 59 Liabilities: Interest rate derivatives $ (97 ) $ — $ (97 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (89 ) (89 ) — Swing Swaps IFERC (1 ) — (1 ) Fixed Swaps/Futures (26 ) (26 ) — Forward Physical Contracts (7 ) — (7 ) Power: Forwards (30 ) — (30 ) Futures (1 ) (1 ) — NGLs — Forwards/Swaps (522 ) (522 ) — Refined Products — Futures (10 ) (10 ) — Crude — Forwards/Swaps (191 ) (191 ) — Total commodity derivatives (877 ) (839 ) (38 ) Total liabilities $ (974 ) $ (839 ) $ (135 ) Fair Value Measurements at Fair Value Total Level 1 Level 2 Assets: Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX $ 11 $ 11 $ — Swing Swaps IFERC 13 — 13 Fixed Swaps/Futures 70 70 — Forward Physical Contracts 8 — 8 Power — Forwards 23 — 23 NGLs — Forwards/Swaps 191 191 — Refined Products — Futures 1 1 — Crude: Forwards/Swaps 2 2 — Futures 2 2 — Total commodity derivatives 321 277 44 Other non-current assets 21 14 7 Total assets $ 342 $ 291 $ 51 Liabilities: Interest rate derivatives $ (219 ) $ — $ (219 ) Commodity derivatives: Natural Gas: Basis Swaps IFERC/NYMEX (24 ) (24 ) — Swing Swaps IFERC (15 ) (1 ) (14 ) Fixed Swaps/Futures (57 ) (57 ) — Forward Physical Contracts (2 ) — (2 ) Power — Forwards (22 ) — (22 ) NGLs — Forwards/Swaps (186 ) (186 ) — Refined Products — Futures (28 ) (28 ) — Crude: Forwards/Swaps (6 ) (6 ) — Futures (1 ) (1 ) — Total commodity derivatives (341 ) (303 ) (38 ) Total liabilities $ (560 ) $ (303 ) $ (257 ) |
Net Income per Limited Partne_2
Net Income per Limited Partner Unit (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Reconciliation Of Net Income And Weighted Average Units | A reconciliation of income and weighted average units used in computing basic and diluted income per unit is as follows: Three Months Ended Nine Months Ended 2018 2017* 2018 2017* Income from continuing operations $ 1,393 $ 741 $ 2,778 $ 1,385 Less: Net income attributable to redeemable noncontrolling interests 12 — 24 — Less: Income from continuing operations attributable to noncontrolling interest 1,010 491 1,667 676 Income from continuing operations, net of noncontrolling interest 371 250 1,087 709 Less: Convertible Unitholders’ interest in income — 11 33 25 Less: General Partner’s interest in income 1 1 3 2 Income from continuing operations available to Limited Partners $ 370 $ 238 $ 1,051 $ 682 Basic Income from Continuing Operations per Limited Partner Unit: Weighted average limited partner units 1,158.2 1,079.1 1,117.7 1,077.9 Basic income from continuing operations per Limited Partner unit $ 0.32 $ 0.22 $ 0.94 $ 0.63 Basic income (loss) from discontinued operations per Limited Partner unit $ 0.00 $ 0.00 $ (0.01 ) $ (0.01 ) Diluted Income from Continuing Operations per Limited Partner Unit: Income from continuing operations available to Limited Partners $ 370 $ 238 $ 1,051 $ 682 Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders — 11 33 25 Diluted income from continuing operations available to Limited Partners $ 370 $ 249 $ 1,084 $ 707 Weighted average limited partner units 1,158.2 1,079.1 1,117.7 1,077.9 Dilutive effect of unconverted unit awards and Convertible Units — 69.2 40.5 69.5 Diluted weighted average limited partner units 1,158.2 1,148.3 1,158.2 1,147.4 Diluted income from continuing operations per Limited Partner unit $ 0.32 $ 0.22 $ 0.94 $ 0.62 Diluted income (loss) from discontinued operations per Limited Partner unit $ 0.00 $ 0.00 $ (0.01 ) $ (0.01 ) |
Equity (Tables)
Equity (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Schedule of Capital Units [Table Text Block] | The changes in ETE common units and ETE Series A Convertible Preferred Units during the nine months ended September 30, 2018 were as follows: Number of ETE Series A Convertible Preferred Units Number of Common Units Outstanding at December 31, 2017 329.3 1,079.1 Conversion of ETE Series A Convertible Preferred Units to common units (329.3 ) 79.1 Outstanding at September 30, 2018 — 1,158.2 |
Accumulated Other Comprehensive Income | The following table presents the components of AOCI, net of tax: September 30, 2018 December 31, 2017 Available-for-sale securities (1) $ 6 $ 8 Foreign currency translation adjustment (5 ) (5 ) Actuarial loss related to pensions and other postretirement benefits (7 ) (5 ) Investments in unconsolidated affiliates, net 14 5 Subtotal 8 3 Amounts attributable to noncontrolling interest (8 ) (3 ) Total AOCI, net of tax $ — $ — (1) Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities , which resulted in the reclassification of $2 million from ETP’s accumulated other comprehensive income related to available-for-sale securities to ETP’s common unitholders. The amount is reflected as a change in noncontrolling interest in the Partnership’s consolidated financial statements. |
Parent Company [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions declared and/or paid subsequent to December 31, 2017 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2017 (1) February 8, 2018 February 20, 2018 $ 0.3050 March 31, 2018 (1) May 7, 2018 May 21, 2018 0.3050 June 30, 2018 August 6, 2018 August 20, 2018 0.3050 September 30, 2018 November 8, 2018 November 19, 2018 0.3050 (1) Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forgo their cash distributions on all or a portion of their common units, and in lieu of receiving cash distributions on these common units for each such quarter, such unitholder received Series A Convertible Preferred Units, and (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Series A Convertible Preferred Unit. The quarter ended March 31, 2018 was the final quarter of participation in the plan. |
ETP [Member] | |
Schedule of Preferred Units [Table Text Block] | Distributions on ETP’s preferred units declared and paid by ETP subsequent to December 31, 2017 were as follows: Period Ended Record Date Payment Date Rate ETP Series A Preferred Units December 31, 2017 February 1, 2018 February 15, 2018 $ 15.451 June 30, 2018 August 1, 2018 August 15, 2018 31.250 ETP Series B Preferred Units December 31, 2017 February 1, 2018 February 15, 2018 16.378 June 30, 2018 August 1, 2018 August 15, 2018 33.125 ETP Series C Preferred Units June 30, 2018 August 1, 2018 August 15, 2018 0.5634 September 30, 2018 November 1, 2018 November 15, 2018 0.4609 ETP Series D Preferred Units September 30, 2018 November 1, 2018 November 15, 2018 0.5931 |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions declared and/or paid by ETP subsequent to December 31, 2017 but prior to the closing of the ETE-ETP Merger as discussed in Note 1 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2017 February 8, 2018 February 14, 2018 $ 0.5650 March 31, 2018 May 7, 2018 May 15, 2018 0.5650 June 30, 2018 August 6, 2018 August 14, 2018 0.5650 |
Sunoco LP [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Sunoco LP Cash Distributions The following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2017 : Quarter Ended Record Date Payment Date Rate December 31, 2017 February 6, 2018 February 14, 2018 $ 0.8255 March 31, 2018 May 7, 2018 May 15, 2018 0.8255 June 30, 2018 August 7, 2018 August 15, 2018 0.8255 September 30, 2018 November 6, 2018 November 14, 2018 0.8255 |
USA Compression Partners, LP [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | USAC Cash Distributions Subsequent to the USAC Transactions described in Note 2, ETE and its wholly-owned subsidiaries own an aggregate 20,466,912 USAC common units, and ETP owns 19,191,351 USAC common units and 6,397,965 USAC Class B units. As of September 30, 2018 , USAC had 89,966,676 common units outstanding. USAC currently has a non-economic general partner interest and no outstanding incentive distribution rights. The following are distributions declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018: Quarter Ended Record Date Payment Date Rate March 31, 2018 May 1, 2018 May 11, 2018 $ 0.5250 June 30, 2018 July 30, 2018 August 10, 2018 0.5250 September 30, 2018 October 29, 2018 November 09, 2018 0.5250 |
Convertible Units [Member] | |
Distributions Made to Limited Partner, by Distribution [Table Text Block] | Distributions declared and/or paid with respect to our Series A Convertible Preferred Units subsequent to December 31, 2017 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2017 February 8, 2018 February 20, 2018 $ 0.1100 March 31, 2018 May 7, 2018 May 21, 2018 0.1100 |
Regulatory Matters, Commitmen_2
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |
Schedule of Rent Expense [Table Text Block] | We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: Three Months Ended Nine Months Ended 2018 2017 2018 2017 Rental expense (1) $ 43 $ 49 $ 117 $ 130 Less: Sublease rental income (11 ) (7 ) (28 ) (19 ) Rental expense, net $ 32 $ 42 $ 89 $ 111 (1) Includes contingent rentals totaling $1 million and $3 million for three months ended September 30, 2018 and 2017 , respectively and $3 million and $13 million for the nine months ended September 30, 2018 and 2017 , respectively. |
Environmental Exit Costs by Cost | 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. September 30, 2018 December 31, 2017 Current $ 43 $ 35 Non-current 347 337 Total environmental liabilities $ 390 $ 372 |
Revenue (Tables)
Revenue (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue [Abstract] | |
Contract with Customer, Asset and Liability [Table Text Block] | The opening and closing balances of Sunoco LP’s contract assets and contract liabilities are as follows: Balance at January 1, 2018 Balance at September 30, 2018 Increase Contract Balances Contract Asset $ 51 $ 66 $ 15 Accounts receivable from contracts with customers 445 582 137 Contract Liability 1 1 — |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block] | As of September 30, 2018 , the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $41.68 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below: Years Ending December 31, 2018 (remainder) 2019 2020 Thereafter Total Revenue expected to be recognized on contracts with customers existing as of September 30, 2018 $ 1,474 $ 5,258 $ 4,696 $ 30,256 $ 41,684 |
Derivative Assets And Liabili_3
Derivative Assets And Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Outstanding Commodity-Related Derivatives | The following table details our outstanding commodity-related derivatives: September 30, 2018 December 31, 2017 Notional Volume Maturity Notional Volume Maturity Mark-to-Market Derivatives (Trading) Natural Gas (BBtu): Fixed Swaps/Futures 358 2018-2019 1,078 2018 Basis Swaps IFERC/NYMEX (1) 69,685 2018-2020 48,510 2018-2020 Options – Puts (17,273 ) 2019 13,000 2018 Power (Megawatt): Forwards 429,720 2018-2019 435,960 2018-2019 Futures 309,123 2018-2019 (25,760 ) 2018 Options — Puts 157,435 2018-2019 (153,600 ) 2018 Options — Calls 321,240 2018-2019 137,600 2018 (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (7,705 ) 2018-2021 4,650 2018-2020 Swing Swaps IFERC 69,145 2018-2019 87,253 2018-2019 Fixed Swaps/Futures (1,834 ) 2018-2020 (4,390 ) 2018-2019 Forward Physical Contracts (54,151 ) 2018-2020 (145,105 ) 2018-2020 NGL (MBbls) – Forwards/Swaps (4,937 ) 2019 (2,493 ) 2018-2019 Crude (MBbls) – Forwards/Swaps 35,228 2018-2019 9,237 2018-2019 Refined Products (MBbls) – Futures (1,507 ) 2018-2019 (3,901 ) 2018-2019 Corn (thousand bushels) (3,100 ) 2018-2019 1,870 2018 Fair Value Hedging Derivatives (Non-Trading) Natural Gas (BBtu): Basis Swaps IFERC/NYMEX (21,475 ) 2018-2019 (39,770 ) 2018 Fixed Swaps/Futures (21,475 ) 2018-2019 (39,770 ) 2018 Hedged Item — Inventory 21,475 2018-2019 39,770 2018 (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: Notional Amount Outstanding Term Type (1) September 30, 2018 December 31, 2017 July 2018 (2) Forward-starting to pay a fixed rate of 3.76% and receive a floating rate $ — $ 300 July 2019 (2) Forward-starting to pay a fixed rate of 3.56% and receive a floating rate 400 300 July 2020 (2) Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400 400 July 2021 (2) Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400 — December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200 1,200 March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300 300 (1) Floating rates are based on 3-month LIBOR. (2) Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date. |
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 September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 Derivatives designated as hedging instruments: Commodity derivatives (margin deposits) $ — $ 14 $ (6 ) $ (2 ) Derivatives not designated as hedging instruments: Commodity derivatives (margin deposits) 477 262 (537 ) (281 ) Commodity derivatives 126 45 (334 ) (58 ) Interest rate derivatives — — (97 ) (219 ) 603 307 (968 ) (558 ) Total derivatives $ 603 $ 321 $ (974 ) $ (560 ) |
Derivatives, Offsetting Fair Value Amounts [Table Text Block] | 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 September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017 Derivatives without offsetting agreements Derivative liabilities $ — $ — $ (97 ) $ (219 ) Derivatives in offsetting agreements: OTC contracts Derivative assets (liabilities) 126 45 (334 ) (58 ) Broker cleared derivative contracts Other current assets (liabilities) 477 276 (543 ) (283 ) Total gross derivatives 603 321 (974 ) (560 ) Offsetting agreements: Counterparty netting Derivative assets (liabilities) (29 ) (21 ) 29 21 Counterparty netting Other current assets (liabilities) (477 ) (263 ) 477 263 Total net derivatives $ 97 $ 37 $ (468 ) $ (276 ) |
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | The following tables summarize the amounts recognized with respect to our derivative financial instruments: Location of Gain Recognized in Income on Derivatives Amount of Gain Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness Three Months Ended Nine Months Ended 2018 2017 2018 2017 Derivatives in fair value hedging relationships (including hedged item): Commodity derivatives Cost of products sold $ — $ 2 $ 9 $ 4 |
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 Three Months Ended Nine Months Ended 2018 2017 2018 2017 Derivatives not designated as hedging instruments: Commodity derivatives — Trading Cost of products sold $ 3 $ (5 ) $ 36 $ 21 Commodity derivatives — Non-trading Cost of products sold 21 (25 ) (345 ) (6 ) Interest rate derivatives Gains (losses) on interest rate derivatives 45 (8 ) 117 (28 ) Embedded derivatives Other, net — — — 1 Total $ 69 $ (38 ) $ (192 ) $ (12 ) |
Reportable Segments (Tables)
Reportable Segments (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Operating Segments [Member] | |
Financial Information By Segment | The following tables present financial information by segment: Three Months Ended Nine Months Ended 2018 2017* 2018 2017* Segment Adjusted EBITDA: Investment in ETP $ 2,329 $ 1,784 $ 6,261 $ 4,774 Investment in Sunoco LP 208 199 457 574 Investment in USAC 90 — 185 — Investment in Lake Charles LNG 43 43 131 131 Corporate and Other (9 ) (3 ) (17 ) (25 ) Adjustments and Eliminations (84 ) (74 ) (176 ) (211 ) Total 2,577 1,949 6,841 5,243 Depreciation, depletion and amortization (750 ) (642 ) (2,109 ) (1,877 ) Interest expense, net of interest capitalized (535 ) (490 ) (1,511 ) (1,440 ) Impairment losses — (10 ) — (99 ) Gains (losses) on interest rate derivatives 45 (8 ) 117 (28 ) Non-cash compensation expense (27 ) (29 ) (82 ) (76 ) Unrealized gains (losses) on commodity risk management activities 97 (76 ) (255 ) 22 Gains on disposal of assets 18 5 14 — Losses on extinguishments of debt — — (106 ) (25 ) Inventory valuation adjustments (7 ) 50 50 8 Equity in earnings of unconsolidated affiliates 87 92 258 228 Adjusted EBITDA related to unconsolidated affiliates (179 ) (205 ) (503 ) (554 ) Adjusted EBITDA related to discontinued operations — (76 ) 25 (179 ) Other, net 15 24 45 76 Income from continuing operations before income tax (expense) benefit 1,341 584 2,784 1,299 Income tax (expense) benefit from continuing operations 52 157 (6 ) 86 Income from continuing operations 1,393 741 2,778 1,385 Income (loss) from discontinued operations, net of income taxes (2 ) 17 (265 ) (187 ) Net income $ 1,391 $ 758 $ 2,513 $ 1,198 * As adjusted. See Note 1. |
Assets Segments [Member] | |
Financial Information By Segment | September 30, 2018 December 31, 2017 Assets: Investment in ETP $ 79,156 $ 77,965 Investment in Sunoco LP 5,148 8,344 Investment in USAC 3,814 — Investment in Lake Charles LNG 1,746 1,646 Corporate and Other 625 598 Adjustments and Eliminations (2,302 ) (2,307 ) Total assets $ 88,187 $ 86,246 |
Sales Revenue, Segment [Member] | |
Financial Information By Segment | Three Months Ended Nine Months Ended 2018 2017* 2018 2017* Revenues: Investment in ETP: Revenues from external customers $ 9,538 $ 6,876 $ 26,921 $ 20,168 Intersegment revenues 103 97 410 276 9,641 6,973 27,331 20,444 Investment in Sunoco LP: Revenues from external customers 4,760 3,058 13,114 8,755 Intersegment revenues 1 6 3 9 4,761 3,064 13,117 8,764 Investment in USAC: Revenues from external customers 166 — 331 — Intersegment revenues 3 — 5 — 169 — 336 — Investment in Lake Charles LNG: Revenues from external customers 50 49 148 148 Adjustments and Eliminations (107 ) (102 ) (418 ) (284 ) Total revenues $ 14,514 $ 9,984 $ 40,514 $ 29,072 * As adjusted. See Note 1. |
Investment In ETP [Member] | |
Revenue from External Customers by Products and Services [Table Text Block] | Investment in ETP Three Months Ended Nine Months Ended 2018 2017* 2018 2017* Intrastate transportation and storage $ 846 $ 729 $ 2,424 $ 2,196 Interstate transportation and storage 390 220 1,026 652 Midstream 537 665 1,571 1,863 NGL and refined products transportation and services 2,948 1,989 7,878 5,874 Crude oil transportation and services 4,422 2,714 12,942 7,749 All Other 498 656 1,490 2,110 Total revenues 9,641 6,973 27,331 20,444 Less: Intersegment revenues 103 97 410 276 Revenues from external customers $ 9,538 $ 6,876 $ 26,921 $ 20,168 * As adjusted. See Note 1. |
Investment In Sunoco LP [Member] | |
Revenue from External Customers by Products and Services [Table Text Block] | Investment in Sunoco LP Three Months Ended Nine Months Ended 2018 2017 2018 2017 Fuel distribution and marketing $ 4,494 $ 2,467 $ 11,983 $ 7,082 All other 267 597 1,134 1,682 Total revenues 4,761 3,064 13,117 8,764 Less: Intersegment revenues 1 6 3 9 Revenues from external customers $ 4,760 $ 3,058 $ 13,114 $ 8,755 |
Investment In USAC [Member] | |
Revenue from External Customers by Products and Services [Table Text Block] | Investment in USAC Three Months Ended Nine Months Ended 2018 2017 2018 2017 Contract operations $ 163 $ — $ 323 $ — Retail parts and services 5 — 11 — Station installations revenue 1 — 2 — Total revenues 169 — 336 — Less: Intersegment revenues 3 — 5 — Revenues from external customers $ 166 $ — $ 331 $ — |
Supplemental Financial Statem_2
Supplemental Financial Statement Information (Tables) - Parent Company [Member] | 9 Months Ended |
Sep. 30, 2018 | |
Schedule Of Balance Sheets | BALANCE SHEETS (unaudited) September 30, 2018 December 31, 2017 ASSETS Current assets: Cash and cash equivalents $ 1 $ 1 Accounts receivable from related companies 100 65 Other current assets 1 1 Total current assets 102 67 Property, plant and equipment, net 27 27 Advances to and investments in unconsolidated affiliates 6,045 6,082 Goodwill 9 9 Other non-current assets, net 7 8 Total assets $ 6,190 $ 6,193 LIABILITIES AND PARTNERS’ DEFICIT Current liabilities: Accounts payable to related companies $ 42 $ — Interest payable 78 66 Accrued and other current liabilities 9 4 Total current liabilities 129 70 Long-term debt, less current maturities 6,415 6,700 Long-term notes payable – related companies 747 617 Other non-current liabilities 2 2 Commitments and contingencies Partners’ deficit: Limited Partners: Series A Convertible Preferred Units — 450 Common Unitholders (1,099 ) (1,643 ) General Partner (4 ) (3 ) Total partners’ deficit (1,103 ) (1,196 ) Total liabilities and partners’ deficit $ 6,190 $ 6,193 |
Schedule Of Statements Of Operations | STATEMENTS OF OPERATIONS (unaudited) Three Months Ended Nine Months Ended 2018 2017 2018 2017 SELLING, GENERAL AND ADMINISTRATIVE EXPENSES $ (9 ) $ (3 ) $ (20 ) $ (25 ) OTHER INCOME (EXPENSE): Interest expense, net (89 ) (88 ) (265 ) (257 ) Equity in earnings of unconsolidated affiliates 469 343 1,359 1,012 Losses on extinguishments of debt — — — (25 ) Other, net — — 3 (2 ) NET INCOME 371 252 1,077 703 Convertible Unitholders’ interest in income — 11 33 25 General Partner’s interest in net income 1 1 3 2 Limited Partners’ interest in net income $ 370 $ 240 $ 1,041 $ 676 |
Schedule Of Statements Of Cash Flows | STATEMENTS OF CASH FLOWS (unaudited) Nine Months Ended 2018 2017 NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 993 $ 620 CASH FLOWS FROM INVESTING ACTIVITIES Contributions to unconsolidated affiliate (250 ) (861 ) Capital expenditures — (1 ) Contributions in aid of construction costs — 7 Sunoco LP Series A Preferred Units redemption 303 — Net cash provided by (used in) investing activities 53 (855 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from borrowings 413 2,116 Principal payments on debt (703 ) (1,795 ) Proceeds from affiliate 130 131 Distributions to partners (886 ) (752 ) Units issued for cash — 568 Debt issuance costs — (35 ) Net cash provided by (used in) financing activities (1,046 ) 233 CHANGE IN CASH AND CASH EQUIVALENTS — (2 ) CASH AND CASH EQUIVALENTS, beginning of period 1 2 CASH AND CASH EQUIVALENTS, end of period $ 1 $ — |
Operations And Organization Nar
Operations And Organization Narrative (Details) | 3 Months Ended | |
Dec. 31, 2018shares | Sep. 30, 2018shares | |
Subsequent Event [Member] | ETE Merger [Member] | ||
Stockholders' Equity Note, Stock Split, Conversion Ratio | 1.28 | |
Sale of Stock, Number of Shares Issued in Transaction | 1,460,000,000 | |
ETP, Sunoco LP and USAC [Member] | ||
Incentive Distribution Rights | 100.00% | |
Sunoco LP [Member] | ||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 2,300,000 | |
Sunoco LP [Member] | Subsequent Event [Member] | ETE Merger [Member] | ||
Sale of Stock, Number of Shares Issued in Transaction | 2,263,158 | |
USAC [Member] | ||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 20,500,000 | |
USAC [Member] | Subsequent Event [Member] | ETE Merger [Member] | ||
Sale of Stock, Number of Shares Issued in Transaction | 12,466,912 | |
ETP [Member] | ||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 27,500,000 | |
Class I Units [Member] | ETP [Member] | ||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 100 | |
IDRs [Member] | Subsequent Event [Member] | ETE Merger [Member] | ||
Sale of Stock, Number of Shares Issued in Transaction | 1,168,205,710 | |
General Partner | Subsequent Event [Member] | ETE Merger [Member] | ||
Sale of Stock, Number of Shares Issued in Transaction | 18,448,341 |
Operations And Organization A_2
Operations And Organization Accounting Change (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||||||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Mar. 31, 2018 | Jan. 01, 2018 | Dec. 31, 2017 | ||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Cost of products sold | $ 11,093 | $ 7,341 | [1] | $ 31,681 | $ 22,018 | [1] | ||||
Operating Income (Loss) | 1,703 | 931 | [1] | 3,929 | 2,431 | [1] | ||||
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest | 1,341 | 584 | [1] | 2,784 | 1,299 | [1] | ||||
Net income, excluding amounts attributable to redeemable noncontrolling interests | 1,391 | 758 | [1] | 2,513 | 1,198 | [1] | ||||
Less: Net income attributable to noncontrolling interest | 1,008 | 506 | [1] | 1,412 | 495 | [1] | ||||
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest | 1,395 | 765 | [1] | 2,520 | 1,204 | [1] | ||||
Inventory valuation adjustments | 7 | (50) | [1] | (50) | (8) | [1] | ||||
Increase (Decrease) in Operating Capital | 423 | 192 | [1] | |||||||
Other current assets | 303 | 303 | $ 303 | $ 295 | ||||||
Property, plant and equipment, net | 65,643 | 65,643 | 61,088 | 61,088 | ||||||
Intangible assets, net | 6,013 | 6,013 | 6,016 | 6,116 | ||||||
Other non-current assets, net | 1,106 | 1,106 | 925 | 886 | ||||||
Other non-current liabilities | 1,253 | 1,253 | 1,218 | 1,217 | ||||||
Noncontrolling interest | 32,136 | 32,136 | 31,176 | |||||||
Operating expenses | 784 | 918 | [1] | 2,280 | 2,167 | [1] | ||||
Depreciation, depletion and amortization | 750 | 642 | [1] | 2,109 | 1,877 | [1] | ||||
Noncontrolling Interest | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Noncontrolling interest | $ 31,122 | |||||||||
Restatement Adjustment [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Cost of products sold | (205) | 46 | (540) | 13 | ||||||
Operating Income (Loss) | (46) | (13) | ||||||||
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest | (46) | (13) | ||||||||
Net income, excluding amounts attributable to redeemable noncontrolling interests | (46) | (13) | ||||||||
Less: Net income attributable to noncontrolling interest | (46) | (13) | ||||||||
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest | (46) | (13) | ||||||||
Inventory valuation adjustments | 30 | |||||||||
Increase (Decrease) in Operating Capital | (17) | |||||||||
Other current assets | $ 11 | 8 | ||||||||
Property, plant and equipment, net | 0 | 0 | ||||||||
Intangible assets, net | (122) | (100) | ||||||||
Other non-current assets, net | 51 | 39 | ||||||||
Other non-current liabilities | 1 | 1 | ||||||||
Noncontrolling interest | (61) | (54) | ||||||||
Operating expenses | 11 | 32 | ||||||||
Depreciation, depletion and amortization | (8) | (21) | ||||||||
Previously Reported [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Cost of products sold | 11,298 | 7,295 | [2] | 32,221 | 22,005 | [2] | ||||
Operating Income (Loss) | [2] | 977 | 2,444 | |||||||
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest | [2] | 630 | 1,312 | |||||||
Net income, excluding amounts attributable to redeemable noncontrolling interests | [2] | 804 | 1,211 | |||||||
Less: Net income attributable to noncontrolling interest | [2] | 552 | 508 | |||||||
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest | [2] | 811 | 1,217 | |||||||
Inventory valuation adjustments | [2] | (38) | ||||||||
Increase (Decrease) in Operating Capital | [2] | 209 | ||||||||
Other current assets | 292 | |||||||||
Property, plant and equipment, net | 65,643 | $ 61,088 | ||||||||
Intangible assets, net | 6,135 | |||||||||
Other non-current assets, net | 1,055 | |||||||||
Other non-current liabilities | 1,252 | |||||||||
Noncontrolling interest | $ 32,197 | |||||||||
Operating expenses | 773 | 2,248 | ||||||||
Depreciation, depletion and amortization | 758 | 2,130 | ||||||||
Natural gas sales [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 1,026 | 1,098 | [1] | 3,112 | 3,132 | [1] | ||||
Natural gas sales [Member] | Restatement Adjustment [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 0 | 0 | ||||||||
Natural gas sales [Member] | Previously Reported [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 1,026 | 3,112 | ||||||||
NGL sales [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 2,695 | 1,749 | [1] | 6,866 | 4,782 | [1] | ||||
NGL sales [Member] | Restatement Adjustment [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 9 | 27 | ||||||||
NGL sales [Member] | Previously Reported [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 2,686 | 6,839 | ||||||||
Oil and Gas [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 3,841 | 2,381 | [1] | 11,336 | 7,268 | [1] | ||||
Oil and Gas [Member] | Restatement Adjustment [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 3 | 10 | ||||||||
Oil and Gas [Member] | Previously Reported [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 3,838 | 11,326 | ||||||||
Natural Gas, Midstream [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 1,781 | 1,068 | [1] | 4,878 | 3,244 | [1] | ||||
Natural Gas, Midstream [Member] | Restatement Adjustment [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | (204) | (537) | ||||||||
Natural Gas, Midstream [Member] | Previously Reported [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 1,985 | 5,415 | ||||||||
Oil and Gas, Refining and Marketing [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 4,955 | 3,080 | [1] | 13,583 | 8,998 | [1] | ||||
Oil and Gas, Refining and Marketing [Member] | Restatement Adjustment [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | (13) | (36) | ||||||||
Oil and Gas, Refining and Marketing [Member] | Previously Reported [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 4,968 | 13,619 | ||||||||
Product and Service, Other [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 216 | $ 608 | [1] | 739 | $ 1,648 | [1] | ||||
Product and Service, Other [Member] | Restatement Adjustment [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | 0 | 0 | ||||||||
Product and Service, Other [Member] | Previously Reported [Member] | ||||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||||||||
Revenue from Contract with Customer, Including Assessed Tax | $ 216 | $ 739 | ||||||||
[1] | As adjusted. See Note 1. | |||||||||
[2] | * Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 2. |
Acquisitions Narrative (Details
Acquisitions Narrative (Details) gal in Millions, $ in Millions | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||||
Apr. 30, 2018USD ($)shares | Jan. 22, 2018USD ($) | Dec. 31, 2018shares | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2018gal | Jan. 31, 2018 | Dec. 31, 2017 | |||
Impairment losses | $ | $ 0 | $ 34 | $ 0 | $ 265 | ||||||||
Revenues | $ | 14,514 | $ 9,984 | [1] | 40,514 | $ 29,072 | [1] | ||||||
Retail Fuel Outlets | 97 | |||||||||||
Subsequent Event [Member] | ||||||||||||
Long-term Purchase Commitment, Minimum Volume Required | gal | 2,000 | |||||||||||
ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 1,460,000,000 | |||||||||||
USAC Transaction [Member] | ||||||||||||
Payments to Acquire Businesses, Gross | $ | $ 1,230 | |||||||||||
Business Combination, Consideration Transferred | $ | $ 1,700 | |||||||||||
Sunoco LP [Member] | ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 2,263,158 | |||||||||||
Sunoco GP [Member] | ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest | 100.00% | |||||||||||
USAC [Member] | ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 12,466,912 | |||||||||||
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest | 100.00% | |||||||||||
Lake Charles LNG [Member] | ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest | 100.00% | |||||||||||
Energy Transfer LNG Export LLC, ET Crude Oil Terminals LLC, & ETC Illinois LLC [Member] | ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest | 60.00% | |||||||||||
USA Compression Partners, LP [Member] | USAC Transaction [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 19,191,351 | |||||||||||
RIGS Haynesville Partnership Co. [Member] | ||||||||||||
Equity Method Investment, Ownership Percentage | 50.01% | 49.99% | ||||||||||
7-Eleven [Member] | ||||||||||||
Revenues | $ | $ 199 | 926 | 2,400 | |||||||||
Trade Receivables Held-for-sale, Reconciliation to Cash Flow, Period Increase (Decrease) | $ | $ 1,000 | $ 2,600 | ||||||||||
Class B Units [Member] | USA Compression Partners, LP [Member] | USAC Transaction [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 6,397,965 | |||||||||||
ETP [Member] | Sunoco LP [Member] | ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 2,874,275 | |||||||||||
ETP [Member] | Sunoco GP [Member] | ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 42,812,389 | |||||||||||
ETP [Member] | USAC [Member] | ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 16,134,903 | |||||||||||
ETP [Member] | Lake Charles LNG [Member] | ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 37,557,815 | |||||||||||
ETE [Member] | USA Compression Partners, LP [Member] | USAC Transaction [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 12,466,912 | |||||||||||
Equity Issued in Business Combination, Fair Value Disclosure | $ | $ 250 | |||||||||||
USAC GP [Member] | USA Compression Partners, LP [Member] | USAC Transaction [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 8,000,000 | |||||||||||
Portfolio optimization plan [Member] | ||||||||||||
Retail Fuel Outlets | 97 | |||||||||||
Sold [Member] | ||||||||||||
Retail Fuel Outlets | 50 | |||||||||||
Under contract [Member] | ||||||||||||
Retail Fuel Outlets | 1 | |||||||||||
Currently being marketed [Member] | ||||||||||||
Retail Fuel Outlets | 5 | |||||||||||
7-Eleven Transaction [Member] | ||||||||||||
Retail Fuel Outlets | 32 | |||||||||||
West Texas, Oklahoma and New Mexico [Member] | ||||||||||||
Retail Fuel Outlets | 207 | |||||||||||
West Texas, Oklahoma and New Mexico [Member] | 7-Eleven Transaction [Member] | ||||||||||||
Retail Fuel Outlets | 9 | |||||||||||
Additional aggregate volumes [Member] | Subsequent Event [Member] | ||||||||||||
Long-term Purchase Commitment, Minimum Volume Required | gal | 500 | |||||||||||
IDRs [Member] | ETE Merger [Member] | Subsequent Event [Member] | ||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 1,168,205,710 | |||||||||||
[1] | As adjusted. See Note 1. |
Acquisitions Discontinued Opera
Acquisitions Discontinued Operations - Balance Sheet Data (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Cash and cash equivalents | $ 0 | $ 21 |
Inventories | 0 | 149 |
Other current assets | 0 | 16 |
Property, plant and equipment, net | 6 | 1,851 |
Goodwill | 0 | 796 |
Intangible assets, net | 0 | 477 |
Other non-current assets, net | 0 | 3 |
Total assets classified as held for sale in the Consolidated Balance Sheet | 6 | 3,313 |
Total liabilities classified as held for sale in the Consolidated Balance Sheet | $ 0 | 75 |
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent | $ 75 |
Acquisitions Discontinued Ope_2
Acquisitions Discontinued Operations - Income Statement Data (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
REVENUES | $ 0 | $ 1,802 | $ 349 | $ 5,145 | ||
Cost of products sold | 0 | 1,482 | 305 | 4,274 | ||
Operating expenses | 0 | 182 | 61 | 566 | ||
Depreciation, depletion and amortization | 0 | (5) | 0 | 31 | ||
Impairment losses | 0 | 34 | 0 | 265 | ||
Selling, general and administrative | 0 | 57 | 7 | 126 | ||
Total costs and expenses | 0 | 1,750 | 373 | 5,262 | ||
OPERATING LOSS | 0 | 52 | (24) | (117) | ||
Interest expense, net | 0 | 13 | 2 | 21 | ||
Loss on extinguishment of debt and other | 0 | 0 | 20 | 0 | ||
Other, net | 0 | (8) | 61 | 0 | ||
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE | 0 | 47 | (107) | (138) | ||
Income tax expense | 2 | 30 | 158 | 49 | ||
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES | (2) | 17 | [1] | (265) | (187) | [1] |
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE ATTRIBUTABLE TO ETE | $ 0 | $ 1 | $ (10) | $ (6) | ||
[1] | As adjusted. See Note 1. |
Acquisitions Acquisitions (Deta
Acquisitions Acquisitions (Details) - USA Compression Partners, LP [Member] $ in Millions | Apr. 02, 2018USD ($) | |
Business Acquisition [Line Items] | ||
Total current assets | $ 786 | |
Property, plant and equipment | 1,332 | |
Other non-current assets | 15 | |
Goodwill1 | 366 | [1] |
Intangible assets | 222 | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 2,721 | |
Total current liabilities | 110 | |
Long-term debt, less current maturities | 1,527 | |
Other non-current liabilities | 2 | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 1,639 | |
Noncontrolling interest | 832 | |
Total consideration | 250 | |
Cash received(2) | 711 | [2] |
Total consideration, net of cash received(2) | $ (461) | [2] |
[1] | None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations. | |
[2] | Cash received represents cash and cash equivalents held by USAC as of the acquisition date. |
Cash And Cash Equivalents Non-C
Cash And Cash Equivalents Non-Cash Activities (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
NON-CASH INVESTING ACTIVITIES: | ||
Accrued capital expenditures | $ 1,059 | $ 1,237 |
Losses from subsidiary common unit transactions | (125) | (57) |
Non-Cash Financing [Abstract] | ||
Capital Contributions from Noncontrolling Interest | 0 | 988 |
Series A Convertible Preferred Units conversion | 0 | |
Common Unitholders | ||
Non-Cash Financing [Abstract] | ||
Series A Convertible Preferred Units conversion | $ 589 | $ 0 |
Inventories Table - Inventory B
Inventories Table - Inventory Balances (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Inventory, Net [Abstract] | ||
Natural gas, NGLs, and refined products | $ 1,072 | $ 1,120 |
Crude oil | 643 | 551 |
Spare parts and other | 351 | 351 |
Total inventories | $ 2,066 | $ 2,022 |
Fair Value Measurements Narrati
Fair Value Measurements Narrative (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2018 | Dec. 31, 2017 | |
Fair Value Measurements [Abstract] | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net | $ 0 | |
Debt obligations, fair value | 45,540 | $ 45,620 |
Long-term Debt | $ 44,770 | $ 44,080 |
Fair Value Measurements Table -
Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Price Risk Derivative Assets, at Fair Value | $ 603 | $ 321 |
Other Assets, Fair Value Disclosure | 28 | 21 |
Assets, Fair Value Disclosure | 631 | 342 |
Interest Rate Derivative Liabilities, at Fair Value | (97) | (219) |
Price Risk Derivative Liabilities, at Fair Value | (877) | (341) |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (974) | (560) |
Level 1 | ||
Price Risk Derivative Assets, at Fair Value | 554 | 277 |
Other Assets, Fair Value Disclosure | 18 | 14 |
Assets, Fair Value Disclosure | 572 | 291 |
Interest Rate Derivative Liabilities, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | (839) | (303) |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (839) | (303) |
Level 2 | ||
Price Risk Derivative Assets, at Fair Value | 49 | 44 |
Other Assets, Fair Value Disclosure | 10 | 7 |
Assets, Fair Value Disclosure | 59 | 51 |
Interest Rate Derivative Liabilities, at Fair Value | (97) | (219) |
Price Risk Derivative Liabilities, at Fair Value | (38) | (38) |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (135) | (257) |
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ||
Price Risk Derivative Assets, at Fair Value | 48 | 11 |
Price Risk Derivative Liabilities, at Fair Value | (89) | (24) |
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | 13 |
Price Risk Derivative Liabilities, at Fair Value | (1) | (15) |
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 25 | 70 |
Price Risk Derivative Liabilities, at Fair Value | (26) | (57) |
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 12 | 8 |
Price Risk Derivative Liabilities, at Fair Value | (7) | 2 |
Commodity Derivatives - Natural Gas [Member] | Level 1 | Basis Swaps IFERC/NYMEX [Member] | ||
Price Risk Derivative Assets, at Fair Value | 48 | 11 |
Price Risk Derivative Liabilities, at Fair Value | (89) | (24) |
Commodity Derivatives - Natural Gas [Member] | Level 1 | Swing Swaps IFERC [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | (1) |
Commodity Derivatives - Natural Gas [Member] | Level 1 | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 25 | 70 |
Price Risk Derivative Liabilities, at Fair Value | 26 | (57) |
Commodity Derivatives - Natural Gas [Member] | Level 1 | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Level 2 | Basis Swaps IFERC/NYMEX [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Level 2 | Swing Swaps IFERC [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | 13 |
Price Risk Derivative Liabilities, at Fair Value | (1) | (14) |
Commodity Derivatives - Natural Gas [Member] | Level 2 | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Natural Gas [Member] | Level 2 | Forward Physical Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 12 | 8 |
Price Risk Derivative Liabilities, at Fair Value | 7 | 2 |
Commodity Derivatives - Refined Products [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 4 | 1 |
Price Risk Derivative Liabilities, at Fair Value | (10) | (28) |
Commodity Derivatives - Refined Products [Member] | Level 1 | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 4 | 1 |
Price Risk Derivative Liabilities, at Fair Value | (10) | (28) |
Commodity Derivatives - Refined Products [Member] | Level 2 | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Crude [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Price Risk Derivative Liabilities, at Fair Value | (191) | (6) |
Commodity Derivatives - Crude [Member] | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Price Risk Derivative Liabilities, at Fair Value | (1) | |
Commodity Derivatives - Crude [Member] | Level 1 | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Price Risk Derivative Liabilities, at Fair Value | (191) | (6) |
Commodity Derivatives - Crude [Member] | Level 1 | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 2 | |
Price Risk Derivative Liabilities, at Fair Value | (1) | |
Commodity Derivatives - Crude [Member] | Level 2 | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Crude [Member] | Level 2 | Future [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 36 | 23 |
Price Risk Derivative Liabilities, at Fair Value | (30) | (22) |
Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | (1) | |
Commodity Derivatives - Power [Member] | Options - Puts [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Commodity Derivatives - Power [Member] | Level 1 | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Commodity Derivatives - Power [Member] | Level 1 | Call Option [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | (1) | |
Commodity Derivatives - Power [Member] | Level 1 | Options - Puts [Member] | ||
Price Risk Derivative Assets, at Fair Value | 1 | |
Commodity Derivatives - Power [Member] | Level 2 | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 36 | 23 |
Price Risk Derivative Liabilities, at Fair Value | (30) | (22) |
Commodity Derivatives - Power [Member] | Level 2 | Call Option [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | 0 | |
Commodity Derivatives - Power [Member] | Level 2 | Options - Puts [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | |
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 476 | 191 |
Price Risk Derivative Liabilities, at Fair Value | (522) | (186) |
Commodity Derivatives - NGLs [Member] | Level 1 | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 476 | 191 |
Price Risk Derivative Liabilities, at Fair Value | 522 | (186) |
Commodity Derivatives - NGLs [Member] | Level 2 | Forward Swaps [Member] | ||
Price Risk Derivative Assets, at Fair Value | 0 | 0 |
Price Risk Derivative Liabilities, at Fair Value | $ 0 | $ 0 |
Net Income per Limited Partne_3
Net Income per Limited Partner Unit Table - Income Reconciliation (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | [1] | Sep. 30, 2018 | Sep. 30, 2017 | [1] | |
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items] | ||||||
Income from continuing operations | $ 1,393 | $ 741 | $ 2,778 | $ 1,385 | ||
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest | 12 | 0 | 24 | 0 | ||
Less: Income from continuing operations attributable to noncontrolling interest | 1,010 | 491 | 1,667 | 676 | ||
Income from continuing operations, net of noncontrolling interest | 371 | 250 | 1,087 | 709 | ||
Less: Convertible Unitholders’ interest in income | 0 | 11 | 33 | 25 | ||
Less: General Partner’s interest in income | 1 | 1 | 3 | 2 | ||
Net Income (Loss) from Continuing Operations Available to Common Shareholders, Basic | $ 370 | $ 238 | $ 1,051 | $ 682 | ||
Basic Income from Continuing Operations per Limited Partner Unit: | ||||||
Weighted average limited partner units | 1,158.2 | 1,079.1 | 1,117.7 | 1,077.9 | ||
Basic income from continuing operations per Limited Partner unit | $ 0.32 | $ 0.22 | $ 0.94 | $ 0.63 | ||
Basic income (loss) from discontinued operations per Limited Partner unit | $ 0 | $ 0 | $ (0.01) | $ (0.01) | ||
Diluted Income from Continuing Operations per Limited Partner Unit: | ||||||
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders | $ 0 | $ 11 | $ 33 | $ 25 | ||
Diluted income from continuing operations available to Limited Partners | $ 370 | $ 249 | $ 1,084 | $ 707 | ||
Dilutive effect of unconverted unit awards and Convertible Units | 0 | 69.2 | 40.5 | 69.5 | ||
Diluted weighted average limited partner units | 1,158.2 | 1,148.3 | 1,158.2 | 1,147.4 | ||
Diluted income from continuing operations per Limited Partner unit | $ 0.32 | $ 0.22 | $ 0.94 | $ 0.62 | ||
Diluted income (loss) from discontinued operations per Limited Partner unit | $ 0 | $ 0 | $ (0.01) | $ (0.01) | ||
[1] | As adjusted. See Note 1. |
Debt Obligations Narrative (Det
Debt Obligations Narrative (Details) - USD ($) $ in Millions | 1 Months Ended | 9 Months Ended | ||||
Oct. 31, 2018 | Feb. 28, 2018 | Jan. 31, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | ||
Debt Instrument [Line Items] | ||||||
Proceeds from Issuance of Senior Long-term Debt | $ 2,200 | $ 2,960 | ||||
Early Repayment of Senior Debt | 1,650 | |||||
Repayments of Long-term Debt | 23,323 | $ 22,536 | [1] | |||
Proceeds from Issuance of Long-term Debt | 22,126 | 23,988 | [1] | |||
Parent Company [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Repayments of Long-term Debt | 703 | 1,795 | ||||
Proceeds from Issuance of Long-term Debt | 413 | $ 2,116 | ||||
Sunoco LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Stock Repurchased During Period, Shares | 17,286,859 | |||||
ETE Senior Secured Revolving Credit Facilities [Member] | Parent Company [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Line of Credit | 898 | |||||
Bakken Term Note [Member] | Bakken Pipeline [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | 2,500 | |||||
4.20% Senior Notes due 2023 [Member] | ETP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 500 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 4.20% | |||||
ETP Credit Facility due December 2022 [Member] | ETP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Line of Credit Facility, Current Borrowing Capacity | $ 2,060 | |||||
Long-term Line of Credit | 1,780 | |||||
Long-term Commercial Paper, Noncurrent | 1,570 | |||||
Letters of Credit Outstanding, Amount | $ 163 | |||||
Line of Credit Facility, Interest Rate at Period End | 3.00% | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 4,000 | |||||
ETP Credit Facility due December 2022 [Member] | Accordion feature [Member] | ETP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Line of Credit | 6,000 | |||||
ETP $1.0 billion 364-day Credit Facility due December 2018 [Member] | ETP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Line of Credit | 0 | |||||
Line of Credit Facility, Maximum Borrowing Capacity | 1,000 | |||||
Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member] | Sunoco LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Line of Credit Facility, Current Borrowing Capacity | 1,500 | |||||
Long-term Line of Credit | 493 | |||||
Letters of Credit Outstanding, Amount | 8 | |||||
Line of Credit Facility, Remaining Borrowing Capacity | 999 | |||||
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Line of Credit | $ 2,500 | |||||
Line of Credit Facility, Interest Rate at Period End | 3.85% | |||||
4.875% senior notes due 2023 [Member] | Sunoco LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 1,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 4.875% | |||||
5.500% senior notes due 2026 [Member] | Sunoco LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 800 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | |||||
5.875% senior notes due 2028 [Member] | Sunoco LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 400 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.875% | |||||
6.25% Senior Notes due 2021 [Member] | Sunoco LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 800 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 6.25% | |||||
5.5% Senior Notes due August 2020 [Member] | Sunoco LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 600 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | |||||
6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 800 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 6.375% | |||||
4.95% Senior Notes due 2028 [Member] | ETP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 1,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 4.95% | |||||
5.80% Senior Notes due 2038 [Member] | ETP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 500 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.80% | |||||
6.0% Senior Notes due 2048 [Member] | ETP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 1,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 6.00% | |||||
2.50% Senior Notes due June 2018 [Member] | ETP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 650 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 2.50% | |||||
7.00% Senior Notes, due June 15, 2018 [Member] | Panhandle [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 400 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 7.00% | |||||
6.7% Senior Notes, due July 1, 2018 [Member] | ETP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 600 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 6.70% | |||||
USAC Credit Facility, due 2023 [Member] | USA Compression Partners, LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,600 | |||||
USAC Credit Facility, due 2023 [Member] | USAC [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Line of Credit | 1,000 | |||||
Line of Credit Facility, Remaining Borrowing Capacity | 578 | |||||
USAC Credit Facility, due 2023 [Member] | Accordion feature [Member] | USA Compression Partners, LP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Line of Credit | 400 | |||||
6.875% Senior notes due April 2026 [Member] | USAC [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes | $ 725 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 6.875% | |||||
Subsequent Event [Member] | ETP Credit Facility due December 2022 [Member] | ETP [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 5,000 | |||||
Line of Credit Facility, Increase (Decrease), Net | $ 1,000 | |||||
[1] | As adjusted. See Note 1. |
Redeemable Noncontrolling Int_2
Redeemable Noncontrolling Interest (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | |||
Apr. 30, 2018 | Sep. 30, 2018 | Apr. 02, 2018 | Dec. 31, 2017 | |
Redeemable noncontrolling interests | $ 499 | $ 21 | ||
ETP [Member] | ||||
Redeemable noncontrolling interests | 22 | |||
USAC [Member] | ||||
Redeemable noncontrolling interests | $ 477 | |||
Preferred Units [Member] | USAC [Member] | ||||
Preferred Units, Issued | 500,000 | |||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ 24.375 | |||
Shares Issued, Price Per Share | $ 1,000 | |||
Proceeds from Issuance of Preferred Limited Partners Units | $ 500 |
Equity Narrative (Details)
Equity Narrative (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||||||||
Jul. 31, 2018 | Apr. 30, 2018 | Feb. 28, 2018 | Jan. 31, 2018 | Dec. 31, 2018 | Sep. 30, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Apr. 02, 2018 | Dec. 31, 2017 | ||
Payments for Repurchase of Common Stock | $ 24 | $ 0 | [1] | ||||||||
Other Comprehensive Income (Loss), Securities, Available-for-sale, Adjustment, before Reclassification Adjustments, after Tax | $ 2 | ||||||||||
Limited Partners' Capital Account, Units Outstanding | 1,158,200,000 | 1,158,200,000 | 1,079,145,561 | ||||||||
Stock Issued During Period, Shares, Conversion of Units | 79,100,000 | ||||||||||
Series A Convertible Preferred Units | $ 0 | $ 0 | $ 450 | ||||||||
Losses from subsidiary common unit transactions | (125) | (57) | |||||||||
Units issued for cash | 0 | 568 | [1] | ||||||||
Stock Repurchase Program, Remaining Authorized Repurchase Amount | $ 936 | 936 | |||||||||
Payments for Repurchase of Preferred Stock and Preference Stock | $ 0 | $ 53 | [1] | ||||||||
ETP [Member] | |||||||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 27,500,000 | 27,500,000 | |||||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ 57 | ||||||||||
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | $ 0 | ||||||||||
Sunoco LP [Member] | |||||||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 2,300,000 | 2,300,000 | |||||||||
Payments for Repurchase of Common Stock | $ 540 | ||||||||||
Stock Repurchased During Period, Shares | 17,286,859 | ||||||||||
USAC [Member] | |||||||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 20,500,000 | 20,500,000 | |||||||||
Limited Partners' Capital Account, Units Outstanding | 89,966,676 | 89,966,676 | |||||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ 0.4 | ||||||||||
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 24,261 | ||||||||||
ETE [Member] | |||||||||||
Equity Distribution Agreements, Value of Units Available to be Issued | $ 1,000 | $ 1,000 | |||||||||
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement | $ 0 | ||||||||||
Series A Preferred Units [Member] | |||||||||||
Preferred Stock, Shares Issued | 950,000 | 950,000 | |||||||||
Series A Preferred Units [Member] | Sunoco LP [Member] | |||||||||||
Preferred Stock Redemption Premium | $ 313 | ||||||||||
Payments for Repurchase of Preferred Stock and Preference Stock | $ 300 | ||||||||||
Call premium on preferred units. | 1.00% | ||||||||||
Series B Preferred Units [Member] | |||||||||||
Preferred Stock, Shares Issued | 550,000 | 550,000 | |||||||||
Series D Preferred Units [Member] | |||||||||||
Preferred Units, Issued | 17,800,000 | ||||||||||
Preferred Stock, Dividend Rate, Percentage | 7.625% | ||||||||||
Shares Issued, Price Per Share | $ 25 | ||||||||||
Proceeds from Issuance of Preferred Limited Partners Units | $ 445 | ||||||||||
Preferred Units, Liquidation Spread, Percent | 4.378% | ||||||||||
Series C Preferred Units [Member] | |||||||||||
Preferred Units, Issued | 18,000,000 | ||||||||||
Preferred Stock, Dividend Rate, Percentage | 7.375% | ||||||||||
Shares Issued, Price Per Share | $ 25 | ||||||||||
Proceeds from Issuance of Preferred Limited Partners Units | $ 450 | ||||||||||
Preferred Units, Liquidation Spread, Percent | 4.53% | ||||||||||
Convertible Preferred Stock [Member] | |||||||||||
Limited Partners' Capital Account, Units Outstanding | 0 | 0 | 329,300,000 | ||||||||
Stock Issued During Period, Shares, Conversion of Units | (329,300,000) | ||||||||||
ETP [Member] | USAC [Member] | |||||||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 19,191,351 | 19,191,351 | |||||||||
ETP [Member] | Class B Units [Member] | USAC [Member] | |||||||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 6,397,965 | 6,397,965 | |||||||||
ETE [Member] | USAC [Member] | |||||||||||
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent. | 20,466,912 | 20,466,912 | |||||||||
Series A Convertible Preferred Units [Member] | |||||||||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ 0.11 | ||||||||||
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 | ||||||||||
ETE Merger [Member] | Subsequent Event [Member] | |||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 1,460,000,000 | ||||||||||
ETE Merger [Member] | Subsequent Event [Member] | Sunoco LP [Member] | |||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 2,263,158 | ||||||||||
ETE Merger [Member] | Subsequent Event [Member] | USAC [Member] | |||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 12,466,912 | ||||||||||
ETE Merger [Member] | ETP [Member] | Subsequent Event [Member] | Sunoco LP [Member] | |||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 2,874,275 | ||||||||||
ETE Merger [Member] | ETP [Member] | Subsequent Event [Member] | USAC [Member] | |||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 16,134,903 | ||||||||||
ETE Merger [Member] | ETE Class A Units [Member] | Subsequent Event [Member] | |||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 650,000,000 | ||||||||||
[1] | As adjusted. See Note 1. |
Equity Table - Change In ETE Co
Equity Table - Change In ETE Common Units (Details) | 9 Months Ended |
Sep. 30, 2018shares | |
Class of Stock [Line Items] | |
Stock Issued During Period, Shares, Conversion of Units | 79,100,000 |
Outstanding at December 31, 2017 | 1,079,145,561 |
Outstanding at March 31, 2018 | 1,158,200,000 |
Convertible Preferred Stock [Member] | |
Class of Stock [Line Items] | |
Stock Issued During Period, Shares, Conversion of Units | (329,300,000) |
Outstanding at December 31, 2017 | 329,300,000 |
Outstanding at March 31, 2018 | 0 |
Equity Table - Quarterly Distri
Equity Table - Quarterly Distributions of Available Cash (Details) - $ / shares | 3 Months Ended | |||
Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | |
Distribution Made to Limited Partner, Date of Record | Nov. 8, 2018 | Aug. 6, 2018 | May 7, 2018 | Feb. 8, 2018 |
Distribution Made to Limited Partner, Distribution Date | Nov. 19, 2018 | Aug. 20, 2018 | May 21, 2018 | Feb. 20, 2018 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.3050 | $ 0.3050 | $ 0.3050 | $ 0.3050 |
USAC [Member] | ||||
Distribution Made to Limited Partner, Date of Record | Oct. 29, 2018 | Jul. 30, 2018 | May 1, 2018 | |
Distribution Made to Limited Partner, Distribution Date | Nov. 9, 2018 | Aug. 10, 2018 | May 11, 2018 | |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.5250 | $ 0.5250 | $ 0.5250 | |
ETP [Member] | ||||
Distribution Made to Limited Partner, Date of Record | Aug. 6, 2018 | May 7, 2018 | Feb. 8, 2018 | |
Distribution Made to Limited Partner, Distribution Date | Aug. 14, 2018 | May 15, 2018 | Feb. 14, 2018 | |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.5650 | $ 0.5650 | $ 0.5650 | |
Sunoco LP [Member] | ||||
Distribution Made to Limited Partner, Date of Record | Nov. 6, 2018 | Aug. 7, 2018 | May 7, 2018 | Feb. 6, 2018 |
Distribution Made to Limited Partner, Distribution Date | Nov. 14, 2018 | Aug. 15, 2018 | May 15, 2018 | Feb. 14, 2018 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.8255 | $ 0.8255 | $ 0.8255 | $ 0.8255 |
Preferred Units [Member] | ||||
Distribution Made to Limited Partner, Date of Record | Nov. 1, 2018 | Aug. 1, 2018 | Feb. 1, 2018 | |
Distribution Made to Limited Partner, Distribution Date | Nov. 15, 2018 | Aug. 15, 2018 | Feb. 15, 2018 | |
Series A Preferred Units [Member] | ||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 31.250 | $ 15.451 | ||
Series B Preferred Units [Member] | ||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | 33.125 | $ 16.378 | ||
Series C Preferred Units [Member] | ||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.4609 | $ 0.5634 | ||
Series D Preferred Units [Member] | ||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.5931 | |||
Series A Convertible Preferred Units [Member] | Parent Company [Member] | ||||
Distribution Made to Limited Partner, Date of Record | May 7, 2018 | Feb. 8, 2018 | ||
Distribution Made to Limited Partner, Distribution Date | May 21, 2018 | Feb. 20, 2018 | ||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.1100 | $ 0.1100 |
Equity Table - Accumulated Othe
Equity Table - Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2018 | Dec. 31, 2017 | ||
Partners' Capital Notes [Abstract] | |||
Available-for-sale securities | [1] | $ 6 | $ 8 |
Foreign currency translation adjustment | (5) | (5) | |
Actuarial gain related to pensions and other postretirement benefits | (7) | (5) | |
AOCI attributable to equity method investments | 14 | 5 | |
Subtotal | 8 | 3 | |
Amounts attributable to noncontrolling interest | 8 | (3) | |
Accumulated other comprehensive income, net | $ 0 | $ 0 | |
[1] | Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which resulted in the reclassification of $2 million from ETP’s accumulated other comprehensive income related to available-for-sale securities to ETP’s common unitholders. The amount is reflected as a change in noncontrolling interest in the Partnership’s consolidated financial statements. |
Income Taxes (Details)
Income Taxes (Details) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2018USD ($) | Sep. 30, 2018USD ($) | |
Income Tax Disclosure [Abstract] | ||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount | $ 113 | $ 164 |
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Reserves | $ 530 | $ 530 |
Regulatory Matters, Commitmen_3
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details) | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||
Feb. 28, 2018USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($) | |
Lessee, Operating Lease, Term of Contract | 15 years | 15 years | ||||
Operating Leases, Rent Expense, Contingent Rentals | $ 1,000,000 | $ 3,000,000 | $ 3,000,000 | $ 13,000,000 | ||
Loss Contingency Accrual, at Carrying Value | 62,000,000 | 62,000,000 | $ 53,000,000 | |||
Amounts recorded in balance sheets for contingencies and current litigation not disclosed | 0 | 0 | ||||
Payments for Environmental Liabilities | 17,000,000 | $ 8,000,000 | 32,000,000 | $ 26,000,000 | ||
Accrual for Environmental Loss Contingencies | $ 390,000,000 | $ 390,000,000 | $ 372,000,000 | |||
Civil penalties | $ 12,600,000 | |||||
Sunoco, Inc. [Member] | ||||||
Loss Contingency, Pending Claims, Number | 6 | 6 | ||||
Williams [Member] | ||||||
Loss on Contract Termination for Default | $ 410,000,000 | |||||
Loss Contingency, Damages Sought, Value | 10,000,000,000 | |||||
Rover Pipeline LLC [Member] | ||||||
Proposed Environmental Penalty | $ 2,600,000 | 2,600,000 | ||||
ETE [Member] | ||||||
Loss Contingency, Damages Sought, Value | $ 8,500,000 | |||||
Sunoco [Member] | ||||||
Site Contingency, Number of Sites Needing Remediation | 41 | 41 | ||||
Compensatory Damages [Member] | ||||||
Gain Contingency, Unrecorded Amount | $ 319,000,000 | $ 319,000,000 | ||||
Final Judgement [Member] | ||||||
Gain Contingency, Unrecorded Amount | 536,000,000 | 536,000,000 | ||||
Expense Reimbursement [Member] | ||||||
Gain Contingency, Unrecorded Amount | 1,000,000 | 1,000,000 | ||||
Disgorgement [Member] | ||||||
Gain Contingency, Unrecorded Amount | 595,000,000 | 595,000,000 | ||||
4.875% senior notes due 2023 [Member] | Sunoco LP [Member] | ||||||
Senior Notes | $ 1,000,000,000 | $ 1,000,000,000 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 4.875% | 4.875% | ||||
5.500% senior notes due 2026 [Member] | Sunoco LP [Member] | ||||||
Senior Notes | $ 800,000,000 | $ 800,000,000 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | 5.50% | ||||
5.875% senior notes due 2028 [Member] | Sunoco LP [Member] | ||||||
Senior Notes | $ 400,000,000 | $ 400,000,000 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 5.875% | 5.875% | ||||
Minimum [Member] | ||||||
Lessee, Operating Lease, Term of Contract | 5 years | 5 years | ||||
Maximum [Member] | ||||||
Lessee, Operating Lease, Term of Contract | 40 years | 40 years |
Regulatory Matters, Commitmen_4
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Rent expense table (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | ||
Rental expense (1) | [1] | $ 43 | $ 49 | $ 117 | $ 130 |
Less: Sublease rental income | (11) | (7) | (28) | (19) | |
Rental expense, net | $ 32 | $ 42 | $ 89 | $ 111 | |
[1] | Includes contingent rentals totaling $1 million and $3 million for three months ended September 30, 2018 and 2017, respectively and $3 million and $13 million for the nine months ended September 30, 2018 and 2017, respectively. |
Regulatory Matters, Commitmen_5
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Environmental Exit Cost [Line Items] | ||
Current | $ 43 | $ 35 |
Non-current | 347 | 337 |
Total environmental liabilities | $ 390 | $ 372 |
Revenue (Details)
Revenue (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2018 | Dec. 31, 2017 | |
Deferred Revenue | $ 383 | $ 383 | |
Contract with Customer, Asset, Net | 66 | 66 | $ 51 |
Contract with Customer, Liability, Revenue Recognized | 12 | 75 | |
Contract with Customer, Asset, Reclassified to Receivable | 15 | ||
Increase (Decrease) in Accounts Receivable | 137 | ||
Contract with Customer, Liability | 1 | 1 | 1 |
Receivables from Customers | 582 | 582 | $ 445 |
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Modification of Contract | 0 | ||
Sunoco LP [Member] | |||
Capitalized Contract Cost, Amortization | $ 4 | $ 10 |
Revenue Disaggregation of reven
Revenue Disaggregation of revenue (Details) $ in Millions | Sep. 30, 2018USD ($) |
Revenue from Contract with Customer [Abstract] | |
Revenue, Remaining Performance Obligation, Amount | $ 41,684 |
Derivative Assets And Liabili_4
Derivative Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details) | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2018bushelsMegawattBBtuMB_bls | Dec. 31, 2017bushelsbarrelsMegawattBBtubbl | ||
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Short [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | |||
Maximum Term Of Commodity Derivatives | 2,020 | 2,020 | |
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Forwards Swaps [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Future [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Maximum Term Of Commodity Derivatives | 2,020 | ||
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | 2,018 | |
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Forwards Swaps [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Future [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Fair Value Hedging [Member] | Maximum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Fair Value Hedging [Member] | Maximum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Fair Value Hedging [Member] | Maximum [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Fair Value Hedging [Member] | Minimum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Fair Value Hedging [Member] | Minimum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Fair Value Hedging [Member] | Minimum [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Short [Member] | |||
Notional Volume | (7,705) | ||
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Long [Member] | |||
Notional Volume | (4,650) | ||
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Long [Member] | |||
Notional Volume | (69,145) | (87,253) | |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Short [Member] | |||
Notional Volume | (1,834) | (4,390) | |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Short [Member] | |||
Notional Volume | (54,151) | (145,105) | |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Long [Member] | |||
Notional Volume | [1] | (69,685) | (48,510) |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Short [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Long [Member] | |||
Notional Volume | (358) | (1,078) | |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Short [Member] | |||
Notional Volume | (17,273) | ||
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Long [Member] | |||
Notional Volume | (13,000) | ||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Maximum Term Of Commodity Derivatives | 2,021 | 2,020 | |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | 2,019 | |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | |||
Maximum Term Of Commodity Derivatives | 2,020 | 2,019 | |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Maximum Term Of Commodity Derivatives | 2,020 | ||
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | 2,018 | |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | 2,018 | |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | 2,018 | |
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Short [Member] | |||
Notional Volume | (21,475) | (39,770) | |
Maximum Term Of Commodity Derivatives | 2,018 | ||
Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Short [Member] | |||
Notional Volume | (21,475) | (39,770) | |
Maximum Term Of Commodity Derivatives | 2,018 | ||
Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | Long [Member] | |||
Notional Volume | (21,475) | (39,770) | |
Maximum Term Of Commodity Derivatives | 2,018 | ||
NGL [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Short [Member] | |||
Notional Volume | (4,937) | (2,493) | |
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Short [Member] | |||
Notional Volume | Megawatt | (153,600) | ||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Long [Member] | |||
Notional Volume | Megawatt | (157,435) | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Call Option [Member] | Long [Member] | |||
Notional Volume | Megawatt | (321,240) | (137,600) | |
Maximum Term Of Commodity Derivatives | 2,018 | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forwards Swaps [Member] | Long [Member] | |||
Notional Volume | Megawatt | (429,720) | (435,960) | |
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Short [Member] | |||
Notional Volume | Megawatt | (25,760) | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Long [Member] | |||
Notional Volume | Megawatt | (309,123) | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Options - Puts [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Call Option [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Forwards Swaps [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | 2,019 | |
Power [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Future [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Options - Puts [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Call Option [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Power [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Forwards Swaps [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | 2,018 | |
Power [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Future [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Long [Member] | |||
Notional Volume | (35,228) | (9,237) | |
Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Forwards Swaps [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Forwards Swaps [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Refined Products [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Short [Member] | |||
Notional Volume | (1,507) | (3,901) | |
Refined Products [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Future [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Refined Products [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Future [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Corn [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
Corn [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Short [Member] | |||
Notional Volume | bushels | (3,100) | ||
Corn [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Long [Member] | |||
Notional Volume | bushels | (1,870) | ||
Corn [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Future [Member] | |||
Maximum Term Of Commodity Derivatives | 2,019 | ||
Corn [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Future [Member] | |||
Maximum Term Of Commodity Derivatives | 2,018 | ||
[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_5
Derivative Assets And Liabilities Table - Interest Rate Swaps Outstanding (Details) - USD ($) $ in Millions | 9 Months Ended | ||
Sep. 30, 2018 | Dec. 31, 2017 | ||
March 2019 [Member] | |||
Notional Amount | $ 300 | $ 300 | |
Type | [1] | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | |
December 2018 [Member] | |||
Notional Amount | $ 1,200 | 1,200 | |
Type | [1] | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | |
July 2020 [Member] | |||
Notional Amount | [2] | $ 400 | 400 |
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | |
July 2021 [Member] | |||
Notional Amount | [2] | $ 400 | 0 |
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.55% and receive a floating rate | |
July 2019 [Member] | |||
Notional Amount | [2] | $ 400 | 300 |
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.56% and receive a floating rate | |
July 2018 [Member] | |||
Notional Amount | [2] | $ 0 | $ 300 |
Type | [1],[2] | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | |
[1] | Floating rates are based on 3-month LIBOR. | ||
[2] | Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date. |
Derivative Assets And Liabili_6
Derivative Assets And Liabilities Table - Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Total derivatives assets | $ 603 | $ 321 |
Total derivatives liabilities | (974) | (560) |
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member] | ||
Total derivatives assets | 0 | 14 |
Total derivatives liabilities | (6) | (2) |
Not Designated as Hedging Instrument [Member] | ||
Total derivatives assets | 603 | 307 |
Total derivatives liabilities | (968) | (558) |
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member] | ||
Total derivatives assets | 477 | 262 |
Total derivatives liabilities | (537) | (281) |
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member] | ||
Total derivatives assets | 126 | 45 |
Total derivatives liabilities | (334) | (58) |
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member] | ||
Total derivatives assets | 0 | 0 |
Total derivatives liabilities | (97) | (219) |
Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | 877 | 341 |
Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | 7 | (2) |
Level 1 | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | 839 | 303 |
Level 1 | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | 0 | 0 |
Level 2 | Fair Value, Measurements, Recurring [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | 38 | 38 |
Level 2 | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | ||
Price Risk Derivative Liabilities, at Fair Value | $ (7) | $ (2) |
Derivative Assets And Liabili_7
Derivative Assets And Liabilities Table - Gross FV and Netting Offset (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 603 | $ 321 |
Derivative Liability, Fair Value, Gross Liability | (974) | (560) |
Counterparty netting | (29) | (21) |
Counterparty netting | 29 | 21 |
Payments on margin deposit | (477) | (263) |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 477 | 263 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 97 | 37 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | (468) | (276) |
Without offsetting agreements [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 97 | 219 |
OTC Contracts [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 126 | 45 |
Derivative Liability, Fair Value, Gross Liability | (334) | (58) |
Broker cleared derivative contracts [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 477 | 276 |
Derivative Liability, Fair Value, Gross Liability | $ (543) | $ (283) |
Derivative Assets And Liabili_8
Derivative Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Amount of Gain (Loss) Recognized (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Amount of Gain/(Loss) Recognized in Income on Derivatives | $ 69 | $ (38) | $ (192) | $ (12) |
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member] | ||||
Amount of Gain/(Loss) Recognized in Income on Derivatives | 3 | (5) | 36 | 21 |
Commodity Derivatives [Member] | Cost of Products Sold [Member] | ||||
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | 0 | 2 | 9 | 4 |
Amount of Gain/(Loss) Recognized in Income on Derivatives | 21 | (25) | (345) | (6) |
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member] | ||||
Amount of Gain/(Loss) Recognized in Income on Derivatives | 45 | (8) | 117 | (28) |
Embedded Derivatives [Member] | Other Income (Expenses) [Member] | ||||
Amount of Gain/(Loss) Recognized in Income on Derivatives | $ 0 | $ 0 | $ 0 | $ 1 |
Related Party Transactions Rela
Related Party Transactions Related Party Revenue (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Related Party Transactions [Abstract] | ||||
Revenue from Related Parties | $ 103 | $ 105 | $ 325 | $ 201 |
Reportable Segments Table - Seg
Reportable Segments Table - Segment Adjusted EBITDA (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | [1] | Sep. 30, 2018 | Sep. 30, 2017 | [1] | |
Segment Reporting Information [Line Items] | ||||||
Segment Adjusted EBITDA | $ 2,577 | $ 1,949 | $ 6,841 | $ 5,243 | ||
Depreciation, depletion and amortization | (750) | (642) | (2,109) | (1,877) | ||
Interest expense, net | (535) | (490) | (1,511) | (1,440) | ||
Impairment losses | 0 | (10) | 0 | (99) | ||
Gains (losses) on interest rate derivatives | 45 | (8) | 117 | (28) | ||
Non-cash compensation expense | (27) | (29) | (82) | (76) | ||
Unrealized gains (losses) on commodity risk management activities | 97 | (76) | (255) | 22 | ||
Sunoco LP Series A Preferred Units redemption | 18 | 5 | 14 | 0 | ||
Losses on extinguishments of debt | 0 | 0 | (106) | (25) | ||
Inventory valuation adjustments | (7) | 50 | 50 | 8 | ||
Equity in earnings of unconsolidated affiliates | 87 | 92 | 258 | 228 | ||
Adjusted EBITDA related to unconsolidated affiliates | (179) | (205) | (503) | (554) | ||
Adjusted EBITDA attributable to discontinued operations | 0 | (76) | 25 | (179) | ||
Other, net | (15) | (24) | (45) | (76) | ||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) | 1,341 | 584 | 2,784 | 1,299 | ||
Income tax (benefit) expense from continuing operations | 52 | 157 | (6) | 86 | ||
Income from continuing operations | 1,393 | 741 | 2,778 | 1,385 | ||
Income (loss) from discontinued operations, net of income taxes | (2) | 17 | (265) | (187) | ||
Net income, excluding amounts attributable to redeemable noncontrolling interests | 1,391 | 758 | 2,513 | 1,198 | ||
Investment In ETP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Segment Adjusted EBITDA | 2,329 | 1,784 | 6,261 | 4,774 | ||
Investment In Sunoco LP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Segment Adjusted EBITDA | 208 | 199 | 457 | 574 | ||
Investment In USAC [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Segment Adjusted EBITDA | 90 | 0 | 185 | 0 | ||
Investment in Lake Charles LNG [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Segment Adjusted EBITDA | 43 | 43 | 131 | 131 | ||
Corporate and Other [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Segment Adjusted EBITDA | (9) | (3) | (17) | (25) | ||
Adjustments And Eliminations [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Segment Adjusted EBITDA | $ (84) | $ (74) | $ (176) | $ (211) | ||
[1] | As adjusted. See Note 1. |
Reportable Segments Table - S_2
Reportable Segments Table - Segment Assets (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Assets | $ 88,187 | $ 86,246 |
Investment In ETP [Member] | ||
Assets | 79,156 | 77,965 |
Investment In Sunoco LP [Member] | ||
Assets | 5,148 | 8,344 |
Investment In USAC [Member] | ||
Assets | 3,814 | 0 |
Investment in Lake Charles LNG [Member] | ||
Assets | 1,746 | 1,646 |
Corporate and Other [Member] | ||
Assets | 625 | 598 |
Adjustments And Eliminations [Member] | ||
Assets | $ (2,302) | $ (2,307) |
Reportable Segments Table - Rev
Reportable Segments Table - Revenues (External and Intersegment) by Investments (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | [1] | Sep. 30, 2018 | Sep. 30, 2017 | [1] | |
Revenues | $ 14,514 | $ 9,984 | $ 40,514 | $ 29,072 | ||
Investment In ETP [Member] | ||||||
Revenues | 9,641 | 6,973 | 27,331 | 20,444 | ||
Investment In Sunoco LP [Member] | ||||||
Revenues | 4,761 | 3,064 | 13,117 | 8,764 | ||
Investment In USAC [Member] | ||||||
Revenues | 169 | 0 | 336 | 0 | ||
Adjustments And Eliminations [Member] | ||||||
Revenues | (107) | (102) | (418) | (284) | ||
Intersegment [Member] | Investment In ETP [Member] | ||||||
Revenues | 103 | 97 | 410 | 276 | ||
Intersegment [Member] | Investment In Sunoco LP [Member] | ||||||
Revenues | 1 | 6 | 3 | 9 | ||
Intersegment [Member] | Investment In USAC [Member] | ||||||
Revenues | 3 | 0 | 5 | 0 | ||
External Customers [Member] | Investment In ETP [Member] | ||||||
Revenues | 9,538 | 6,876 | 26,921 | 20,168 | ||
External Customers [Member] | Investment In Sunoco LP [Member] | ||||||
Revenues | 4,760 | 3,058 | 13,114 | 8,755 | ||
External Customers [Member] | Investment In USAC [Member] | ||||||
Revenues | 166 | 0 | 331 | 0 | ||
External Customers [Member] | Investment in Lake Charles LNG [Member] | ||||||
Revenues | $ 50 | $ 49 | $ 148 | $ 148 | ||
[1] | As adjusted. See Note 1. |
Reportable Segments Table - Re
Reportable Segments Table - Revenues from External Customers by Segment (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |||
Segment Reporting Information [Line Items] | ||||||
Revenues | $ 14,514 | $ 9,984 | [1] | $ 40,514 | $ 29,072 | [1] |
Investment In USAC [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 169 | 0 | [1] | 336 | 0 | [1] |
Investment In Sunoco LP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 4,761 | 3,064 | [1] | 13,117 | 8,764 | [1] |
Investment In ETP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 9,641 | 6,973 | [1] | 27,331 | 20,444 | [1] |
Intersegment [Member] | Investment In USAC [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 3 | 0 | [1] | 5 | 0 | [1] |
Intersegment [Member] | Investment In Sunoco LP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 1 | 6 | [1] | 3 | 9 | [1] |
Intersegment [Member] | Investment In ETP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 103 | 97 | [1] | 410 | 276 | [1] |
External Customers [Member] | Investment In USAC [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 166 | 0 | [1] | 331 | 0 | [1] |
External Customers [Member] | Investment In Sunoco LP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 4,760 | 3,058 | [1] | 13,114 | 8,755 | [1] |
External Customers [Member] | Investment In ETP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 9,538 | 6,876 | [1] | 26,921 | 20,168 | [1] |
Contract operations revenue [Member] | Investment In USAC [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 163 | 0 | 323 | 0 | ||
Intrastate Transportation And Storage [Member] | Investment In ETP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 846 | 729 | [1] | 2,424 | 2,196 | [1] |
Interstate Transportation and Storage [Member] | Investment In ETP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 390 | 220 | [1] | 1,026 | 652 | [1] |
Midstream [Member] | Investment In ETP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 537 | 665 | [1] | 1,571 | 1,863 | [1] |
NGL and refined products transportation and services [Member] | Investment In ETP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 2,948 | 1,989 | [1] | 7,878 | 5,874 | [1] |
Crude oil transportation and services [Member] | Investment In ETP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 4,422 | 2,714 | [1] | 12,942 | 7,749 | [1] |
Other Operations [Member] | Investment In ETP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 498 | 656 | [1] | 1,490 | 2,110 | [1] |
Retail Operations [Member] | Investment In Sunoco LP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 267 | 597 | 1,134 | 1,682 | ||
Wholesale Operations [Member] | Investment In Sunoco LP [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 4,494 | 2,467 | 11,983 | 7,082 | ||
Retail [Member] | Investment In USAC [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | 5 | 0 | 11 | 0 | ||
Station installations revenue [Member] | Investment In USAC [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues | $ 1 | $ 0 | $ 2 | $ 0 | ||
[1] | As adjusted. See Note 1. |
Supplemental Financial Statem_3
Supplemental Financial Statement Information Table - Balance Sheets (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Jan. 01, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Dec. 31, 2016 | ||
Accounts payable to related companies | $ 58 | $ 31 | |||||
Cash and cash equivalents | 398 | 336 | $ 475 | [1] | $ 467 | [1] | |
Accounts receivable from related companies | 80 | 53 | |||||
Other current assets | 303 | $ 303 | 295 | ||||
Total current assets | 7,527 | 10,683 | |||||
Property, plant and equipment, net | 65,643 | 61,088 | 61,088 | ||||
Advances to and investments in unconsolidated affiliates | 2,656 | 2,705 | |||||
Goodwill | 5,242 | 4,768 | |||||
Other non-current assets, net | 1,106 | 925 | 886 | ||||
Total assets | 88,187 | 86,246 | |||||
Accrued and other current liabilities | 3,088 | 2,582 | |||||
Total current liabilities | 10,219 | 7,897 | |||||
Long-term debt, less current maturities | 42,117 | 43,671 | |||||
Other non-current liabilities | 1,253 | $ 1,218 | 1,217 | ||||
Commitments and contingencies | |||||||
Series A Convertible Preferred Units | 0 | 450 | |||||
Common Unitholders | (1,099) | (1,643) | |||||
General Partner | (4) | (3) | |||||
Total partners’ capital | (1,103) | (1,196) | |||||
Total liabilities and equity | 88,187 | 86,246 | |||||
Parent Company [Member] | |||||||
Accounts payable to related companies | 42 | 0 | |||||
Cash and cash equivalents | 1 | 1 | $ 0 | $ 2 | |||
Accounts receivable from related companies | 100 | 65 | |||||
Other current assets | 1 | 1 | |||||
Total current assets | 102 | 67 | |||||
Property, plant and equipment, net | 27 | 27 | |||||
Advances to and investments in unconsolidated affiliates | 6,045 | 6,082 | |||||
Goodwill | 9 | 9 | |||||
Other non-current assets, net | 7 | 8 | |||||
Total assets | 6,190 | 6,193 | |||||
Interest payable | 78 | 66 | |||||
Accrued and other current liabilities | 9 | 4 | |||||
Total current liabilities | 129 | 70 | |||||
Long-term debt, less current maturities | 6,415 | 6,700 | |||||
Long-term notes payable – related companies | 747 | 617 | |||||
Other non-current liabilities | 2 | 2 | |||||
Commitments and contingencies | |||||||
Series A Convertible Preferred Units | 0 | 450 | |||||
Common Unitholders | (1,099) | (1,643) | |||||
General Partner | (4) | (3) | |||||
Total partners’ capital | (1,103) | (1,196) | |||||
Total liabilities and equity | $ 6,190 | $ 6,193 | |||||
[1] | As adjusted. See Note 1. |
Supplemental Financial Statem_4
Supplemental Financial Statement Information Schedule of Statements of Operations (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |||
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ (184) | $ (142) | [1] | $ (515) | $ (480) | [1] |
Interest expense, net | (535) | (490) | [1] | (1,511) | (1,440) | [1] |
Equity in earnings of unconsolidated affiliates | 87 | 92 | [1] | 258 | 228 | [1] |
Losses on extinguishments of debt | 0 | 0 | [1] | (106) | (25) | [1] |
Other, net | 23 | 54 | [1] | 83 | 133 | [1] |
NET INCOME | 371 | 252 | [1] | 1,077 | 703 | [1] |
Convertible Unitholders' interest in income | 0 | 11 | [1] | 33 | 25 | [1] |
General Partner’s interest in net income | 1 | 1 | [1] | 3 | 2 | [1] |
Limited Partners’ interest in net income | 370 | 240 | [1] | 1,041 | 676 | [1] |
Parent Company [Member] | ||||||
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | 9 | (3) | 20 | 25 | ||
Interest expense, net | 89 | (88) | 265 | 257 | ||
Equity in earnings of unconsolidated affiliates | 469 | 343 | 1,359 | 1,012 | ||
Losses on extinguishments of debt | 0 | 0 | 0 | (25) | ||
Other, net | 0 | 0 | 3 | (2) | ||
NET INCOME | 371 | 252 | 1,077 | 703 | ||
Convertible Unitholders' interest in income | 0 | 11 | ||||
General Partner’s interest in net income | 1 | 1 | 3 | 2 | ||
Limited Partners’ interest in net income | $ 370 | $ 240 | $ 1,041 | $ 676 | ||
[1] | As adjusted. See Note 1. |
Supplemental Financial Statem_5
Supplemental Financial Statement Information Schedule Of Statements of Cash Flows (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |||
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ 5,295 | $ 3,410 | [1] | |||
Contributions to unconsolidated affiliate | 13 | 230 | [1] | |||
Capital expenditures | 5,175 | 6,126 | [1] | |||
Contributions in aid of construction costs | 95 | 25 | [1] | |||
Sunoco LP Series A Preferred Units redemption | $ 18 | $ 5 | [1] | 14 | 0 | [1] |
Net cash provided by (used in) investing activities | (4,763) | (4,785) | [1] | |||
Proceeds from borrowings | 22,126 | 23,988 | [1] | |||
Repayments of long-term debt | (23,323) | (22,536) | [1] | |||
Proceeds from affiliate | 438 | 919 | [1] | |||
Distributions to partners | (886) | (752) | [1] | |||
Units issued for cash | 0 | 568 | [1] | |||
Debt issuance costs | (188) | (85) | [1] | |||
Net cash provided by (used in) financing activities | (3,208) | 1,303 | [1] | |||
CHANGE IN CASH AND CASH EQUIVALENTS | 62 | 8 | [1] | |||
Cash and cash equivalents, beginning of period | 336 | 467 | [1] | |||
Cash and cash equivalents, end of period | 398 | 475 | [1] | 398 | 475 | [1] |
Parent Company [Member] | ||||||
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | 993 | 620 | ||||
Contributions to unconsolidated affiliate | 250 | 861 | ||||
Capital expenditures | 0 | 1 | ||||
Contributions in aid of construction costs | 0 | (7) | ||||
Sunoco LP Series A Preferred Units redemption | 303 | 0 | ||||
Net cash provided by (used in) investing activities | 53 | (855) | ||||
Proceeds from borrowings | 413 | 2,116 | ||||
Repayments of long-term debt | (703) | (1,795) | ||||
Proceeds from affiliate | 130 | 131 | ||||
Distributions to partners | (886) | (752) | ||||
Units issued for cash | 0 | 568 | ||||
Debt issuance costs | 0 | (35) | ||||
Net cash provided by (used in) financing activities | (1,046) | 233 | ||||
CHANGE IN CASH AND CASH EQUIVALENTS | 0 | (2) | ||||
Cash and cash equivalents, beginning of period | 1 | 2 | ||||
Cash and cash equivalents, end of period | $ 1 | $ 0 | $ 1 | $ 0 | ||
[1] | As adjusted. See Note 1. |
Uncategorized Items - ete-20180
Label | Element | Value |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction Start Date Axis: (nil) | ||
Revenue, Remaining Performance Obligation, Amount | us-gaap_RevenueRemainingPerformanceObligation | $ 41,680,000,000 |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction Start Date Axis: 2019-12-31 | ||
Revenue, Remaining Performance Obligation, Amount | us-gaap_RevenueRemainingPerformanceObligation | 5,258,000,000 |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction Start Date Axis: 2021-12-31 | ||
Revenue, Remaining Performance Obligation, Amount | us-gaap_RevenueRemainingPerformanceObligation | 30,256,000,000 |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction Start Date Axis: 2018-12-31 | ||
Revenue, Remaining Performance Obligation, Amount | us-gaap_RevenueRemainingPerformanceObligation | 1,474,000,000 |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction Start Date Axis: 2020-12-31 | ||
Revenue, Remaining Performance Obligation, Amount | us-gaap_RevenueRemainingPerformanceObligation | $ 4,696,000,000 |