View Filing Data

$ 1,024

$ 1,022

^[1]

$ 2,086

$ 2,034

2,141

1,485

^[1]

4,171

3,032

4,241

2,345

^[1]

7,495

4,887

1,464

1,067

^[1]

2,861

2,091

413

304

^[1]

852

775

127

353

^[1]

225

652

Total revenues

9,410

6,576

^[1]

17,690

13,471

COSTS AND EXPENSES:

7,140

4,624

^[1]

13,128

9,674

Depreciation, depletion and amortization

627

539

^[1]

1,231

1,031

588

557

^[1]

1,191

1,117

Selling, general and administrative

112

120

^[1]

224

230

Total costs and expenses

8,467

5,840

^[1]

15,774

12,052

Equity in earnings (losses) of unconsolidated affiliates

943

736

^[1]

1,916

1,419

OTHER INCOME (EXPENSE):

Interest expense, net

(358)

(336)

^[1]

(704)

(668)

106

(61)

^[1]

^[1]

172

Gains (losses) on interest rate derivatives

(86)

(25)

^[1]

(20)

Other, net

^[1]

106

INCOME BEFORE INCOME TAX EXPENSE

671

375

^[1]

1,510

823

Income tax expense

^[1]

134

NET INCOME

602

296

^[1]

1,481

689

Less: Net income attributable to noncontrolling interest

170

^[1]

334

156

NET INCOME ATTRIBUTABLE TO PARTNERS

432

202

^[1]

1,147

533

Series A Preferred Units Interest in Net Income

^[1]

Series B Preferred Units Interest in Net Income

^[1]

Series C Preferred Units Interest in Net Income

^[1]

General Partner’s interest in net income

402

251

^[1]

804

457

Class H Unitholder’s interest in net income

^[1]

Common Unitholders’ interest in net income (loss)

$ 0

$ (49)

^[1]

$ 289

$ (17)

NET INCOME (LOSS) PER COMMON UNIT:

$ (0.01)

$ (0.04)

^[1]

$ 0.23

$ (0.02)

Statement of Comprehensive Income [Abstract]

$ (0.01)

$ (0.04)

^[1]

$ 0.23

$ (0.02)

[1]	* As adjusted. See Note 1.

Consolidated Statements Of Comprehensive Income - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2018

Jun. 30, 2017

^[1]

Jun. 30, 2018

Jun. 30, 2017

^[1]

Other comprehensive income (loss), net of tax:

$ 602

$ 296

$ 1,481

$ 689

Change in value of available-for-sale securities

(2)

Actuarial loss relating to pension and other postretirement benefit plans

(1)

(2)

(3)

Change in other comprehensive income from unconsolidated affiliates

(1)

Total other comprehensive income (loss)

(1)

Less: Comprehensive income attributable to noncontrolling interest

604

295

1,484

688

170

334

156

$ 434

$ 201

$ 1,150

$ 532

[1]	* As adjusted. See Note 1.

Consolidated Statement Of Equity - 6 months ended Jun. 30, 2018 - USD ($) $ in Millions	Total	Series A Preferred Units [Member]	Series B Preferred Units [Member]	Series C Preferred Units [Member]	Common Units	General Partner	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Balance, December 31, 2017 at Dec. 31, 2017	$ 34,151	$ 944	$ 547	$ 0	$ 26,531	$ 244	$ 3	$ 5,882
Distributions to partners	(2,011)	(15)	(9)	0	(1,315)	(672)	0	0
Distributions to noncontrolling interest	(359)	0	0	0	0	0	0	(359)
Units issued for cash	475	0	0	436	39	0	0	0
Capital contributions from noncontrolling interest	318	0	0	0	0	0	0	318
Repurchases of common units	(24)	0	0	0	(24)	0	0	0
Other comprehensive income, net of tax	3	0	0	0	0	0	3	0
Other, net	2	1	0	0	26	17	(2)	(4)
Net income	1,481	30	18	6	289	804	0	334
Balance, June 30, 2018 at Jun. 30, 2018	$ 34,036	$ 958	$ 556	$ 442	$ 25,546	$ 359	$ 4	$ 6,171

Consolidated Statements Of Cash Flows - USD ($)
$ in Millions

6 Months Ended

Jun. 30, 2018

Jun. 30, 2017

^[1]

OPERATING ACTIVITIES

Reconciliation of net income to net cash provided by operating activities:

$ 1,481

$ 689

Depreciation, depletion and amortization

1,191

1,117

Deferred income taxes

121

Non-cash compensation expense

(172)

Distributions on unvested awards

(17)

(15)

Equity in earnings of unconsolidated affiliates

(34)

(12)

Distributions from unconsolidated affiliates

215

197

Other non-cash

(122)

(98)

Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations

229

(387)

Net cash provided by operating activities

2,950

1,650

INVESTING ACTIVITIES

Cash proceeds from Bakken pipeline transaction

2,000

Cash proceeds from CDM contribution

1,227

Cash proceeds from Sunoco LP common unit repurchase

540

Cash paid for acquisition of PennTex noncontrolling interest

(280)

Cash paid for all other acquisitions

261

Capital expenditures, excluding allowance for equity funds used during construction

(3,409)

(2,842)

Contributions in aid of construction costs

Contributions to unconsolidated affiliates

(13)

(225)

Distributions from unconsolidated affiliates in excess of cumulative earnings

Proceeds from the sale of assets

Net cash used in investing activities

(7)

(1,591)

(1,486)

FINANCING ACTIVITIES

Proceeds from borrowings

12,476

11,466

Repayments of debt

(12,018)

(10,953)

Cash paid to affiliate notes

(255)

Common units issued for cash

990

Preferred units issued for cash

436

Capital contributions from noncontrolling interest

318

456

Distributions to partners

(2,011)

(1,702)

Distributions to noncontrolling interest

(359)

(186)

Repurchases of common units

Redemption of Legacy ETP Preferred Units

(53)

Debt issuance costs

Net cash used in financing activities

(1,171)

(252)

Increase (decrease) in cash and cash equivalents

188

(88)

Cash and cash equivalents, beginning of period

306

360

Cash and cash equivalents, end of period

$ 494

$ 272

[1]	* As adjusted. See Note 1.

Operations And Basis of Presentation

6 Months Ended

Jun. 30, 2018

Operations And Organization [Abstract]

Operations And Organization

ORGANIZATION AND BASIS OF PRESENTATION

Organization

Energy Transfer Partners, L.P. (“ETP”) is a consolidated subsidiary of ETE. In August 2018, ETE and ETP announced that they have entered into a definitive agreement providing for the merger of ETP with a wholly-owned subsidiary of ETE in a unit-for-unit exchange. In connection with the transaction, ETE’s IDRs in ETP will be cancelled. Under the terms of the transaction, ETP unitholders (other than ETE and its subsidiaries) will receive 1.28 common units of ETE for each common unit of ETP they own. The transaction is expected to close in the fourth quarter of 2018, subject to the approval by a majority of the unaffiliated unitholders of ETP and other customary closing conditions.

In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction (the “Sunoco Logistics Merger”), with the Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. In connection with the Sunoco Logistics Merger, Sunoco Logistics was renamed Energy Transfer Partners, L.P. and Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.

The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes).

The consolidated financial statements of the Partnership presented herein include our operating subsidiaries (collectively, the “Operating Companies”), through which our activities are primarily conducted, as follows:

•

ETC OLP, Regency and PennTex, which are primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP and Regency own and operate, through their wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico, West Virginia, Colorado and Ohio.


•	Energy Transfer Interstate Holdings, LLC, (“ETIH”) with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales, which is the parent company of:


•	Transwestern, engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.


•	ETC Fayetteville Express Pipeline, LLC, which directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.


•	ETC Tiger Pipeline, LLC, engaged in interstate transportation of natural gas.


•	CrossCountry Energy, LLC, which indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.


•	ETC Midcontinent Express Pipeline, L.L.C., which directly owns a 50% interest in MEP.


•	ET Rover Pipeline, LLC, which ETIH directly owns a 50.1% interest in, which owns a 65% interest in the Rover pipeline.


•	ETC Compression, LLC, engaged in natural gas compression services and related equipment sales. As discussed further in Note 2 below, in April 2018, we contributed certain assets to USAC.

•

ETP Holdco, which indirectly owns Panhandle and Sunoco, Inc. Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. Sunoco Inc.’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES. ETP Holdco also holds an equity method investment in ETP through its ownership of ETP Class E, Class G, and Class K units, which investment is eliminated in ETP’s consolidated financial statements.


•	Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.

We currently have the following reportable business segments:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

Prior periods have been retrospectively adjusted to reflect the impact of the Sunoco Logistics Merger on our reportable business segments.

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 of Energy Transfer Partners, L.P. for the year ended December 31, 2017, included in the Partnership’s Annual Report on Form 10-K 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.

The historical common units and net income per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.

For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.

Change in Accounting Policy

Inventory Accounting Change

During the fourth quarter of 2017, the Partnership elected to change its 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 products and NGLs associated with the legacy Sunoco Logistics business. 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, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

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 June 30, 2017									Six Months Ended June 30, 2017
	As Originally Reported			Effect of Change			As Adjusted			As Originally Reported			Effect of Change			As Adjusted
Cost of products sold ⁽¹⁾	$	4,628		$	(4	)	$	4,624		$	9,707		$	(33	)	$	9,674
Operating income	732			4			736			1,386			33			1,419
Income before income tax expense	371			4			375			790			33			823
Net income	292			4			296			656			33			689
Net income attributable to partners	199			3			202			523			10			533
Net loss per common unit – basic	(0.04		)	—			(0.04		)	(0.04		)	0.02			(0.02		)
Net loss per common unit – diluted	(0.04		)	—			(0.04		)	(0.04		)	0.02			(0.02		)
Comprehensive income	291			4			295			655			33			688
Comprehensive income attributable to partners	198			3			201			522			10			532

⁽¹⁾As originally reported amounts reflect certain reclassifications made to conform to the current year presentation.

As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows:



	Six Months Ended June 30, 2017
	As Originally Reported			Effect of Change			As Adjusted
Net income	$	656		$	33		$	689
Inventory valuation adjustments	56			(56		)	—
Net change in operating assets and liabilities, net of effects from acquisitions (change in inventories)	(410		)	23			(387		)

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 multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. 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.

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.

The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. 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 adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales and operating expenses. There were no material changes in the timing of recognition of revenue and therefore no material impacts to the balance sheet upon adoption.

The disclosure below shows the impact of adopting the new standard during the period of adoption compared to amounts that would have been reported under the Partnership’s previous revenue recognition policies:



	Three Months Ended June 30, 2018							Six Months Ended June 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	$	1,024	$	1,024	$	—		$	2,086	$	2,086	$	—
NGL sales	2,141		2,134		7			4,171		4,153		18
Crude sales	4,241		4,238		3			7,495		7,488		7
Gathering, transportation and other fees	1,464		1,611		(147		)	2,861		3,194		(333		)
Refined product sales	413		413		—			852		852		—
Other	127		127		—			225		225		—

Costs and expenses:
Cost of products sold	$	7,140	$	7,287	$	(147	)	$	13,128	$	13,461	$	(333	)
Operating expenses	627		617		10			1,231		1,206		25

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 useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. 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 Topic 840. The Partnership expects to adopt ASU 2016-02 and elect the practical expedient under ASU 2018-01 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

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 and Other Transactions	6 Months Ended
Acquisitions and Other Transactions	Jun. 30, 2017
Acquisitions [Abstract]
Business Combination Disclosure [Text Block]	ACQUISITIONS AND OTHER INVESTING TRANSACTIONS CDM Contribution On April 2, 2018, 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 common units representing limited partner interests in USAC, (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, ETP’s consolidated financial statements reflected an equity method investment in USAC. CDM’s assets and liabilities were not reflected as held for sale, nor were CDM’s results reflected as discontinued operations in these financial statements. At June 30, 2018, the carrying value of ETP’s investment in USAC was $399 million, which is reflected in the all other segment. ETP recorded a $86 million loss on the deconsolidation of CDM including a $45 million accrual related to the indemnification of USAC related to an ongoing CDM sales and use tax audit. In connection with the CDM Contribution, ETE acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC, and (ii) 12,466,912 USAC common units for cash consideration equal to $250 million.

Advances to and Investments in Affiliates (Notes)	6 Months Ended
Advances to and Investments in Affiliates (Notes)	Jun. 30, 2018
Schedule of Equity Method Investments [Line Items]
Investments in and Advances to Affiliates, Schedule of Investments [Text Block]	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES 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 ETP’s financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in ETP’s financial statements. Sunoco LP In February 2018, after 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. As of June 30, 2018, ETP owns 26.2 million Sunoco LP common units representing 31.8% of Sunoco LP’s total outstanding common units. Our investment in Sunoco LP is reflected in the all other segment. As of June 30, 2018, the carrying value of our investment in Sunoco LP is $535 million. USAC As of June 30, 2018, ETP owns 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests in USAC. USAC provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. Our investment in USAC is reflected in the all other segment. As of June 30, 2018, the carrying value of our investment in USAC is $399 million.

Cash And Cash Equivalents

6 Months Ended

Jun. 30, 2018

Cash and Cash Equivalents [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

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.

The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows:



	Six Months Ended June 30,
	2018			2017*
Accounts receivable	$	236		$	88
Accounts receivable from related companies	156			(115		)
Inventories	299			160
Other current assets	(375		)	77
Other non-current assets, net	(3		)	(39		)
Accounts payable	(465		)	(286		)
Accounts payable to related companies	(99		)	131
Accrued and other current liabilities	249			(389		)
Other non-current liabilities	(2		)	7
Derivative assets and liabilities, net	233			(21		)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	229		$	(387	)

* As adjusted. See Note 1.

Non-cash investing and financing activities are as follows:



	Six Months Ended June 30,
	2018		2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,007	$	1,363
USAC limited partner interests received in the CDM Contribution (see Note 2)	411		—
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	—	$	988

Cash And Cash Equivalents

Non-cash investing and financing activities are as follows:



	Six Months Ended June 30,
	2018		2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,007	$	1,363
USAC limited partner interests received in the CDM Contribution (see Note 2)	411		—
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	—	$	988

Inventories

6 Months Ended

Jun. 30, 2018

Inventory, Gross [Abstract]

Inventories

INVENTORIES

Inventories consisted of the following:



	June 30, 2018		December 31, 2017
Natural gas, NGLs and refined products	$	434	$	733
Crude oil	571		551
Spare parts and other	251		305
Total inventories	$	1,256	$	1,589

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.

Fair Value Measurements

6 Months Ended

Jun. 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 June 30, 2018 was $33.64 billion and $33.90 billion, respectively. As of December 31, 2017, the aggregate fair value and carrying amount of our consolidated debt obligations was $34.28 billion and $33.09 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the 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 six months ended June 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 June 30, 2018 and December 31, 2017 based on inputs used to derive their fair values:



				Fair Value Measurements at June 30, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	22		$	22		$	—
Swing Swaps IFERC	1			—			1
Fixed Swaps/Futures	11			11			—
Forward Physical Contracts	9			—			9
Power:
Forwards	69			—			69
Options – Puts	1			1			—
NGLs – Forwards/Swaps	300			300			—
Total commodity derivatives	413			334			79
Other non-current assets	21			14			7
Total assets	$	434		$	348		$	86
Liabilities:
Interest rate derivatives	$	(147	)	$	—		$	(147	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(70		)	(70		)	—
Swing Swaps IFERC	(2		)	(1		)	(1		)
Fixed Swaps/Futures	(14		)	(14		)	—
Forward Physical Contracts	(5		)	—			(5		)
Power – Forwards	(57		)	—			(57		)
NGLs – Forwards/Swaps	(316		)	(316		)	—
Refined Products – Futures	(5		)	(5		)	—
Crude – Forwards/Swaps	(307		)	(307		)	—
Total commodity derivatives	(776		)	(713		)	(63		)
Total liabilities	$	(923	)	$	(713	)	$	(210	)



				Fair Value Measurements at December 31, 2017
	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 Swaps	8			—			8
Power – Forwards	23			—			23
NGLs – Forwards/Swaps	191			191			—
Crude:
Forwards/Swaps	2			2			—
Futures	2			2			—
Total commodity derivatives	320			276			44
Other non-current assets	21			14			7
Total assets	$	341		$	290		$	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 Swaps	(2		)	—			(2		)
Power – Forwards	(22		)	—			(22		)
NGLs – Forwards/Swaps	(186		)	(186		)	—
Refined Products – Futures	(25		)	(25		)	—
Crude:
Forwards/Swaps	(6		)	(6		)	—
Futures	(1		)	(1		)	—
Total commodity derivatives	(338		)	(300		)	(38		)
Total liabilities	$	(557	)	$	(300	)	$	(257	)

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Net Income Per Limited Partner Unit

6 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

Net Income (Loss) Per Limited Partner Unit [Text Block]

NET INCOME (LOSS) PER LIMITED PARTNER UNIT

A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017*			2018			2017*
Net income	$	602		$	296		$	1,481		$	689
Less: Income attributable to noncontrolling interest	170			94			334			156
Net income, net of noncontrolling interest	432			202			1,147			533
Series A Preferred Unitholders’ interest in net income	15			—			30			—
Series B Preferred Unitholders’ interest in net income	9			—			18			—
Series C Preferred Unitholders’ interest in net income	6			—			6			—
General Partner’s interest in net income	402			251			804			457
Class H Unitholder’s interest in net income	—			—			—			93
Common Unitholders’ interest in net income (loss)	—			(49		)	289			(17		)
Additional (earnings) distributions allocated to General Partner	(1		)	15			(3		)	12
Distributions on employee unit awards, net of allocation to General Partner	(7		)	(6		)	(15		)	(13		)
Net income (loss) available to Common Unitholders	$	(8	)	$	(40	)	$	271		$	(18	)
Weighted average Common Units – basic	1,165.4			1,021.7			1,164.6			922.5
Basic net income (loss) per Common Unit	$	(0.01	)	$	(0.04	)	$	0.23		$	(0.02	)

Weighted average Common Units – diluted	1,165.4			1,021.7			1,169.4			922.5
Diluted net income (loss) per Common Unit	$	(0.01	)	$	(0.04	)	$	0.23		$	(0.02	)

* As adjusted. See Note 1.

For certain periods reflected above, distributions paid for the period exceeded net income attributable to partners. Accordingly, the distributions paid to preferred unitholders and the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.

Debt Obligations	6 Months Ended
Debt Obligations	Jun. 30, 2018
Debt Disclosure [Abstract]
Debt Obligations	DEBT OBLIGATIONS 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 our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our 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. Credit Facilities and Commercial Paper ETP Five-Year Credit Facility ETP’s revolving credit facility (the “ETP Five-Year Credit Facility”) allows for unsecured borrowings up to $4.00 billion and matures in December 2022. 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 June 30, 2018, the ETP Five-Year Credit Facility had $1.23 billion outstanding, all of which was commercial paper. The amount available for future borrowings was $2.61 billion after taking into account letters of credit of $167 million. The weighted average interest rate on the total amount outstanding as of June 30, 2018 was 2.87%. ETP 364-Day Facility ETP’s 364-day revolving credit facility (the “ETP 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 30, 2018. As of June 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 June 30, 2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of June 30, 2018 was 3.72%. Compliance with Our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of June 30, 2018.

Equity

6 Months Ended

Jun. 30, 2018

Partners' Capital Notes [Abstract]

Equity

EQUITY

The changes in outstanding common units during the six months ended June 30, 2018 were as follows:



	Number of Units
Number of common units at December 31, 2017	1,164.1
Common units issued in connection with the distribution reinvestment plan	2.1
Common units issued in connection with certain transactions	1.3
Issuance of common units under equity incentive plans	0.1
Repurchases of common units in open-market transactions	(1.2	)
Number of common units at June 30, 2018	1,166.4

Equity Distribution Program

During the six months ended June 30, 2018, there were no units issued under the Partnership’s equity distribution agreement. As of June 30, 2018, $752 million of the Partnership’s common units remained available to be issued under the Partnership’s existing $1.00 billion equity distribution agreement.

Distribution Reinvestment Program

During the six months ended June 30, 2018, distributions of $39 million were reinvested under the Partnership’s distribution reinvestment plan.

Preferred Units

ETP issued 950,000 Series A Preferred Units and 550,000 Series B Preferred Units in November 2017.

Series C Preferred Units Issuance

In April 2018, ETP issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per 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 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 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 Series C Preferred Units are redeemable at ETP’s option on or after May 15, 2023 at a redemption price of $25 per Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Series D Preferred Units Issuance

In July 2018, ETP issued 17.8 million of its 7.625% 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 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 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 Series D Preferred Units are redeemable at ETP’s option on or after August 15, 2023 at a redemption price of $25 per Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Cash Distributions

Under our limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

Distributions on common units declared and/or paid by the Partnership subsequent to December 31, 2017 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

ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods:



	Year Ending December 31,
2018 (remainder)	$	69
2019	128
Each year beyond 2019	33

Distributions on preferred units declared and/or paid by the Partnership subsequent to December 31, 2017 were as follows:



Period Ended	Record Date	Payment Date	Rate
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
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
Series C Preferred Units
June 30, 2018	August 1, 2018	August 15, 2018	$	0.56337

Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:



	June 30, 2018			December 31, 2017
Available-for-sale securities ⁽¹⁾	$	4		$	8
Foreign currency translation adjustment	(5		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(7		)	(5		)
Investments in unconsolidated affiliates, net	12			5
Total AOCI, net of tax	$	4		$	3


⁽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 accumulated other comprehensive income related to available-for-sale securities to common unitholders.

Income Taxes (Notes)	6 Months Ended
Income Taxes (Notes)	Jun. 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 six months ended June 30, 2018, the Partnership’s income tax benefit also reflected $3 million and $70 million, respectively, of deferred benefit adjustments as the result of a state statutory rate reduction.

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

6 Months Ended

Jun. 30, 2018

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Guarantee of Sunoco LP Notes

In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to certain of Sunoco LP’s senior notes and $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).

On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes, repaid and terminated the term loan and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:


•	$1.00 billion aggregate principal amount of 4.875% senior notes due 2023;


•	$800 million aggregate principal amount of 5.50% senior notes due 2026; and


•	$400 million aggregate principal amount of 5.875% senior notes due 2028.

Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.

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 audit is ongoing.

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.

Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. 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 June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Rental expense	$	22	$	19	$	39	$	39

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 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 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 Tribes 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 Tribe.

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. Following the completion of the remand process by the USACE, 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 June 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.

Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. On April 5, 2018, the Court entered an Order dismissing the matter with prejudice.

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.

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.

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, 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. Defendants’ motions to dismiss are due on or before September 10, 2018.

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 June 30, 2018 and December 31, 2017, accruals of approximately $52 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 West Whiteland 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 West Whiteland Township.

Following a hearing on May 7 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 and geophysical studies within the Township. The ALJ’s Order was immediately effective, and SPLP complied by shutting down service on ME1 and discontinuing all construction in the Township on ME2 and ME2x. The ALJ’s Order was automatically certified as a material question to the PUC, which issued an Opinion and Order on June 15, 2018 (following a public meeting on June 14, 2018) that reversed in part and affirmed in part the ALJ’s Order. PUC’s Opinion and Order permitted SPLP to resume service on ME1, but continued the shutdown of construction on ME2 and ME2x pending the submission of the following three types of information to PUC: (i) inspection and testing protocols; (ii) comprehensive emergency response plan; and (iii) safety training curriculum for employees and contractors. SPLP submitted the required information on June 22, 2018. On July 2, 2018, Senator Dinniman and intervenors responded to the submission. SPLP is also required to provide an affidavit that the Pennsylvania Department of Environmental Protection (“DEP”) has issued appropriate approvals for construction of ME2 and ME2x in the Township before recommencing construction of ME2 and ME2x locations within the Township. SPLP submitted all necessary affidavits. On August 2, 2018 the PUC entered an Order lifting the stay of construction on ME2 and ME2x in West Whiteland Township with respect to all areas within the Township where the necessary environmental permits had been issued. Also on August 2, 2018, the PUC ratified its prior action by notational voting of certifying for interlocutory appeal to the Pennsylvania Commonwealth Court the legal issue of whether Senator Dinniman has standing to pursue the action.

Service on ME1 was resumed in accordance with PUC’s Opinion and Order. Senator Dinniman’s Complaint will proceed forward under a schedule to be determined by the ALJ. A prehearing conference with the ALJ is scheduled for August 28, 2018.

On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project. On August 1, 2017 the EHB lifted the order as to two drill locations. On August 3, 2017, the EHB lifted the order as to 14 additional locations. The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”). The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting. On August 7, 2017 a final settlement was reached. A stipulated order has been submitted to the EHB Judge with respect to the settlement. The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project. The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation. Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits. Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company. On July 31, 2018 the underlying permit appeals in which the above settlements occurred were withdrawn in a settlement between the appellants and PADEP. That settlement did not involve SPLP.

In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project. Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval. SPLP has fulfilled the requirements of those agreements and has been authorized by PADEP to resume drilling the locations.

No amounts have been recorded in our June 30, 2018 or December 31, 2017 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Environmental Matters

Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January 2015. In May 2017, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July 2017, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. Since then, the parties have reached an agreement in principal to resolve all penalties. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality, and we are involved in settlement discussion with the agencies.

On January 3, 2018, PADEP issued an Administrative Order to SPLP directing that work on the Mariner East 2 and 2X pipelines be stopped. The Administrative Order detailed alleged violations of the permits issued by PADEP in February 2017, during the construction of the project. SPLP began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues. Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so SPLP took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, SPLP entered into a Consent Order and Agreement with PADEP that (i) withdraws the Administrative Order; (ii) establishes requirements for compliance with permits on a going forward basis; (iii) resolves the non-compliance alleged in the Administrative Order; and (iv) conditions restart of work on an agreement by SPLP to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, SPLP admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP. PADEP also found in the Consent Order and Agreement that SPLP had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. SPLP concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:


•	certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.


•	certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.


•	legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.

•

Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of June 30, 2018, Sunoco, Inc. had been named as a PRP at approximately 41 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

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.



	June 30, 2018		December 31, 2017
Current	$	42	$	36
Non-current	276		314
Total environmental liabilities	$	318	$	350

In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the three months ended June 30, 2018 and 2017, the Partnership recorded $6 million and $7 million, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2018 and 2017, the Partnership recorded $11 million and $13 million, respectively, of expenditures related to environmental programs.

On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, EPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 to the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

Our pipeline operations are subject to regulation by the United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Health and Safety Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

Revenue (Notes)

6 Months Ended

Jun. 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 six months ended June 30, 2017 were recorded under the Partnership’s previous accounting policies.

Disaggregation of revenue

The Partnership’s consolidated financial statements reflect the following six reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes:


•	intrastate transportation and storage;


•	interstate transportation and storage;


•	midstream;


•	NGL and refined products transportation and services;


•	crude oil transportation and services; and


•	all other.

Note 15 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.

Intrastate transportation and storage revenue

Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Interstate transportation and storage revenue

Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to 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.

Midstream revenue

Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported for our customers. The various types of revenue contracts our midstream segment enters into include:

Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed.

Keepwhole: Contracts under which we gather raw natural gas from a third party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed.

Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:


•	In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.

•

Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.

Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition.

Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints.

NGL and refined products transportation and services revenue

Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606.

Crude oil transportation and services revenue

Our crude oil transportation and service segment are primarily derived from 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. Payment for services under these contracts are typically due the month after the services have been performed.

Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606.

All other revenue

Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard.

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. As of June 30, 2018 and January 1, 2018, no contract assets have been recognized.

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. As of June 30, 2018, the Partnership had $235 million in deferred revenues representing the current value of our future performance obligations.

The amount of revenue recognized for the three and six months ended June 30, 2018 that was included in the deferred revenue liability balance as of January 1, 2018 was $28 million and $63 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 service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contacts, only the fixed component of the contracts are included in the table below.

As of June 30, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $40.32 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:



	2018 (remainder)		2019		2020		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of June 30, 2018	$	2,598	$	5,048	$	4,604	$	28,071	$	40,321

Practical Expedients Utilized by the Partnership

The Partnership elected the following practical expedients in accordance with Topic 606:

•

Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.


•	Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.


•	Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.

Derivative Assets And Liabilities

6 Months Ended

Jun. 30, 2018

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Price Risk Management Assets and Liabilities


	DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.

We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.

We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.

We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The following table details our outstanding commodity-related derivatives:



	June 30, 2018			December 31, 2017
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	465		2018	1,078		2018
Basis Swaps IFERC/NYMEX ⁽¹⁾	102,328		2018-2020	48,510		2018-2020
Options – Puts	(3,043	)	2018	13,000		2018
Power (Megawatt):
Forwards	3,196,100		2018-2019	435,960		2018-2019
Futures	(42,768	)	2018	(25,760	)	2018
Options – Puts	(30,532	)	2018	(153,600	)	2018
Options – Calls	996,172		2018	137,600		2018
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	6,600		2018-2020	4,650		2018-2020
Swing Swaps IFERC	52,413		2018-2019	87,253		2018-2019
Fixed Swaps/Futures	5,360		2018-2019	(4,700	)	2018-2019
Forward Physical Contracts	(174,465	)	2018-2020	(145,105	)	2018-2020
NGL (MBbls) – Forwards/Swaps	(1,590	)	2018-2019	(2,493	)	2018-2019
Crude (MBbls) – Forwards/Swaps	44,190		2018-2019	9,172		2018-2019
Refined Products (MBbls) – Futures	(1,076	)	2018-2019	(3,783	)	2018-2019
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(21,475	)	2018	(39,770	)	2018
Fixed Swaps/Futures	(21,475	)	2018	(39,770	)	2018
Hedged Item – Inventory	21,475		2018	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 our anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	June 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 terms 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 the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily 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
	June 30, 2018		December 31, 2017		June 30, 2018			December 31, 2017
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	14	$	(2	)	$	(2	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	307		262		(352		)	(281		)
Commodity derivatives	106		44		(422		)	(55		)
Interest rate derivatives	—		—		(147		)	(219		)
	413		306		(921		)	(555		)
Total derivatives	$	413	$	320	$	(923	)	$	(557	)

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	June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(147	)	$	(219	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	106			44			(422		)	(55		)
Broker cleared derivative contracts	Other current assets (liabilities)	307			276			(354		)	(283		)
Total gross derivatives		413			320			(923		)	(557		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(49		)	(20		)	49			20
Counterparty netting	Other current assets (liabilities)	(306		)	(263		)	306			263
Total net derivatives		$	58		$	37		$	(568	)	$	(274	)

We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized in income with respect to our derivative financial instruments:



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,				Six Months Ended June 30,
		2018		2017		2018		2017
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	6	$	6	$	9	$	2



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2018			2017			2018			2017
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	16		$	15		$	33		$	26
Commodity derivatives – Non-trading	Cost of products sold	(300		)	7			(373		)	(3		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Embedded derivatives	Other, net	—			—			—			1
Total		$	(264	)	$	(3	)	$	(268	)	$	4

Related Party Transactions

6 Months Ended

Jun. 30, 2018

Related Party Transactions

RELATED PARTY TRANSACTIONS

The Partnership has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.

The following table summarizes the affiliate revenues on our consolidated statements of operations:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Affiliated revenues	$	222	$	133	$	508	$	251

The following table summarizes the related company balances on our consolidated balance sheets:



	June 30, 2018		December 31, 2017
Accounts receivable from related companies:
Sunoco LP	$	184	$	219
FGT	18		11
Other	132		88
Total accounts receivable from related companies:	$	334	$	318

Accounts payable to related companies:
Sunoco LP	$	195	$	195
USAC	45		—
Other	89		14
Total accounts payable to related companies:	$	329	$	209



	June 30, 2018		December 31, 2017
Long-term notes receivable from related company:
Sunoco LP	$	85	$	85

Reportable Segments

6 Months Ended

Jun. 30, 2018

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS

Our financial statements currently reflect the following reportable segments, which conduct their business in the United States, as follows:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

The amounts included in the NGL and refined products transportation and services segment and the crude oil transportation and services segment have been retrospectively adjusted in these consolidated financial statements as a result of the Sunoco Logistics Merger.

Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales, refined product sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our all other segment are primarily reflected in other.

We report Segment Adjusted EBITDA as a measure of segment performance. 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 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. Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership's proportionate ownership.

The following tables present financial information by segment:



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	761		$	699		$	1,578		$	1,467
Intersegment revenues	52			54			110			102
	813			753			1,688			1,569
Interstate transportation and storage:
Revenues from external customers	323			201			636			432
Intersegment revenues	5			6			8			10
	328			207			644			442
Midstream:
Revenues from external customers	594			633			1,034			1,198
Intersegment revenues	1,280			982			2,454			2,054
	1,874			1,615			3,488			3,252
NGL and refined products transportation and services:
Revenues from external customers	2,472			1,767			4,930			3,885
Intersegment revenues	96			12			184			160
	2,568			1,779			5,114			4,045
Crude oil transportation and services:
Revenues from external customers	4,789			2,460			8,520			5,035
Intersegment revenues	14			5			28			5
	4,803			2,465			8,548			5,040
All other:
Revenues from external customers	471			816			992			1,454
Intersegment revenues	31			54			81			186
	502			870			1,073			1,640
Eliminations	(1,478		)	(1,113		)	(2,865		)	(2,517		)
Total revenues	$	9,410		$	6,576		$	17,690		$	13,471



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017*			2018			2017*
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	208		$	148		$	400		$	317
Interstate transportation and storage	330			262			653			527
Midstream	414			412			791			732
NGL and refined products transportation and services	461			388			912			769
Crude oil transportation and services	548			228			1,012			415
All other	90			107			164			230
Total	2,051			1,545			3,932			2,990
Depreciation, depletion and amortization	(588		)	(557		)	(1,191		)	(1,117		)
Interest expense, net	(358		)	(336		)	(704		)	(668		)
Gain on Sunoco LP common unit repurchase	—			—			172			—
Loss on deconsolidation of CDM	(86		)	—			(86		)	—
Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Non-cash compensation expense	(21		)	(15		)	(41		)	(38		)
Unrealized gains (losses) on commodity risk management activities	(265		)	34			(352		)	98
Adjusted EBITDA related to unconsolidated affiliates	(228		)	(247		)	(413		)	(486		)
Equity in earnings (losses) of unconsolidated affiliates	106			(61		)	34			12
Other, net	40			37			87			52
Income before income tax expense	$	671		$	375		$	1,510		$	823

* As adjusted. See Note 1.



	June 30, 2018		December 31, 2017
Assets:
Intrastate transportation and storage	$	5,604	$	5,020
Interstate transportation and storage	14,037		13,518
Midstream	19,949		20,004
NGL and refined products transportation and services	17,517		17,600
Crude oil transportation and services	18,168		17,736
All other	3,295		4,087
Total assets	$	78,570	$	77,965

Guarantor Financial Information (Notes)

6 Months Ended

Jun. 30, 2018

Guarantor Financial Information [Abstract]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, is the issuer of multiple series of senior notes that are guaranteed by ETP. These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer Partners, L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.”

The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting.

The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows:



	June 30, 2018
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—	$	—		$	494	$	—		$	494
All other current assets	—		57			8,527		(2,531		)	6,053
Property, plant and equipment, net	—		—			59,776		—			59,776
Investments in unconsolidated affiliates	51,199		12,078			3,636		(63,277		)	3,636
All other assets	8		—			8,603		—			8,611
Total assets	$	51,207	$	12,135		$	81,036	$	(65,808	)	$	78,570

Current liabilities	$	390	$	(3,571	)	$	12,353	$	(2,531	)	$	6,641
Non-current liabilities	22,949		7,606			7,338		—			37,893
Noncontrolling interest	—		—			6,171		—			6,171
Total partners’ capital	27,868		8,100			55,174		(63,277		)	27,865
Total liabilities and equity	$	51,207	$	12,135		$	81,036	$	(65,808	)	$	78,570



	December 31, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	(3	)	$	309	$	—		$	306
All other current assets	—			159			6,063		—			6,222
Property, plant and equipment, net	—			—			58,437		—			58,437
Investments in unconsolidated affiliates	48,378			11,648			3,816		(60,026		)	3,816
All other assets	—			—			9,184		—			9,184
Total assets	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965

Current liabilities	$	(1,496	)	$	(3,660	)	$	12,150	$	—		$	6,994
Non-current liabilities	21,604			7,607			7,609		—			36,820
Noncontrolling interest	—			—			5,882		—			5,882
Total partners’ capital	28,270			7,857			52,168		(60,026		)	28,269
Total liabilities and equity	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965



	Three Months Ended June 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	9,410		$	—		$	9,410
Operating costs, expenses, and other	—			—			8,467			—			8,467
Operating income	—			—			943			—			943
Interest expense, net	(289		)	(41		)	(28		)	—			(358		)
Equity in earnings of unconsolidated affiliates	701			66			106			(767		)	106
Gains on interest rate derivatives	20			—			—			—			20
Loss on deconsolidation of CDM	—			—			(86		)	—			(86		)
Other, net	—			—			46			—			46
Income before income tax expense	432			25			981			(767		)	671
Income tax expense	—			—			69			—			69
Net income	432			25			912			(767		)	602
Less: Net income attributable to noncontrolling interest	—			—			170			—			170
Net income attributable to partners	$	432		$	25		$	742		$	(767	)	$	432

Other comprehensive income	$	—		$	—		$	2		$	—		$	2
Comprehensive income	432			25			914			(767		)	604
Comprehensive income attributable to noncontrolling interest	—			—			170			—			170
Comprehensive income attributable to partners	$	432		$	25		$	744		$	(767	)	$	434



	Three Months Ended June 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,576		$	—		$	6,576
Operating costs, expenses, and other	—		1			5,839			—			5,840
Operating income (loss)	—		(1		)	737			—			736
Interest expense, net	—		(39		)	(297		)	—			(336		)
Equity in earnings (losses) of unconsolidated affiliates	199		137			(61		)	(336		)	(61		)
Losses on interest rate derivatives	—		—			(25		)	—			(25		)
Other, net	—		3			59			(1		)	61
Income before income tax expense	199		100			413			(337		)	375
Income tax expense	—		—			79			—			79
Net income	199		100			334			(337		)	296
Less: Net income attributable to noncontrolling interest	—		—			94			—			94
Net income attributable to partners	$	199	$	100		$	240		$	(337	)	$	202

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	199		100			333			(337		)	295
Comprehensive income attributable to noncontrolling interest	—		—			94			—			94
Comprehensive income attributable to partners	$	199	$	100		$	239		$	(337	)	$	201

* As adjusted. See Note 1.



	Six Months Ended June 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	17,690		$	—		$	17,690
Operating costs, expenses, and other	—			—			15,774			—			15,774
Operating income	—			—			1,916			—			1,916
Interest expense, net	(567		)	(82		)	(55		)	—			(704		)
Equity in earnings of unconsolidated affiliates	1,642			326			34			(1,968		)	34
Gains on interest rate derivatives	72			—			—			—			72
Gain on Sunoco LP unit repurchase	—			—			172			—			172
Loss on deconsolidation of CDM	—			—			(86		)	—			(86		)
Other, net	—			—			106			—			106
Income before income tax expense	1,147			244			2,087			(1,968		)	1,510
Income tax expense	—			—			29			—			29
Net income	1,147			244			2,058			(1,968		)	1,481
Less: Net income attributable to noncontrolling interest	—			—			334			—			334
Net income attributable to partners	$	1,147		$	244		$	1,724		$	(1,968	)	$	1,147

Other comprehensive income	$	—		$	—		$	3		$	—		$	3
Comprehensive income	1,147			244			2,061			(1,968		)	1,484
Comprehensive income attributable to noncontrolling interest	—			—			334			—			334
Comprehensive income attributable to partners	$	1,147		$	244		$	1,727		$	(1,968	)	$	1,150



	Six Months Ended June 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	13,471		$	—		$	13,471
Operating costs, expenses, and other	—		1			12,051			—			12,052
Operating income (loss)	—		(1		)	1,420			—			1,419
Interest expense, net	—		(81		)	(587		)	—			(668		)
Equity in earnings of unconsolidated affiliates	1,010		765			12			(1,775		)	12
Losses on interest rate derivatives	—		—			(20		)	—			(20		)
Other, net	—		3			78			(1		)	80
Income before income tax expense	1,010		686			903			(1,776		)	823
Income tax expense	—		—			134			—			134
Net income	1,010		686			769			(1,776		)	689
Less: Net income attributable to noncontrolling interest	—		—			156			—			156
Net income attributable to partners	$	1,010	$	686		$	613		$	(1,776	)	$	533

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	1,010		686			768			(1,776		)	688
Comprehensive income attributable to noncontrolling interest	—		—			156			—			156
Comprehensive income attributable to partners	$	1,010	$	686		$	612		$	(1,776	)	$	532

* As adjusted. See Note 1.



	Six Months Ended June 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	3,252		$	102		$	585		$	(989	)	$	2,950
Cash flows used in investing activities	(2,925		)	(99		)	(903		)	2,336			(1,591		)
Cash flows provided by (used in) financing activities	(327		)	—			503			(1,347		)	(1,171		)
Change in cash	—			3			185			—			188
Cash at beginning of period	—			(3		)	309			—			306
Cash at end of period	$	—		$	—		$	494		$	—		$	494



	Six Months Ended June 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	1,010		$	652		$	1,764		$	(1,776	)	$	1,650
Cash flows used in investing activities	(716		)	(421		)	(2,125		)	1,776			(1,486		)
Cash flows provided by (used in) financing activities	(294		)	(249		)	291			—			(252		)
Change in cash	—			(18		)	(70		)	—			(88		)
Cash at beginning of period	—			41			319			—			360
Cash at end of period	$	—		$	23		$	249		$	—		$	272

- Definition

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

+ References + Details

Operations And Basis of Presentation Accounting Policy (Policies)

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation

Accounting Changes [Policy Text Block]

Change in Accounting Policy

Inventory Accounting Change

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition Standard



	Three Months Ended June 30, 2018							Six Months Ended June 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	$	1,024	$	1,024	$	—		$	2,086	$	2,086	$	—
NGL sales	2,141		2,134		7			4,171		4,153		18
Crude sales	4,241		4,238		3			7,495		7,488		7
Gathering, transportation and other fees	1,464		1,611		(147		)	2,861		3,194		(333		)
Refined product sales	413		413		—			852		852		—
Other	127		127		—			225		225		—

Costs and expenses:
Cost of products sold	$	7,140	$	7,287	$	(147	)	$	13,128	$	13,461	$	(333	)
Operating expenses	627		617		10			1,231		1,206		25

Additional disclosures related to revenue are included in Note 12.

Disaggregation of revenue


•	intrastate transportation and storage;


•	interstate transportation and storage;


•	midstream;


•	NGL and refined products transportation and services;


•	crude oil transportation and services; and


•	all other.

Note 15 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.

Intrastate transportation and storage revenue

Interstate transportation and storage revenue

Midstream revenue


•	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.

•

Payment for services under these contracts are typically due the month after the services have been performed.

NGL and refined products transportation and services revenue

Crude oil transportation and services revenue

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 crude oil at market rates. These contracts were not affected by ASC 606.

All other revenue

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

New Accounting Pronouncements, Policy [Policy Text Block]

Recent Accounting Pronouncements

ASU 2016-02

ASU 2017-12

ASU 2018-02

Cash And Cash Equivalents Cash and Cash Equivalents (Policies)	6 Months Ended
	Jun. 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 (Policies)	6 Months Ended
Inventories Inventories (Policies)	Jun. 30, 2018
Inventory Disclosure [Abstract]
Inventory, Policy [Policy Text Block]	We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.

Fair Value Measurements Fair Value Measurements (Policies)	6 Months Ended
	Jun. 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 June 30, 2018 was $33.64 billion and $33.90 billion, respectively. As of December 31, 2017, the aggregate fair value and carrying amount of our consolidated debt obligations was $34.28 billion and $33.09 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the 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 six months ended June 30, 2018, no transfers were made between any levels within the fair value hierarchy.

Revenue (Policies)

6 Months Ended

Jun. 30, 2018

Revenue [Abstract]

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition Standard



	Three Months Ended June 30, 2018							Six Months Ended June 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	$	1,024	$	1,024	$	—		$	2,086	$	2,086	$	—
NGL sales	2,141		2,134		7			4,171		4,153		18
Crude sales	4,241		4,238		3			7,495		7,488		7
Gathering, transportation and other fees	1,464		1,611		(147		)	2,861		3,194		(333		)
Refined product sales	413		413		—			852		852		—
Other	127		127		—			225		225		—

Costs and expenses:
Cost of products sold	$	7,140	$	7,287	$	(147	)	$	13,128	$	13,461	$	(333	)
Operating expenses	627		617		10			1,231		1,206		25

Additional disclosures related to revenue are included in Note 12.

Disaggregation of revenue


•	intrastate transportation and storage;


•	interstate transportation and storage;


•	midstream;


•	NGL and refined products transportation and services;


•	crude oil transportation and services; and


•	all other.

Note 15 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.

Intrastate transportation and storage revenue

Interstate transportation and storage revenue

Midstream revenue


•	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.

•

Payment for services under these contracts are typically due the month after the services have been performed.

NGL and refined products transportation and services revenue

Crude oil transportation and services revenue

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 crude oil at market rates. These contracts were not affected by ASC 606.

All other revenue

Revenue Recognition, Deferred Revenue [Policy Text Block]

Contract Balances with Customers

Derivative Assets And Liabilities Derivative Assets and Liabilities (Policies)	6 Months Ended
	Jun. 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 the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily 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 segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

Operations And Basis of Presentation Operations and Basis of Presentation (Tables)

6 Months Ended

Jun. 30, 2018

Operations and Basis of Presentation [Abstract]

Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]

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 June 30, 2017									Six Months Ended June 30, 2017
	As Originally Reported			Effect of Change			As Adjusted			As Originally Reported			Effect of Change			As Adjusted
Cost of products sold ⁽¹⁾	$	4,628		$	(4	)	$	4,624		$	9,707		$	(33	)	$	9,674
Operating income	732			4			736			1,386			33			1,419
Income before income tax expense	371			4			375			790			33			823
Net income	292			4			296			656			33			689
Net income attributable to partners	199			3			202			523			10			533
Net loss per common unit – basic	(0.04		)	—			(0.04		)	(0.04		)	0.02			(0.02		)
Net loss per common unit – diluted	(0.04		)	—			(0.04		)	(0.04		)	0.02			(0.02		)
Comprehensive income	291			4			295			655			33			688
Comprehensive income attributable to partners	198			3			201			522			10			532

⁽¹⁾As originally reported amounts reflect certain reclassifications made to conform to the current year presentation.

As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows:



	Six Months Ended June 30, 2017
	As Originally Reported			Effect of Change			As Adjusted
Net income	$	656		$	33		$	689
Inventory valuation adjustments	56			(56		)	—
Net change in operating assets and liabilities, net of effects from acquisitions (change in inventories)	(410		)	23			(387		)



	Three Months Ended June 30, 2018							Six Months Ended June 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	$	1,024	$	1,024	$	—		$	2,086	$	2,086	$	—
NGL sales	2,141		2,134		7			4,171		4,153		18
Crude sales	4,241		4,238		3			7,495		7,488		7
Gathering, transportation and other fees	1,464		1,611		(147		)	2,861		3,194		(333		)
Refined product sales	413		413		—			852		852		—
Other	127		127		—			225		225		—

Costs and expenses:
Cost of products sold	$	7,140	$	7,287	$	(147	)	$	13,128	$	13,461	$	(333	)
Operating expenses	627		617		10			1,231		1,206		25

Additional disclosures related to revenue are included in Note 12.

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]



	2018 (remainder)		2019		2020		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of June 30, 2018	$	2,598	$	5,048	$	4,604	$	28,071	$	40,321

Cash And Cash Equivalents (Tables)

6 Months Ended

Jun. 30, 2018

Cash and Cash Equivalents [Abstract]

Net Cash Provided By Operating Activities

The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows:



	Six Months Ended June 30,
	2018			2017*
Accounts receivable	$	236		$	88
Accounts receivable from related companies	156			(115		)
Inventories	299			160
Other current assets	(375		)	77
Other non-current assets, net	(3		)	(39		)
Accounts payable	(465		)	(286		)
Accounts payable to related companies	(99		)	131
Accrued and other current liabilities	249			(389		)
Other non-current liabilities	(2		)	7
Derivative assets and liabilities, net	233			(21		)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	229		$	(387	)

* As adjusted. See Note 1.

Non-Cash Investing And Financing Activities

Non-cash investing and financing activities are as follows:



	Six Months Ended June 30,
	2018		2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,007	$	1,363
USAC limited partner interests received in the CDM Contribution (see Note 2)	411		—
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	—	$	988

Inventories (Tables)

6 Months Ended

Jun. 30, 2018

Inventory, Gross [Abstract]

Schedule Of Inventories

Inventories consisted of the following:



	June 30, 2018		December 31, 2017
Natural gas, NGLs and refined products	$	434	$	733
Crude oil	571		551
Spare parts and other	251		305
Total inventories	$	1,256	$	1,589

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2018

Fair Value Measurements [Abstract]

Fair Value Of Assets And Liabilities Measured And Recorded On Recurring Basis



				Fair Value Measurements at June 30, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	22		$	22		$	—
Swing Swaps IFERC	1			—			1
Fixed Swaps/Futures	11			11			—
Forward Physical Contracts	9			—			9
Power:
Forwards	69			—			69
Options – Puts	1			1			—
NGLs – Forwards/Swaps	300			300			—
Total commodity derivatives	413			334			79
Other non-current assets	21			14			7
Total assets	$	434		$	348		$	86
Liabilities:
Interest rate derivatives	$	(147	)	$	—		$	(147	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(70		)	(70		)	—
Swing Swaps IFERC	(2		)	(1		)	(1		)
Fixed Swaps/Futures	(14		)	(14		)	—
Forward Physical Contracts	(5		)	—			(5		)
Power – Forwards	(57		)	—			(57		)
NGLs – Forwards/Swaps	(316		)	(316		)	—
Refined Products – Futures	(5		)	(5		)	—
Crude – Forwards/Swaps	(307		)	(307		)	—
Total commodity derivatives	(776		)	(713		)	(63		)
Total liabilities	$	(923	)	$	(713	)	$	(210	)



				Fair Value Measurements at December 31, 2017
	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 Swaps	8			—			8
Power – Forwards	23			—			23
NGLs – Forwards/Swaps	191			191			—
Crude:
Forwards/Swaps	2			2			—
Futures	2			2			—
Total commodity derivatives	320			276			44
Other non-current assets	21			14			7
Total assets	$	341		$	290		$	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 Swaps	(2		)	—			(2		)
Power – Forwards	(22		)	—			(22		)
NGLs – Forwards/Swaps	(186		)	(186		)	—
Refined Products – Futures	(25		)	(25		)	—
Crude:
Forwards/Swaps	(6		)	(6		)	—
Futures	(1		)	(1		)	—
Total commodity derivatives	(338		)	(300		)	(38		)
Total liabilities	$	(557	)	$	(300	)	$	(257	)

Net Income Per Limited Partner Unit (Tables)

6 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017*			2018			2017*
Net income	$	602		$	296		$	1,481		$	689
Less: Income attributable to noncontrolling interest	170			94			334			156
Net income, net of noncontrolling interest	432			202			1,147			533
Series A Preferred Unitholders’ interest in net income	15			—			30			—
Series B Preferred Unitholders’ interest in net income	9			—			18			—
Series C Preferred Unitholders’ interest in net income	6			—			6			—
General Partner’s interest in net income	402			251			804			457
Class H Unitholder’s interest in net income	—			—			—			93
Common Unitholders’ interest in net income (loss)	—			(49		)	289			(17		)
Additional (earnings) distributions allocated to General Partner	(1		)	15			(3		)	12
Distributions on employee unit awards, net of allocation to General Partner	(7		)	(6		)	(15		)	(13		)
Net income (loss) available to Common Unitholders	$	(8	)	$	(40	)	$	271		$	(18	)
Weighted average Common Units – basic	1,165.4			1,021.7			1,164.6			922.5
Basic net income (loss) per Common Unit	$	(0.01	)	$	(0.04	)	$	0.23		$	(0.02	)

Weighted average Common Units – diluted	1,165.4			1,021.7			1,169.4			922.5
Diluted net income (loss) per Common Unit	$	(0.01	)	$	(0.04	)	$	0.23		$	(0.02	)

* As adjusted. See Note 1.

Equity (Tables)

6 Months Ended

Jun. 30, 2018

Change In Common Units

The changes in outstanding common units during the six months ended June 30, 2018 were as follows:



	Number of Units
Number of common units at December 31, 2017	1,164.1
Common units issued in connection with the distribution reinvestment plan	2.1
Common units issued in connection with certain transactions	1.3
Issuance of common units under equity incentive plans	0.1
Repurchases of common units in open-market transactions	(1.2	)
Number of common units at June 30, 2018	1,166.4

Distributions Made to Limited Partner, by Distribution [Table Text Block]

Distributions on common units declared and/or paid by the Partnership subsequent to December 31, 2017 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

Schedule of Future Relinquishments of Incentive Distribution Rights [Table Text Block]

ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods:



	Year Ending December 31,
2018 (remainder)	$	69
2019	128
Each year beyond 2019	33

Schedule of Preferred Units [Table Text Block]

Distributions on preferred units declared and/or paid by the Partnership subsequent to December 31, 2017 were as follows:



Period Ended	Record Date	Payment Date	Rate
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
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
Series C Preferred Units
June 30, 2018	August 1, 2018	August 15, 2018	$	0.56337

Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:



	June 30, 2018			December 31, 2017
Available-for-sale securities ⁽¹⁾	$	4		$	8
Foreign currency translation adjustment	(5		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(7		)	(5		)
Investments in unconsolidated affiliates, net	12			5
Total AOCI, net of tax	$	4		$	3


⁽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 accumulated other comprehensive income related to available-for-sale securities to common unitholders.

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)

6 Months Ended

Jun. 30, 2018

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]

Schedule of Rent Expense [Table Text Block]



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Rental expense	$	22	$	19	$	39	$	39

Environmental Exit Costs by Cost [Table Text Block]



	June 30, 2018		December 31, 2017
Current	$	42	$	36
Non-current	276		314
Total environmental liabilities	$	318	$	350

Revenue (Tables)

6 Months Ended

Jun. 30, 2018

Revenue [Abstract]

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]



	2018 (remainder)		2019		2020		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of June 30, 2018	$	2,598	$	5,048	$	4,604	$	28,071	$	40,321

Derivative Assets And Liabilities (Tables)

6 Months Ended

Jun. 30, 2018

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:



	June 30, 2018			December 31, 2017
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	465		2018	1,078		2018
Basis Swaps IFERC/NYMEX ⁽¹⁾	102,328		2018-2020	48,510		2018-2020
Options – Puts	(3,043	)	2018	13,000		2018
Power (Megawatt):
Forwards	3,196,100		2018-2019	435,960		2018-2019
Futures	(42,768	)	2018	(25,760	)	2018
Options – Puts	(30,532	)	2018	(153,600	)	2018
Options – Calls	996,172		2018	137,600		2018
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	6,600		2018-2020	4,650		2018-2020
Swing Swaps IFERC	52,413		2018-2019	87,253		2018-2019
Fixed Swaps/Futures	5,360		2018-2019	(4,700	)	2018-2019
Forward Physical Contracts	(174,465	)	2018-2020	(145,105	)	2018-2020
NGL (MBbls) – Forwards/Swaps	(1,590	)	2018-2019	(2,493	)	2018-2019
Crude (MBbls) – Forwards/Swaps	44,190		2018-2019	9,172		2018-2019
Refined Products (MBbls) – Futures	(1,076	)	2018-2019	(3,783	)	2018-2019
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(21,475	)	2018	(39,770	)	2018
Fixed Swaps/Futures	(21,475	)	2018	(39,770	)	2018
Hedged Item – Inventory	21,475		2018	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:



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	June 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 terms 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
	June 30, 2018		December 31, 2017		June 30, 2018			December 31, 2017
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	14	$	(2	)	$	(2	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	307		262		(352		)	(281		)
Commodity derivatives	106		44		(422		)	(55		)
Interest rate derivatives	—		—		(147		)	(219		)
	413		306		(921		)	(555		)
Total derivatives	$	413	$	320	$	(923	)	$	(557	)

Derivatives, Offsetting Fair Value Amounts [Table Text Block]



		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(147	)	$	(219	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	106			44			(422		)	(55		)
Broker cleared derivative contracts	Other current assets (liabilities)	307			276			(354		)	(283		)
Total gross derivatives		413			320			(923		)	(557		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(49		)	(20		)	49			20
Counterparty netting	Other current assets (liabilities)	(306		)	(263		)	306			263
Total net derivatives		$	58		$	37		$	(568	)	$	(274	)

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The following tables summarize the amounts recognized in income with respect to our derivative financial instruments:



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,				Six Months Ended June 30,
		2018		2017		2018		2017
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	6	$	6	$	9	$	2



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2018			2017			2018			2017
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	16		$	15		$	33		$	26
Commodity derivatives – Non-trading	Cost of products sold	(300		)	7			(373		)	(3		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Embedded derivatives	Other, net	—			—			—			1
Total		$	(264	)	$	(3	)	$	(268	)	$	4

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41620-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2018

The following table summarizes the affiliate revenues on our consolidated statements of operations:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Affiliated revenues	$	222	$	133	$	508	$	251



	June 30, 2018		December 31, 2017
Accounts receivable from related companies:
Sunoco LP	$	184	$	219
FGT	18		11
Other	132		88
Total accounts receivable from related companies:	$	334	$	318

Accounts payable to related companies:
Sunoco LP	$	195	$	195
USAC	45		—
Other	89		14
Total accounts payable to related companies:	$	329	$	209



	June 30, 2018		December 31, 2017
Long-term notes receivable from related company:
Sunoco LP	$	85	$	85

Reportable Segments (Tables)

6 Months Ended

Jun. 30, 2018

Sales Revenue, Segment [Member]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The following tables present financial information by segment:



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	761		$	699		$	1,578		$	1,467
Intersegment revenues	52			54			110			102
	813			753			1,688			1,569
Interstate transportation and storage:
Revenues from external customers	323			201			636			432
Intersegment revenues	5			6			8			10
	328			207			644			442
Midstream:
Revenues from external customers	594			633			1,034			1,198
Intersegment revenues	1,280			982			2,454			2,054
	1,874			1,615			3,488			3,252
NGL and refined products transportation and services:
Revenues from external customers	2,472			1,767			4,930			3,885
Intersegment revenues	96			12			184			160
	2,568			1,779			5,114			4,045
Crude oil transportation and services:
Revenues from external customers	4,789			2,460			8,520			5,035
Intersegment revenues	14			5			28			5
	4,803			2,465			8,548			5,040
All other:
Revenues from external customers	471			816			992			1,454
Intersegment revenues	31			54			81			186
	502			870			1,073			1,640
Eliminations	(1,478		)	(1,113		)	(2,865		)	(2,517		)
Total revenues	$	9,410		$	6,576		$	17,690		$	13,471

Operating Segments [Member]

Schedule of Segment Reporting Information, by Segment [Table Text Block]



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017*			2018			2017*
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	208		$	148		$	400		$	317
Interstate transportation and storage	330			262			653			527
Midstream	414			412			791			732
NGL and refined products transportation and services	461			388			912			769
Crude oil transportation and services	548			228			1,012			415
All other	90			107			164			230
Total	2,051			1,545			3,932			2,990
Depreciation, depletion and amortization	(588		)	(557		)	(1,191		)	(1,117		)
Interest expense, net	(358		)	(336		)	(704		)	(668		)
Gain on Sunoco LP common unit repurchase	—			—			172			—
Loss on deconsolidation of CDM	(86		)	—			(86		)	—
Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Non-cash compensation expense	(21		)	(15		)	(41		)	(38		)
Unrealized gains (losses) on commodity risk management activities	(265		)	34			(352		)	98
Adjusted EBITDA related to unconsolidated affiliates	(228		)	(247		)	(413		)	(486		)
Equity in earnings (losses) of unconsolidated affiliates	106			(61		)	34			12
Other, net	40			37			87			52
Income before income tax expense	$	671		$	375		$	1,510		$	823

Assets Segments [Member]

Schedule of Segment Reporting Information, by Segment [Table Text Block]



	June 30, 2018		December 31, 2017
Assets:
Intrastate transportation and storage	$	5,604	$	5,020
Interstate transportation and storage	14,037		13,518
Midstream	19,949		20,004
NGL and refined products transportation and services	17,517		17,600
Crude oil transportation and services	18,168		17,736
All other	3,295		4,087
Total assets	$	78,570	$	77,965

Guarantor Financial Information (Tables)

6 Months Ended

Jun. 30, 2018

Guarantor Financial Information [Abstract]

Condensed Income Statement [Table Text Block]

The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows:



	June 30, 2018
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—	$	—		$	494	$	—		$	494
All other current assets	—		57			8,527		(2,531		)	6,053
Property, plant and equipment, net	—		—			59,776		—			59,776
Investments in unconsolidated affiliates	51,199		12,078			3,636		(63,277		)	3,636
All other assets	8		—			8,603		—			8,611
Total assets	$	51,207	$	12,135		$	81,036	$	(65,808	)	$	78,570

Current liabilities	$	390	$	(3,571	)	$	12,353	$	(2,531	)	$	6,641
Non-current liabilities	22,949		7,606			7,338		—			37,893
Noncontrolling interest	—		—			6,171		—			6,171
Total partners’ capital	27,868		8,100			55,174		(63,277		)	27,865
Total liabilities and equity	$	51,207	$	12,135		$	81,036	$	(65,808	)	$	78,570



	December 31, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	(3	)	$	309	$	—		$	306
All other current assets	—			159			6,063		—			6,222
Property, plant and equipment, net	—			—			58,437		—			58,437
Investments in unconsolidated affiliates	48,378			11,648			3,816		(60,026		)	3,816
All other assets	—			—			9,184		—			9,184
Total assets	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965

Current liabilities	$	(1,496	)	$	(3,660	)	$	12,150	$	—		$	6,994
Non-current liabilities	21,604			7,607			7,609		—			36,820
Noncontrolling interest	—			—			5,882		—			5,882
Total partners’ capital	28,270			7,857			52,168		(60,026		)	28,269
Total liabilities and equity	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965



	Three Months Ended June 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	9,410		$	—		$	9,410
Operating costs, expenses, and other	—			—			8,467			—			8,467
Operating income	—			—			943			—			943
Interest expense, net	(289		)	(41		)	(28		)	—			(358		)
Equity in earnings of unconsolidated affiliates	701			66			106			(767		)	106
Gains on interest rate derivatives	20			—			—			—			20
Loss on deconsolidation of CDM	—			—			(86		)	—			(86		)
Other, net	—			—			46			—			46
Income before income tax expense	432			25			981			(767		)	671
Income tax expense	—			—			69			—			69
Net income	432			25			912			(767		)	602
Less: Net income attributable to noncontrolling interest	—			—			170			—			170
Net income attributable to partners	$	432		$	25		$	742		$	(767	)	$	432

Other comprehensive income	$	—		$	—		$	2		$	—		$	2
Comprehensive income	432			25			914			(767		)	604
Comprehensive income attributable to noncontrolling interest	—			—			170			—			170
Comprehensive income attributable to partners	$	432		$	25		$	744		$	(767	)	$	434



	Three Months Ended June 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,576		$	—		$	6,576
Operating costs, expenses, and other	—		1			5,839			—			5,840
Operating income (loss)	—		(1		)	737			—			736
Interest expense, net	—		(39		)	(297		)	—			(336		)
Equity in earnings (losses) of unconsolidated affiliates	199		137			(61		)	(336		)	(61		)
Losses on interest rate derivatives	—		—			(25		)	—			(25		)
Other, net	—		3			59			(1		)	61
Income before income tax expense	199		100			413			(337		)	375
Income tax expense	—		—			79			—			79
Net income	199		100			334			(337		)	296
Less: Net income attributable to noncontrolling interest	—		—			94			—			94
Net income attributable to partners	$	199	$	100		$	240		$	(337	)	$	202

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	199		100			333			(337		)	295
Comprehensive income attributable to noncontrolling interest	—		—			94			—			94
Comprehensive income attributable to partners	$	199	$	100		$	239		$	(337	)	$	201

* As adjusted. See Note 1.



	Six Months Ended June 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	17,690		$	—		$	17,690
Operating costs, expenses, and other	—			—			15,774			—			15,774
Operating income	—			—			1,916			—			1,916
Interest expense, net	(567		)	(82		)	(55		)	—			(704		)
Equity in earnings of unconsolidated affiliates	1,642			326			34			(1,968		)	34
Gains on interest rate derivatives	72			—			—			—			72
Gain on Sunoco LP unit repurchase	—			—			172			—			172
Loss on deconsolidation of CDM	—			—			(86		)	—			(86		)
Other, net	—			—			106			—			106
Income before income tax expense	1,147			244			2,087			(1,968		)	1,510
Income tax expense	—			—			29			—			29
Net income	1,147			244			2,058			(1,968		)	1,481
Less: Net income attributable to noncontrolling interest	—			—			334			—			334
Net income attributable to partners	$	1,147		$	244		$	1,724		$	(1,968	)	$	1,147

Other comprehensive income	$	—		$	—		$	3		$	—		$	3
Comprehensive income	1,147			244			2,061			(1,968		)	1,484
Comprehensive income attributable to noncontrolling interest	—			—			334			—			334
Comprehensive income attributable to partners	$	1,147		$	244		$	1,727		$	(1,968	)	$	1,150



	Six Months Ended June 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	13,471		$	—		$	13,471
Operating costs, expenses, and other	—		1			12,051			—			12,052
Operating income (loss)	—		(1		)	1,420			—			1,419
Interest expense, net	—		(81		)	(587		)	—			(668		)
Equity in earnings of unconsolidated affiliates	1,010		765			12			(1,775		)	12
Losses on interest rate derivatives	—		—			(20		)	—			(20		)
Other, net	—		3			78			(1		)	80
Income before income tax expense	1,010		686			903			(1,776		)	823
Income tax expense	—		—			134			—			134
Net income	1,010		686			769			(1,776		)	689
Less: Net income attributable to noncontrolling interest	—		—			156			—			156
Net income attributable to partners	$	1,010	$	686		$	613		$	(1,776	)	$	533

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	1,010		686			768			(1,776		)	688
Comprehensive income attributable to noncontrolling interest	—		—			156			—			156
Comprehensive income attributable to partners	$	1,010	$	686		$	612		$	(1,776	)	$	532

* As adjusted. See Note 1.



	Six Months Ended June 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	3,252		$	102		$	585		$	(989	)	$	2,950
Cash flows used in investing activities	(2,925		)	(99		)	(903		)	2,336			(1,591		)
Cash flows provided by (used in) financing activities	(327		)	—			503			(1,347		)	(1,171		)
Change in cash	—			3			185			—			188
Cash at beginning of period	—			(3		)	309			—			306
Cash at end of period	$	—		$	—		$	494		$	—		$	494



	Six Months Ended June 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	1,010		$	652		$	1,764		$	(1,776	)	$	1,650
Cash flows used in investing activities	(716		)	(421		)	(2,125		)	1,776			(1,486		)
Cash flows provided by (used in) financing activities	(294		)	(249		)	291			—			(252		)
Change in cash	—			(18		)	(70		)	—			(88		)
Cash at beginning of period	—			41			319			—			360
Cash at end of period	$	—		$	23		$	249		$	—		$	272

Operations And Basis of Presentation Operations And Organization Narrative (Details)	1 Months Ended	3 Months Ended	6 Months Ended
	Apr. 30, 2017	Dec. 31, 2018	Jun. 30, 2018
SXL and ETP Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.5
FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
Citrus [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
MEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
ET Rover Pipeline, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.10%
Rover Pipeline LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			65.00%
Fayetteville Express Pipeline, LLC [Member] \| FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Citrus [Member] \| FGT
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Subsequent Event [Member] \| ETE Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio		1.28

Operations And Basis of Presentation Schedule of Change in Accounting Policy (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2018

Jun. 30, 2017

Jun. 30, 2018

Jun. 30, 2017

Error Corrections and Prior Period Adjustments Restatement [Line Items]

$ 7,140

$ 4,624

^[1]

$ 13,128

$ 9,674

^[1]

Income before income tax expense

943

736

^[1]

1,916

1,419

^[1]

671

375

^[1]

1,510

823

^[1]

602

296

^[1]

1,481

689

^[1]

$ 432

$ 202

^[1]

$ 1,147

$ 533

^[1]

$ (0.01)

$ (0.04)

^[1]

$ 0.23

$ (0.02)

^[1]

$ (0.01)

$ (0.04)

^[1]

$ 0.23

$ (0.02)

^[1]

$ 604

$ 295

^[1]

$ 1,484

$ 688

^[1]

Inventory, LIFO Reserve, Period Charge

434

201

^[1]

1,150

532

^[1]

^[1]

Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations

229

(387)

^[1]

Scenario, Previously Reported [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

^[2]

4,628

9,707

Income before income tax expense

732

1,386

371

790

292

656

$ 199

$ 523

$ (0.04)

$ (0.04)

$ 291

$ 655

Inventory, LIFO Reserve, Period Charge

198

522

Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations

410

Restatement Adjustment [Member]

Error Corrections and Prior Period Adjustments Restatement [Line Items]

$ (147)

(4)

$ (333)

(33)

Income before income tax expense

$ 3

$ 10

$ 0.00

$ 0.02

$ 0.00

$ 0.02

$ 4

$ 33

Inventory, LIFO Reserve, Period Charge

$ 3

(56)

Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations

$ (23)

[1]	* As adjusted. See Note 1.
[2]	As originally reported amounts reflect certain reclassifications made to conform to the current year presentation.

Operations And Basis of Presentation Schedule of Impact of Accounting Standard (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2018

Jun. 30, 2017

Jun. 30, 2018

Jun. 30, 2017

$ 1,024

$ 1,022

^[1]

$ 2,086

$ 2,034

^[1]

2,141

1,485

^[1]

4,171

3,032

^[1]

4,241

2,345

^[1]

7,495

4,887

^[1]

1,464

1,067

^[1]

2,861

2,091

^[1]

413

304

^[1]

852

775

^[1]

127

353

^[1]

225

652

^[1]

7,140

4,624

^[1]

13,128

9,674

^[1]

Accounting Standards Update 2014-09 [Member]

627

539

^[1]

1,231

1,031

^[1]

1,024

2,086

2,134

4,153

4,238

7,488

1,611

3,194

413

852

127

225

7,287

13,461

Restatement Adjustment [Member]

617

1,206

(147)

(333)

(147)

$ (4)

(333)

$ (33)

Advances to and investments in unconsolidated affiliates

$ 10

$ 25

[1]	* As adjusted. See Note 1.

Acquisitions and Other Transactions Narrative (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

Apr. 30, 2018

Feb. 28, 2018

Jun. 30, 2018

Jun. 30, 2017

Jun. 30, 2018

Jun. 30, 2017

^[1]

Dec. 31, 2017

$ 3,636

$ 3,816

(86)

$ 0

$ (86)

$ 0

Cash proceeds from Sunoco LP common unit repurchase

1,200,000

$ 540

$ 0

^[1]

172

$ 0

Sunoco LP

Cash proceeds from Sunoco LP common unit repurchase

17,286,859

$ 540

USAC Transaction [Member]

Business Combination, Consideration Transferred

$ 1,700

Payments to Acquire Businesses, Gross

$ 1,230

USAC Transaction [Member] | USA Compression Partners, LP [Member]

Sale of Stock, Number of Shares Issued in Transaction

19,191,351

Class B Units [Member] | USAC Transaction [Member] | USA Compression Partners, LP [Member]

Sale of Stock, Number of Shares Issued in Transaction

6,397,965

ETE | USAC Transaction [Member] | USA Compression Partners, LP [Member]

Sale of Stock, Number of Shares Issued in Transaction

12,466,912

Equity Issued in Business Combination, Fair Value Disclosure

$ 250

USA Compression Partners, LP [Member]

Advances to and investments in unconsolidated affiliates

399

Accrual for Taxes Other than Income Taxes, Current

$ 45

[1]	* As adjusted. See Note 1.

Advances to and Investments in Affiliates (Details) - USD ($)
$ in Millions

1 Months Ended

6 Months Ended

Feb. 28, 2018

Jun. 30, 2018

Jun. 30, 2017

^[1]

Apr. 30, 2018

Dec. 31, 2017

Schedule of Equity Method Investments [Line Items]

Advances to and investments in unconsolidated affiliates

$ 3,636

$ 3,816

Cash proceeds from Sunoco LP common unit repurchase

1,200,000

$ 540

$ 0

Repurchases of common units

$ 24

$ 0

RIGS Haynesville Partnership Co. [Member]

Schedule of Equity Method Investments [Line Items]

Equity Method Investment, Ownership Percentage

50.01%

49.99%

Sunoco LP

Schedule of Equity Method Investments [Line Items]

Equity Method Investment, Ownership Percentage

31.80%

Cash proceeds from Sunoco LP common unit repurchase

17,286,859

$ 540

Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.

26,200,000

USAC [Member]

Schedule of Equity Method Investments [Line Items]

Equity Method Investment, Ownership Percentage

26.60%

Advances to and investments in unconsolidated affiliates

$ 399

Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.

19,200,000

USAC [Member] | Class B Units [Member]

Schedule of Equity Method Investments [Line Items]

Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.

6,400,000

Sunoco LP

Schedule of Equity Method Investments [Line Items]

Advances to and investments in unconsolidated affiliates

$ 535

[1]	* As adjusted. See Note 1.

Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($)
$ in Millions

6 Months Ended

Jun. 30, 2018

Jun. 30, 2017

^[1]

Cash and Cash Equivalents [Abstract]

Accounts receivable

$ 236

$ 88

Accounts receivable from related companies

156

(115)

Inventories

299

160

Other current assets

(375)

Other non-current assets, net

(3)

(39)

Accounts payable

(465)

(286)

Accounts payable to related companies

(99)

131

Accrued and other current liabilities

249

(389)

Other non-current liabilities

(2)

Derivative assets and liabilities, net

233

(21)

Net change in operating assets and liabilities, net of effects of acquisitions

$ 229

$ (387)

[1]	* As adjusted. See Note 1.

Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 1,007	$ 1,363
USAC limited partner interests received in the CDM Contribution (see Note 2)	411	0
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$ 0	$ 988

Inventories (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Inventory, Gross [Abstract]
Natural gas, NGLs and refined products	$ 434	$ 733
Crude oil	571	551
Spare parts and other	251	305
Total inventories	$ 1,256	$ 1,589

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Fair Value Measurements [Abstract]
Transfers between levels in fair value hierarchy	$ 0
Aggregate fair value of long-term debt	33,640	$ 34,280
Long-term Debt	$ 33,900	$ 33,090

Fair Value Measurements Fair Value Heigharchy (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Derivative Liability, Fair Value, Gross Liability	$ (923)	$ (557)
Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	413	320
Other Assets, Fair Value Disclosure	21	21
Assets, Fair Value Disclosure, Recurring	434	341
Interest rate derivatives, Liabilities	(147)	(219)
Price Risk Derivative Liabilities, at Fair Value	(776)	(338)
Liabilities, Fair Value Disclosure, Recurring	(923)	(557)
Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	334	276
Other Assets, Fair Value Disclosure	14	14
Assets, Fair Value Disclosure, Recurring	348	290
Interest rate derivatives, Liabilities	0	0
Price Risk Derivative Liabilities, at Fair Value	(713)	(300)
Liabilities, Fair Value Disclosure, Recurring	(713)	(300)
Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	79	44
Other Assets, Fair Value Disclosure	7	7
Assets, Fair Value Disclosure, Recurring	86	51
Interest rate derivatives, Liabilities	(147)	(219)
Price Risk Derivative Liabilities, at Fair Value	(63)	(38)
Liabilities, Fair Value Disclosure, Recurring	(210)	(257)
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC/NYMEX [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	22	11
Price Risk Derivative Liabilities, at Fair Value	(70)	(24)
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC/NYMEX [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	22	11
Price Risk Derivative Liabilities, at Fair Value	(70)	(24)
Commodity Derivatives - Natural Gas [Member] \| Basis Swaps IFERC/NYMEX [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	13
Price Risk Derivative Liabilities, at Fair Value	(2)	(15)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	(1)	(1)
Commodity Derivatives - Natural Gas [Member] \| Swing Swaps IFERC [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	1	13
Price Risk Derivative Liabilities, at Fair Value	(1)	(14)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	11	70
Price Risk Derivative Liabilities, at Fair Value	(14)	(57)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	11	70
Price Risk Derivative Liabilities, at Fair Value	(14)	(57)
Commodity Derivatives - Natural Gas [Member] \| Fixed Swaps/Futures [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	9	8
Price Risk Derivative Liabilities, at Fair Value	(5)
Trading Liabilities, Fair Value Disclosure		2
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0
Trading Liabilities, Fair Value Disclosure		0
Commodity Derivatives - Natural Gas [Member] \| Forward Physical Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	9	8
Price Risk Derivative Liabilities, at Fair Value	(5)
Trading Liabilities, Fair Value Disclosure		2
Commodity Derivatives - Power [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	69	23
Price Risk Derivative Liabilities, at Fair Value	(57)	(22)
Commodity Derivatives - Power [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	69	23
Price Risk Derivative Liabilities, at Fair Value	(57)	(22)
Commodity Derivatives - Power [Member] \| Put Option [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1
Commodity Derivatives - Power [Member] \| Put Option [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	1
Commodity Derivatives - Power [Member] \| Put Option [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	0
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	300	191
Price Risk Derivative Liabilities, at Fair Value	(316)	(186)
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value	300	191
Price Risk Derivative Liabilities, at Fair Value	(316)	(186)
Commodity Derivatives - NGLs [Member] \| Forward Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Refined Products [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Liabilities, at Fair Value	(5)	(25)
Commodity Derivatives - Refined Products [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Liabilities, at Fair Value	(5)	(25)
Commodity Derivatives - Refined Products [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Crude [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value	(307)	(1)
Commodity Derivatives - Crude [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value	(307)	(1)
Commodity Derivatives - Crude [Member] \| Future [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value	$ 0	0
Commodity Derivatives - Crude [Member] \| Forwards Swaps [Member] \| Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value		(6)
Commodity Derivatives - Crude [Member] \| Forwards Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 1
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value		(6)
Commodity Derivatives - Crude [Member] \| Forwards Swaps [Member] \| Fair Value, Measurements, Recurring [Member] \| Level 2
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		$ 0

Net Income Per Limited Partner Unit Reconciliation of Basic and Diluted EPU (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2018

Jun. 30, 2017

^[1]

Jun. 30, 2018

Jun. 30, 2017

^[1]

Earnings Per Share [Abstract]

NET INCOME

$ 602

$ 296

$ 1,481

$ 689

Less: Net income attributable to noncontrolling interest

170

334

156

Series A Preferred Units Interest in Net Income

432

202

1,147

533

Series B Preferred Units Interest in Net Income

Series C Preferred Units Interest in Net Income

General Partner’s interest in net income

402

251

804

457

Class H Unitholder’s interest in net income

Common Unitholders’ interest in net income (loss)

(49)

289

(17)

Additional (earnings) distributions allocated to General Partner

(1)

(3)

Distributions on employee unit awards, net of allocation to General Partner

(7)

(6)

(15)

(13)

Net Income (Loss) from Continuing Operations Available to Common Shareholders, Basic

$ (8)

$ (40)

$ 271

$ (18)

Weighted average Common Units – basic

1,165.4

1,021.7

1,164.6

922.5

Weighted average Common Units – diluted

1,165.4

1,021.7

1,169.4

922.5

$ (0.01)

$ (0.04)

$ 0.23

$ (0.02)

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI for Sale of Securities, before Tax

$ (0.01)

$ (0.04)

$ 0.23

$ (0.02)

[1]	* As adjusted. See Note 1.

Net Income Per Limited Partner Unit Narrative (Details)	1 Months Ended
Net Income Per Limited Partner Unit Narrative (Details)	Apr. 30, 2017
SXL and ETP Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.5

Debt Obligations Narrative (Details) $ in Millions	6 Months Ended
Debt Obligations Narrative (Details) $ in Millions	Jun. 30, 2018 USD ($)
Early Repayment of Senior Debt	$ 1,650
Proceeds from Issuance of Senior Long-term Debt	2,960
Bakken Pipeline [Member] \| Bakken Term Note [Member]
Line of Credit Facility, Maximum Borrowing Capacity	2,500
4.20% Senior Notes due 2023 [Member] \| ETP [Member]
Senior Notes	$ 500
Debt Instrument, Interest Rate, Stated Percentage	4.20%
4.95% Senior Notes due 2028 [Member] \| ETP [Member]
Senior Notes	$ 1,000
Debt Instrument, Interest Rate, Stated Percentage	4.95%
5.80% Senior Notes due 2038 [Member] \| ETP [Member]
Senior Notes	$ 500
Debt Instrument, Interest Rate, Stated Percentage	5.80%
6.0% Senior Notes due 2048 [Member] \| ETP [Member]
Senior Notes	$ 1,000
Debt Instrument, Interest Rate, Stated Percentage	6.00%
2.50% Senior Notes due June 2018 [Member] \| ETP [Member]
Senior Notes	$ 650
Debt Instrument, Interest Rate, Stated Percentage	2.50%
7.00% Senior Notes, due June 15, 2018 [Member] \| Panhandle [Member]
Senior Notes	$ 400
Debt Instrument, Interest Rate, Stated Percentage	7.00%
6.7% Senior Notes, due July 1, 2018 [Member] \| ETP [Member]
Senior Notes	$ 600
Debt Instrument, Interest Rate, Stated Percentage	6.70%
ETP Credit Facility due December 2022 [Member] \| ETP [Member]
Line of Credit Facility, Current Borrowing Capacity	$ 2,610
Long-term Line of Credit	1,230
Long-term Commercial Paper, Noncurrent	1,230
Line of Credit Facility, Maximum Borrowing Capacity	4,000
Letters of Credit Outstanding, Amount	$ 167
Line of Credit Facility, Interest Rate at Period End	2.87%
ETP Credit Facility due December 2022 [Member] \| ETP [Member] \| Accordion feature [Member]
Long-term Line of Credit	$ 6,000
ETP $1.0 billion 364-day Credit Facility due December 2018 [Member] \| ETP [Member]
Long-term Line of Credit	0
Line of Credit Facility, Maximum Borrowing Capacity	1,000
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] \| Bakken Project [Member]
Long-term Line of Credit	$ 2,500
Line of Credit Facility, Interest Rate at Period End	3.72%

Equity Narrative (Details) - USD ($)
$ / shares in Units, $ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

Jul. 31, 2018

Apr. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Jun. 30, 2018

Jun. 30, 2017

^[1]

$ 2

Proceeds from Issuance of Preferred Limited Partners Units

436

$ 0

Proceeds from Issuance of Common Limited Partners Units

$ 990

ETP [Member]

Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement

Equity Distribution Agreements, Value of Units Available to be Issued

$ 752

752

Equity Distribution Agreement, Maximum Aggregate Value Of Common Units

1,000

Stock Issued During Period, Value, Dividend Reinvestment Plan

$ 0.5650

$ 39

Series A Preferred Units [Member]

Preferred Stock, Shares Issued

$ 31.250

15.451

950,000

Series B Preferred Units [Member]

Preferred Stock, Shares Issued

$ 33.125

$ 16.378

550,000

Series C Preferred Units [Member]

Preferred Stock, Dividend Rate, Percentage

$ 0.56337

Preferred Units, Issued

18,000,000

7.375%

Shares Issued, Price Per Share

$ 25

Preferred Units, Liquidation Spread, Percent

4.53%

Proceeds from Issuance of Preferred Limited Partners Units

$ 450

Series D Preferred Units [Member] | Subsequent Event [Member]

Preferred Units, Issued

17,800,000

Preferred Stock, Dividend Rate, Percentage

7.625%

Shares Issued, Price Per Share

$ 25

Preferred Units, Liquidation Spread, Percent

4.378%

Proceeds from Issuance of Preferred Limited Partners Units

$ 445

[1]	* As adjusted. See Note 1.

Equity Common Unit Activity (Details) shares in Millions	6 Months Ended
Equity Common Unit Activity (Details) shares in Millions	Jun. 30, 2018 shares
Partners' Capital Notes [Abstract]
Number of common units at December 31, 2017	1,164.1
Common units issued in connection with the distribution reinvestment plan	2.1
Common units issued in connection with certain transactions	1.3
Issuance of common units under equity incentive plans	0.1
Repurchases of common units in open-market transactions	(1.2)
Number of common units at June 30, 2018	1,166.4

Equity Quarterly Distributions Of Available Cash (Details) - $ / shares	3 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017
ETP [Member]
Distribution Made to Member or Limited Partner [Line Items]
Record Date	Aug. 06, 2018	May 07, 2018	Feb. 08, 2018
Payment Date	Aug. 14, 2018	May 15, 2018	Feb. 14, 2018
Rate	$ 0.5650	$ 0.5650	$ 0.5650
Preferred Units [Member]
Distribution Made to Member or Limited Partner [Line Items]
Record Date	Aug. 01, 2018		Feb. 01, 2018
Payment Date	Aug. 15, 2018		Feb. 15, 2018
Series A Preferred Units [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate	$ 31.250		$ 15.451
Series B Preferred Units [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate	33.125		$ 16.378
Series C Preferred Units [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate	$ 0.56337

Equity Net IDR Schedule (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
Equity Net IDR Schedule (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019
ETE \| Subsequent Event [Member]
Relinquishment of Incentive Distributions	$ 69	$ 33	$ 128

Equity AOCI (Details) - USD ($)
$ in Millions

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Partners' Capital Notes [Abstract]

Available-for-sale securities (1)

^[1]

$ 4

$ 8

Foreign currency translation adjustment

(5)

Actuarial loss related to pensions and other postretirement benefits

(7)

(5)

Investments in unconsolidated affiliates, net

Total AOCI, net of tax

$ 4

$ 3

[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 accumulated other comprehensive income related to available-for-sale securities to common unitholders.

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Jun. 30, 2018	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	$ 3	$ 70

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended	3 Months Ended		6 Months Ended
	Feb. 28, 2018 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jan. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Maximum lease expiration year				Dec. 31, 2034
Loss contingency accrual, at carrying value		$ 52,000,000		$ 52,000,000			$ 53,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed		0		0
Accrual for Environmental Loss Contingencies		318,000,000		318,000,000			$ 350,000,000
Civil penalties	$ 12,600,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount		319,000,000		319,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount		595,000,000		595,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount		1,000,000		1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount		536,000,000		536,000,000
Sunoco LP \| Term loan due 2019 [Member]
Senior Notes		$ 2,035,000,000		$ 2,035,000,000
Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number		6		6
Payments for Environmental Liabilities		$ 6,000,000	$ 7,000,000	$ 11,000,000	$ 13,000,000
Proposed Environmental Penalty		$ 200,000		$ 200,000
Sunoco [Member]
Sites where remediation operations are responsibility of third parties		41		41
Rover Pipeline LLC [Member]
Proposed Environmental Penalty		$ 2,600,000		$ 2,600,000
4.875% senior notes due 2023 [Member] \| Sunoco LP
Senior Notes						$ 1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage						4.875%
5.500% senior notes due 2026 [Member] \| Sunoco LP
Senior Notes						$ 800,000,000
Debt Instrument, Interest Rate, Stated Percentage						5.50%
5.875% senior notes due 2028 [Member] \| Sunoco LP
Senior Notes						$ 400,000,000
Debt Instrument, Interest Rate, Stated Percentage						5.875%

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Operating Leases, Rental Expense (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Rental expense	$ 22	$ 19	$ 39	$ 39

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Environmental Exit Cost [Line Items]
Current	$ 42	$ 36
Non-current	276	314
Total environmental liabilities	$ 318	$ 350

Revenue (Details) $ in Millions	3 Months Ended	6 Months Ended
Revenue (Details) $ in Millions	Jun. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)
Contract with Customer, Asset, Gross	$ 0	$ 0
Deferred Revenue	235	235
Contract with Customer, Liability, Revenue Recognized	28	63
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-12-31
Revenue, Remaining Performance Obligation	2,598	2,598
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-12-31
Revenue, Remaining Performance Obligation	5,048	5,048
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-12-31
Revenue, Remaining Performance Obligation	4,604	4,604
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-12-31
Revenue, Remaining Performance Obligation	28,071	28,071
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation	$ 40,321	$ 40,321

Derivative Assets And Liabilities Outstanding Interest Rate Derivatives (Details) - USD ($)
$ in Millions

6 Months Ended

Jun. 30, 2018

Dec. 31, 2017

July 2018 [Member]

^[1]

$ 0

$ 300

^[1],[2]

Forward-starting to pay a fixed rate of 3.76% and receive a floating rate

December 2018 [Member]

$ 1,200

1,200

^[2]

Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%

July 2019 [Member]

^[1]

$ 400

300

^[1],[2]

Forward-starting to pay a fixed rate of 3.56% and receive a floating rate

July 2020 [Member]

^[1]

$ 400

400

^[1],[2]

Forward-starting to pay a fixed rate of 3.52% and receive a floating rate

July 2021 [Member]

^[1]

$ 400

^[1],[2]

Forward-starting to pay a fixed rate of 3.55% and receive a floating rate

March 2019 [Member]

$ 300

Amount of Gain/(Loss) Recognized in Income on Derivatives

^[2]

Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%

[1]	Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
[2]	Floating rates are based on 3-month LIBOR.

Derivative Assets And Liabilities Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Total derivatives assets	$ 413	$ 320
Total derivatives liabilities	(923)	(557)
Designated as Hedging Instrument [Member] \| Commodity derivatives (margin deposits)
Total derivatives assets	0	14
Total derivatives liabilities	(2)	(2)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	413	306
Total derivatives liabilities	(921)	(555)
Not Designated as Hedging Instrument [Member] \| Commodity derivatives (margin deposits)
Total derivatives assets	307	262
Total derivatives liabilities	(352)	(281)
Not Designated as Hedging Instrument [Member] \| Commodity derivatives
Total derivatives assets	106	44
Total derivatives liabilities	(422)	(55)
Not Designated as Hedging Instrument [Member] \| Interest rate derivatives
Total derivatives assets	0	0
Total derivatives liabilities	$ (147)	$ (219)

Derivative Assets And Liabilities Fair Value of Derivatives, Netting Basis (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 413	$ 320
Derivative Liability, Fair Value, Gross Liability	(923)	(557)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(49)	(20)
Derivative Liability, Fair Value, Amount Offset Against Collateral	49	20
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(306)	(263)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	306	263
Derivative Asset, Fair Value, Net	58	37
Derivative Liability, Fair Value, Net	(568)	(274)
Without offsetting agreements [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(147)	(219)
OTC Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	106	44
Derivative Liability, Fair Value, Gross Liability	(422)	(55)
Broker cleared derivative contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	307	276
Derivative Liability, Fair Value, Gross Liability	$ (354)	$ (283)

Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Recognized OCI On Derivatives (Effective Portion) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Commodity Derivatives [Member]
Commodity derivatives	$ 6	$ 6	$ 9	$ 2

Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Amount Of Gain/(Loss) Reclassified From AOCI Into Income (Effective Portion) (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2018

Jun. 30, 2017

Jun. 30, 2018

Jun. 30, 2017

$ (264)

$ (3)

$ (268)

$ 4

Gains (losses) on interest rate derivatives

(25)

^[1]

(20)

^[1]

Commodity Derivatives - Trading [Member]

Amount of Gain/(Loss) Recognized in Income on Derivatives

Commodity derivatives

Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness

Amount of Gain/(Loss) Recognized in Income on Derivatives

(300)

(373)

(3)

Other Income (Expenses) [Member] | Embedded Derivatives in Preferred Units [Member]

Amount of Gain/(Loss) Recognized in Income on Derivatives

$ 0

$ 1

[1]	* As adjusted. See Note 1.

Related Party Transactions Affiliated Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Related Party Transactions [Abstract]
Affiliated revenues	$ 222	$ 133	$ 508	$ 251

Related Party Transactions Related Party A/R and A/P (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Total accounts receivable from related companies:	$ 334	$ 318
Total accounts payable to related companies:	329	209
USAC [Member]
Total accounts payable to related companies:	45	0
Sunoco LP
Notes Receivable, Related Parties, Noncurrent	85	85
Total accounts receivable from related companies:	184	219
Total accounts payable to related companies:	195	195
FGT
Total accounts receivable from related companies:	18	11
Other
Total accounts receivable from related companies:	132	88
Total accounts payable to related companies:	$ 89	$ 14

Reportable Segments Segment Revenues (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2018

Jun. 30, 2017

Jun. 30, 2018

Jun. 30, 2017

Intrastate transportation and storage

$ 9,410

$ 6,576

^[1]

$ 17,690

$ 13,471

^[1]

Intrastate transportation and storage | Revenues from external customers

813

753

1,688

1,569

Intrastate transportation and storage | Intersegment revenues

761

699

1,578

1,467

Interstate transportation and storage

110

102

Interstate transportation and storage | Revenues from external customers

328

207

644

442

Interstate transportation and storage | Intersegment revenues

323

201

636

432

Midstream

Midstream | Revenues from external customers

1,874

1,615

3,488

3,252

Midstream | Intersegment revenues

594

633

1,034

1,198

NGL and refined products transportation and services

1,280

982

2,454

2,054

NGL and refined products transportation and services | Revenues from external customers

2,568

1,779

5,114

4,045

NGL and refined products transportation and services | Intersegment revenues

2,472

1,767

4,930

3,885

Crude oil transportation and services

184

160

Crude oil transportation and services | Revenues from external customers

4,803

2,465

8,548

5,040

Crude oil transportation and services | Intersegment revenues

4,789

2,460

8,520

5,035

All other

All other | Revenues from external customers

502

870

1,073

1,640

All other | Intersegment revenues

471

816

992

1,454

186

Eliminations

$ (1,478)

$ (1,113)

$ (2,865)

$ (2,517)

[1]	* As adjusted. See Note 1.

Reportable Segments Segment Adjusted EBITDA (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2018

Jun. 30, 2017

Jun. 30, 2018

Jun. 30, 2017

^[1]

Depreciation, depletion and amortization

$ 2,051

$ 1,545

$ 3,932

$ 2,990

(588)

(557)

(1,191)

(1,117)

Interest expense, net

(358)

(336)

^[1]

(704)

(668)

^[1]

172

Gains (losses) on interest rate derivatives

(86)

(25)

^[1]

(20)

Non-cash compensation expense

(21)

(15)

(41)

(38)

Unrealized gains (losses) on commodity risk management activities

(265)

(352)

Adjusted EBITDA related to unconsolidated affiliates

(228)

(247)

413

486

Equity in earnings (losses) of unconsolidated affiliates

106

(61)

^[1]

Other, net

INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)

671

375

^[1]

1,510

823

Intrastate transportation and storage

Interstate transportation and storage

208

148

400

317

330

262

653

527

Midstream

NGL and refined products transportation and services

414

412

791

732

Crude oil transportation and services

461

388

912

769

548

228

1,012

415

All other