Edgar Filing: Energy Transfer Partners, L.P.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Emerging growth company

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-31219

ENERGY TRANSFER PARTNERS, L.P.

(Exact name of registrant as specified in its charter)



Delaware		73-1493906
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

At May 4, 2018, the registrant had 1,165,133,105 Common Units outstanding.

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FORM 10-Q

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS



PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets	1

Consolidated Statements of Operations	3

Consolidated Statements of Comprehensive Income	4

Consolidated Statement of Equity	5

Consolidated Statements of Cash Flows	6

Notes to Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	40

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	56

ITEM 4. CONTROLS AND PROCEDURES	57

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	58

ITEM 1A. RISK FACTORS	58

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	61

ITEM 5. OTHER INFORMATION	61

ITEM 6. EXHIBITS	63

SIGNATURE	64

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Partners, L.P. (the “Partnership” or “ETP”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected or expected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I – Item 1A. Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 filed with the Securities and Exchange Commission on February 23, 2018.

Definitions

The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:



	/d		per day

	AOCI		accumulated other comprehensive income (loss)

	Btu		British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used

	BBtu		billion British thermal units

	Capacity		capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels

	CDM		CDM Resource Management LLC

	CDM E&T		CDM Environmental & Technical Services LLC

	Citrus		Citrus, LLC

	CrossCountry		CrossCountry Energy, LLC

	DOJ		United States Department of Justice

	EPA		United States Environmental Protection Agency

	ETC OLP		La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company

	ETE		Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC for the periods presented herein

	ETP GP		Energy Transfer Partners GP, L.P., the general partner of ETP

	ETP Holdco		ETP Holdco Corporation

	ETP LLC		Energy Transfer Partners, L.L.C., the general partner of ETP GP

	Exchange Act		Securities Exchange Act of 1934

	FEP		Fayetteville Express Pipeline LLC

	FERC		Federal Energy Regulatory Commission

	FGT		Florida Gas Transmission Company, LLC

	GAAP		accounting principles generally accepted in the United States of America

	HPC		RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP

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	IDRs		incentive distribution rights

	Legacy ETP Preferred Units		legacy ETP Series A cumulative convertible preferred units

	LIBOR		London Interbank Offered Rate

	MBbls		thousand barrels

	MEP		Midcontinent Express Pipeline LLC

	MTBE		methyl tertiary butyl ether

	NGL		natural gas liquid, such as propane, butane and natural gasoline

	NYMEX		New York Mercantile Exchange

	OSHA		federal Occupational Safety and Health Act

	OTC		over-the-counter

	Panhandle		Panhandle Eastern Pipe Line Company, LP and its subsidiaries

	PCBs		polychlorinated biphenyls

	PennTex		PennTex Midstream Partners, LP

	PES		Philadelphia Energy Solutions

	Regency		Regency Energy Partners LP

	Retail Holdings		ETP Retail Holdings, LLC, a wholly-owned subsidiary of Sunoco, Inc.

	Rover		Rover Pipeline LLC, a subsidiary of ETP

	SEC		Securities and Exchange Commission

	Series A Preferred Units		6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

	Series B Preferred Units		6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

	Series C Preferred Units		7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

	Sunoco Logistics		Sunoco Logistics Partners L.P.

	Transwestern		Transwestern Pipeline Company, LLC

	Trunkline		Trunkline Gas Company, LLC, a subsidiary of Panhandle

	USAC		USA Compression Partners, LP

Adjusted EBITDA is a term used throughout this document, which we define 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. Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.

iii

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	March 31, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	446		$	306
Accounts receivable, net	3,123			3,946
Accounts receivable from related companies	340			318
Inventories	1,421			1,589
Income taxes receivable	166			135
Derivative assets	23			24
Other current assets	229			210
Total current assets	5,748			6,528

Property, plant and equipment	69,164			67,699
Accumulated depreciation and depletion	(9,791		)	(9,262		)
	59,373			58,437

Advances to and investments in unconsolidated affiliates	3,258			3,816
Other non-current assets, net	758			758
Intangible assets, net	5,243			5,311
Goodwill	3,115			3,115
Total assets	$	77,495		$	77,965

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	March 31, 2018		December 31, 2017
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,288	$	4,126
Accounts payable to related companies	244		209
Derivative liabilities	147		109
Accrued and other current liabilities	2,140		2,143
Current maturities of long-term debt	404		407
Total current liabilities	6,223		6,994

Long-term debt, less current maturities	33,109		32,687
Non-current derivative liabilities	97		145
Deferred income taxes	2,860		2,883
Other non-current liabilities	1,100		1,084

Commitments and contingencies
Redeemable noncontrolling interests	21		21

Equity:
Series A Preferred Unitholders	943		944
Series B Preferred Unitholders	546		547
Common Unitholders	26,143		26,531
General Partner	365		244
Accumulated other comprehensive income	2		3
Total partners’ capital	27,999		28,269
Noncontrolling interest	6,086		5,882
Total equity	34,085		34,151
Total liabilities and equity	$	77,495	$	77,965

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

(unaudited)



	Three Months Ended March 31,
	2018			2017*
REVENUES:
Natural gas sales	$	1,062		$	1,012
NGL sales	2,030			1,547
Crude sales	3,254			2,542
Gathering, transportation and other fees	1,397			1,024
Refined product sales	439			471
Other	98			299
Total revenues	8,280			6,895
COSTS AND EXPENSES:
Cost of products sold	5,988			5,050
Operating expenses	604			492
Depreciation, depletion and amortization	603			560
Selling, general and administrative	112			110
Total costs and expenses	7,307			6,212
OPERATING INCOME	973			683
OTHER INCOME (EXPENSE):
Interest expense, net	(346		)	(332		)
Equity in earnings (losses) of unconsolidated affiliates	(72		)	73
Gain on Sunoco LP common unit repurchase	172			—
Gains on interest rate derivatives	52			5
Other, net	60			19
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	839			448
Income tax expense (benefit)	(40		)	55
NET INCOME	879			393
Less: Net income attributable to noncontrolling interest	164			62
NET INCOME ATTRIBUTABLE TO PARTNERS	715			331
General Partner’s interest in net income	402			206
Series A Preferred Unitholders’ interest in net income	15			—
Series B Preferred Unitholders’ interest in net income	9			—
Class H Unitholder’s interest in net income	—			93
Common Unitholders’ interest in net income	$	289		$	32
NET INCOME PER COMMON UNIT:
Basic	$	0.24		$	0.03
Diluted	$	0.24		$	0.03

* As adjusted. See Note 1.

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)



	Three Months Ended March 31,
	2018			2017*
Net income	$	879		$	393
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	(2		)	2
Actuarial loss relating to pension and other postretirement benefit plans	(2		)	(2		)
Change in other comprehensive income from unconsolidated affiliates	5			—
	1			—
Comprehensive income	880			393
Less: Comprehensive income attributable to noncontrolling interest	164			62
Comprehensive income attributable to partners	$	716		$	331

* As adjusted. See Note 1.

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2018

(Dollars in millions)

(unaudited)



	Series A Preferred Units			Series B Preferred Units			Common Units			General Partner			Accumulated Other Comprehensive Income			Noncontrolling Interest			Total
Balance, December 31, 2017	$	944		$	547		$	26,531		$	244		$	3		$	5,882		$	34,151
Distributions to partners	(15		)	(9		)	(657		)	(264		)	—			—			(945		)
Distributions to noncontrolling interest	—			—			—			—			—			(183		)	(183		)
Units issued for cash	—			—			20			—			—			—			20
Capital contributions from noncontrolling interest	—			—			—			—			—			229			229
Repurchases of common units	—			—			(24		)	—			—			—			(24		)
Other comprehensive income, net of tax	—			—			—			—			1			—			1
Other, net	(1		)	(1		)	(16		)	(17		)	(2		)	(6		)	(43		)
Net income	15			9			289			402			—			164			879
Balance, March 31, 2018	$	943		$	546		$	26,143		$	365		$	2		$	6,086		$	34,085

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)



	Three Months Ended March 31,
	2018			2017*
OPERATING ACTIVITIES
Net income	$	879		$	393
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	603			560
Deferred income taxes	(40		)	54
Non-cash compensation expense	20			23
Gain on Sunoco LP common unit repurchase	(172		)	—
Distributions on unvested awards	(8		)	(8		)
Equity in (earnings) losses of unconsolidated affiliates	72			(73		)
Distributions from unconsolidated affiliates	106			82
Other non-cash	(78		)	(53		)
Net change in operating assets and liabilities, net of effects of acquisitions	392			(46		)
Net cash provided by operating activities	1,774			932
INVESTING ACTIVITIES
Cash proceeds from Bakken Pipeline Transaction	—			2,000
Cash proceeds from Sunoco LP common unit repurchase	540			—
Cash paid for acquisition of PennTex noncontrolling interest	—			(280		)
Cash paid for all other acquisitions	(4		)	(38		)
Capital expenditures, excluding allowance for equity funds used during construction	(1,718		)	(1,384		)
Contributions in aid of construction costs	20			6
Contributions to unconsolidated affiliates	(8		)	(111		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	27			90
Other	—			(3		)
Net cash (used in) provided by investing activities	(1,143		)	280
FINANCING ACTIVITIES
Proceeds from borrowings	3,959			6,366
Repayments of long-term debt	(3,545		)	(7,216		)
Cash received from (paid to) affiliate notes	2			(250		)
Units issued for cash	20			826
Capital contributions from noncontrolling interest	229			106
Distributions to partners	(945		)	(896		)
Distributions to noncontrolling interest	(183		)	(148		)
Repurchases of common units	(24		)	—
Redemption of Legacy ETP Preferred Units	—			(53		)
Debt issuance costs	—			(19		)
Other	(4		)	3
Net cash used in financing activities	(491		)	(1,281		)
Increase (decrease) in cash and cash equivalents	140			(69		)
Cash and cash equivalents, beginning of period	306			360
Cash and cash equivalents, end of period	$	446		$	291

* As adjusted. See Note 1.

The accompanying notes are an integral part of these consolidated financial statements.

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar and unit amounts, except per unit data, are in millions)

(unaudited)


1.	ORGANIZATION AND BASIS OF PRESENTATION

Organization

Energy Transfer Partners, L.P. (“ETP”) is a consolidated subsidiary of ETE.

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, 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.

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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.

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As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows:



	Three Months Ended March 31, 2017
	As Originally Reported*			Effect of Change			As Adjusted
Consolidated Statement of Operations and Comprehensive Income:
Cost of products sold	$	5,079		$	(29	)	$	5,050
Operating income	654			29			683
Income before income tax expense	419			29			448
Net income	364			29			393
Net income attributable to partners	324			7			331
Net income per common unit – basic	0.02			0.01			0.03
Net income per common unit – diluted	0.02			0.01			0.03
Comprehensive income	364			29			393
Comprehensive income attributable to partners	324			7			331

Consolidated Statements of Cash Flows:
Net income	364			29			393
Inventory valuation adjustments	(2		)	2			—
Net change in operating assets and liabilities (change in inventories)	(15		)	(31		)	(46		)

* Amounts reflect certain reclassifications made to conform to the current year presentation.

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 increases in revenue (with offsetting increases 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.

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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 March 31, 2018
	As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)
Revenues:
Natural gas sales	$	1,062	$	1,062	$	—
NGL sales	2,030		2,019		11
Crude sales	3,254		3,254		—
Gathering, transportation and other fees	1,397		1,584		(187		)
Refined product sales	439		439		—
Other	98		98		—

Costs and expenses:
Cost of products sold	5,988		6,175		(187		)
Operating expenses	604		593		11

Additional disclosures related to revenue are included in Note 11.

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 retained earnings at 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.

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2.	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 and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The 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 Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each 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.

Beginning April 2018, ETP’s consolidated financial statements will reflect an equity method investment in USAC. CDM and CDM E&T’s assets and liabilities have not been reflected as held for sale, nor have CDM and CDM E&T’s results been reflected as discontinued operations in these financial statements.

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.

Sunoco LP Common Unit Repurchase

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. In connection with this transaction, the Partnership recognized a gain of $172 million.


3.	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) included in cash flows from operating activities is comprised as follows:



	Three Months Ended March 31,
	2018			2017*
Accounts receivable	$	817		$	(23	)
Accounts receivable from related companies	122			(44		)
Inventories	169			137
Other current assets	(48		)	43
Other non-current assets, net	(3		)	(18		)
Accounts payable	(667		)	(88		)
Accounts payable to related companies	(111		)	120
Accrued and other current liabilities	106			(139		)
Other non-current liabilities	16			(2		)
Derivative assets and liabilities, net	(9		)	(32		)
Net change in operating assets and liabilities, net of effects of acquisitions	$	392		$	(46	)

* As adjusted. See Note 1.

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Non-cash investing and financing activities are as follows:



	Three Months Ended March 31,
	2018		2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,010	$	832
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	—	$	988


4.	INVENTORIES

Inventories consisted of the following:



	March 31, 2018		December 31, 2017
Natural gas, NGLs, and refined products	$	419	$	733
Crude oil	701		551
Spare parts and other	301		305
Total inventories	$	1,421	$	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.


5.	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 March 31, 2018 was $33.78 billion and $33.51 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 three months ended March 31, 2018, no transfers were made between any levels within the fair value hierarchy.

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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 March 31, 2018 and December 31, 2017 based on inputs used to derive their fair values:



				Fair Value Measurements at March 31, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	35		$	35		$	—
Swing Swaps IFERC	1			—			1
Fixed Swaps/Futures	14			14			—
Forward Physical Contracts	7			—			7
Power:
Forwards	78			—			78
Options – Puts	1			1			—
Options – Calls	1			1			—
Natural Gas Liquids – Forwards/Swaps	115			115			—
Total commodity derivatives	252			166			86
Other non-current assets	21			14			7
Total assets	$	273		$	180		$	93
Liabilities:
Interest rate derivatives	$	(167	)	$	—		$	(167	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(81		)	(81		)	—
Swing Swaps IFERC	(1		)	—			(1		)
Fixed Swaps/Futures	(13		)	(13		)	—
Options – Calls	(1		)	(1		)	—
Forward Physical Contracts	(6		)	—			(6		)
Power – Forwards	(72		)	—			(72		)
Natural Gas Liquids – Forwards/Swaps	(169		)	(169		)	—
Refined Products – Futures	(3		)	(3		)	—
Total commodity derivatives	(346		)	(267		)	(79		)
Total liabilities	$	(513	)	$	(267	)	$	(246	)

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				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
Natural Gas Liquids – Forwards/Swaps	193			193			—
Crude – 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		)
Natural Gas Liquids – Forwards/Swaps	(192		)	(192		)	—
Refined Products – Futures	(25		)	(25		)	—
Crude – Futures	(1		)	(1		)	—
Total commodity derivatives	(338		)	(300		)	(38		)
Total liabilities	$	(557	)	$	(300	)	$	(257	)


6.	NET INCOME PER LIMITED PARTNER UNIT

Net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to the General Partner, the holder of the IDRs pursuant to the Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.

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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 March 31,
	2018			2017*
Net income	$	879		$	393
Less: Income attributable to noncontrolling interest	164			62
Net income, net of noncontrolling interest	715			331
General Partner’s interest in net income	402			206
Series A Preferred Unitholders’ interest in net income	15			—
Series B Preferred Unitholders’ interest in net income	9			—
Class H Unitholder’s interest in net income	—			93
Common Unitholders’ interest in net income	289			32
Additional earnings allocated to General Partner	(2		)	(3		)
Distributions on employee unit awards, net of allocation to General Partner	(8		)	(7		)
Net income available to Common Unitholders	$	279		$	22
Weighted average Common Units – basic	1,163.8			822.3
Basic net income per Common Unit	$	0.24		$	0.03

Dilutive effect of unvested employee unit awards	4.0			2.2
Weighted average Common Units – diluted	1,167.8			824.5
Diluted net income per Common Unit	$	0.24		$	0.03

* As adjusted. See Note 1.


7.	DEBT OBLIGATIONS

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 March 31, 2018, the ETP Five-Year Credit Facility had $2.76 billion outstanding, of which $1.93 billion was commercial paper. The amount available for future borrowings was $1.09 billion after taking into account letters of credit of $155 million. The weighted average interest rate on the total amount outstanding as of March 31, 2018 was 2.92%.

ETP 364-Day Facility

ETP’s 364-day term loan facility (the “ETP 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 30, 2018. As of March 31, 2018, the ETP 364-Day Facility had no outstanding borrowings.

Bakken Credit Facility

In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of March 31, 2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of March 31, 2018 was 3.31%.

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of March 31, 2018.

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8.	EQUITY

The changes in outstanding common units during the three months ended March 31, 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	1.1
Repurchases of common units in open-market transactions	(1.2	)
Number of common units at March 31, 2018	1,164.0

Equity Distribution Program

During the three months ended March 31, 2018, there were no units issued under the Partnership’s equity distribution agreements. As of March 31, 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 three months ended March 31, 2018, distributions of $20 million were reinvested under the distribution reinvestment plan.

Preferred Units

As of each of March 31, 2018 and December 31, 2017, the Partnership had 950,000 Series A Preferred Units and 550,000 Series B Preferred Units outstanding.

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 our 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.

Quarterly Distributions of Available Cash

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

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



	Total Year
2018 (remainder)	$	111
2019	128
Each year beyond 2019	33

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

Distribution per Preferred Unit

Quarter Ended

Record Date

Payment Date

Series A

Series B

December 31, 2017

February 1, 2018

February 15, 2018

15.451

16.378

Accumulated Other Comprehensive Income

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



	March 31, 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	10			5
Total AOCI, net of tax	$	2		$	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.


9.	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 months ended March 31, 2018 the Partnership’s income tax benefit also reflected a $67 million deferred benefit adjustment as the result of a state statutory rate reduction.


10.	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 (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $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 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.

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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 March 31,
	2018		2017
Rental expense	$	25	$	20

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.

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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. 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 block 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 April 18, 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

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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. On March 6, 2018, Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint.

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 Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. 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. ETP filed a petition for review with the Texas Supreme Court.

Bayou Bridge

On January 11, 2018, environmental groups and a trade association filed suit against the United States Army Corps of Engineers (the “Corps”) in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the Corps’ 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 Corps corrects alleged deficiencies in its decision-making process. ETP, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26. On March 27, 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 but subsequently granted the preliminary injunction on February 23. On February 26, Bayou Bridge filed a notice of appeal and a motion to stay the February 23 preliminary injunction order. On February 27, Judge Dick issued an opinion that clarified her February 23 preliminary injunction order and denied Bayou Bridge’s February

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26 motion to stay as moot. On March 1, Bayou Bridge filed a new notice of appeal and motion to stay the February 27 preliminary injunction order in the district court. On March 5, the district court denied the March 1 motion to stay the February 27 order.

On March 2, 2018, Bayou Bridge filed a motion to stay the preliminary injunction in the Fifth Circuit. On March 15, 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.

Rover

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover Pipeline, LLC (“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., and D&G Directional Drilling, Inc. d/b/a D&G Directional Drilling, LLC (collectively, with Rover and Pretec, “Defendants”) were added as defendants on April 17, 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 Rover caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Rover’s answer to Ohio EPA’s complaint is due on May 17, 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 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 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 March 31, 2018 and December 31, 2017, accruals of approximately $30 million and $33 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. (“Sunoco”) before the Pennsylvania Public Utilities 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 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) Sunoco failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increase 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 Sunoco fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in

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which they sit; (iv) requiring Sunoco 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. A hearing before Administrative Law Judge Elizabeth H. Barnes on the emergency relief is scheduled for May 7 and 10, 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.

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 is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.

No amounts have been recorded in our March 31, 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 Sunoco Pipeline L.P. (“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 of 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 of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of 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

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demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. 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 Sunoco Pipeline L.P. 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 of 2017, during the construction of the project. Sunoco Pipeline L.P. 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 Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, Sunoco Pipeline L.P. 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 Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. 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 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 March 31, 2018, Sunoco, Inc. had been named as a PRP at approximately 50 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.



	March 31, 2018		December 31, 2017
Current	$	43	$	36
Non-current	302		314
Total environmental liabilities	$	345	$	350

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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 March 31, 2018 and 2017, the Partnership recorded $5 million and $2 million, respectively, of expenditures related to environmental cleanup 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.


11.	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 months ended March 31, 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.

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Note 14 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:

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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.

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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 business which provides compression services to customers engaged in the transportation of natural gas. 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 March 31, 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 March 31, 2018, the Partnership had $317 million in deferred revenues representing the current value of our future performance obligations.

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The amount of revenue recognized in the current period that was included in the deferred revenue liability balance as of January 1, 2018 was $42 million.

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 March 31, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $35.66 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 March 31, 2018	$	3,430	$	4,596	$	4,116	$	23,520	$	35,662

Practical Expedients Utilized by the Partnership

For the period ended March 31, 2018, 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.


12.	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.

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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.

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The following table details our outstanding commodity-related derivatives:



	March 31, 2018			December 31, 2017
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	1,008		2018	1,078		2018
Basis Swaps IFERC/NYMEX ⁽¹⁾	82,493		2018-2020	48,510		2018-2020
Options – Puts	13,000		2018	13,000		2018
Options – Calls	460		2018	—		—
Power (Megawatt):
Forwards	236,680		2018-2019	435,960		2018-2019
Futures	126,200		2018	(25,760	)	2018
Options – Puts	238,400		2018	(153,600	)	2018
Options – Calls	349,600		2018	137,600		2018
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	9,750		2018-2020	4,650		2018-2020
Swing Swaps IFERC	(24,825	)	2018-2019	87,253		2018-2019
Fixed Swaps/Futures	(4,620	)	2018-2019	(4,700	)	2018-2019
Forward Physical Contracts	(224,178	)	2018-2020	(145,105	)	2018-2020
Natural Gas Liquid/Crude (MBbls) – Forwards/Swaps	38,875		2018-2019	6,679		2018-2019
Refined Products (MBbls) – Futures	(1,219	)	2018-2019	(3,783	)	2018-2019
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(18,685	)	2018	(39,770	)	2018
Fixed Swaps/Futures	(18,685	)	2018	(39,770	)	2018
Hedged Item – Inventory	18,685		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.

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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⁾	March 31, 2018		December 31, 2017
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	$	300	$	300
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		300
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		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.

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Derivative Summary

The following table provides a summary of our derivative assets and liabilities:



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	March 31, 2018		December 31, 2017		March 31, 2018			December 31, 2017
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	14	$	—		$	(2	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	166		262		(206		)	(281		)
Commodity derivatives	86		44		(140		)	(55		)
Interest rate derivatives	—		—		(167		)	(219		)
	252		306		(513		)	(555		)
Total derivatives	$	252	$	320	$	(513	)	$	(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	March 31, 2018			December 31, 2017			March 31, 2018			December 31, 2017
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(167	)	$	(219	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	86			44			(140		)	(55		)
Broker cleared derivative contracts	Other current assets (liabilities)	166			276			(206		)	(283		)
Total gross derivatives		252			320			(513		)	(557		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(63		)	(20		)	63			20
Counterparty netting	Other current assets (liabilities)	(165		)	(263		)	165			263
Total net derivatives		$	24		$	37		$	(285	)	$	(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.

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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 March 31,
		2018		2017
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	3	$	(4	)



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2018			2017
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	17		$	11
Commodity derivatives – Non-trading	Cost of products sold	(73		)	(10		)
Interest rate derivatives	Gains on interest rate derivatives	52			5
Embedded derivatives	Other, net	—			1
Total		$	(4	)	$	7


13.	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 March 31,
	2018		2017
Affiliated revenues	$	286	$	118

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



	March 31, 2018		December 31, 2017
Accounts receivable from related companies:
Sunoco LP	$	209	$	219
FGT	24		11
Other	107		88
Total accounts receivable from related companies:	$	340	$	318

Accounts payable to related companies:
Sunoco LP	$	194	$	195
Other	50		14
Total accounts payable to related companies:	$	244	$	209



	March 31, 2018		December 31, 2017
Long-term notes receivable from related company:
Sunoco LP	$	83	$	85


14.	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.

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The following tables present financial information by segment:



	Three Months Ended March 31,
	2018			2017
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	817		$	768
Intersegment revenues	58			48
	875			816
Interstate transportation and storage:
Revenues from external customers	313			231
Intersegment revenues	3			4
	316			235
Midstream:
Revenues from external customers	440			565
Intersegment revenues	1,174			1,072
	1,614			1,637
NGL and refined products transportation and services:
Revenues from external customers	2,458			2,118
Intersegment revenues	88			148
	2,546			2,266
Crude oil transportation and services:
Revenues from external customers	3,731			2,575
Intersegment revenues	14			—
	3,745			2,575
All other:
Revenues from external customers	521			638
Intersegment revenues	50			132
	571			770
Eliminations	(1,387		)	(1,404		)
Total revenues	$	8,280		$	6,895

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	Three Months Ended March 31,
	2018			2017*
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	192		$	169
Interstate transportation and storage	323			265
Midstream	377			320
NGL and refined products transportation and services	451			381
Crude oil transportation and services	464			187
All other	74			123
Total	1,881			1,445
Depreciation, depletion and amortization	(603		)	(560		)
Interest expense, net	(346		)	(332		)
Gain on Sunoco LP common unit repurchase	172			—
Gains on interest rate derivatives	52			5
Non-cash compensation expense	(20		)	(23		)
Unrealized gains (losses) on commodity risk management activities	(87		)	64
Adjusted EBITDA related to unconsolidated affiliates	(185		)	(239		)
Equity in earnings (losses) of unconsolidated affiliates	(72		)	73
Other, net	47			15
Income before income tax (expense) benefit	$	839		$	448

* As adjusted. See Note 1.



	March 31, 2018		December 31, 2017
Assets:
Intrastate transportation and storage	$	5,008	$	5,020
Interstate transportation and storage	13,730		13,518
Midstream	20,199		20,004
NGL and refined products transportation and services	17,285		17,600
Crude oil transportation and services	17,401		17,736
All other	3,872		4,087
Total assets	$	77,495	$	77,965


15.	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.

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



	March 31, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	—		$	446	$	—		$	446
All other current assets	33			57			5,526		(314		)	5,302
Property, plant and equipment, net	—			—			59,373		—			59,373
Investments in unconsolidated affiliates	48,973			11,957			3,258		(60,930		)	3,258
All other assets	7			—			9,109		—			9,116
Total assets	$	49,013		$	12,014		$	77,712	$	(61,244	)	$	77,495

Current liabilities	$	(1,113	)	$	(3,665	)	$	11,315	$	(314	)	$	6,223
Non-current liabilities	22,124			7,607			7,456		—			37,187
Noncontrolling interest	—			—			6,086		—			6,086
Total partners’ capital	28,002			8,072			52,855		(60,930		)	27,999
Total liabilities and equity	$	49,013		$	12,014		$	77,712	$	(61,244	)	$	77,495



	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

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	Three Months Ended March 31, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	8,280		$	—		$	8,280
Operating costs, expenses, and other	—			—			7,307			—			7,307
Operating income	—			—			973			—			973
Interest expense, net	(278		)	(41		)	(27		)	—			(346		)
Equity in earnings (losses) of unconsolidated affiliates	941			260			(72		)	(1,201		)	(72		)
Gain on Sunoco LP common unit repurchase	—			—			172			—			172
Gains on interest rate derivatives	52			—			—			—			52
Other, net	—			—			60			—			60
Income before income tax benefit	715			219			1,106			(1,201		)	839
Income tax benefit	—			—			(40		)	—			(40		)
Net income	715			219			1,146			(1,201		)	879
Less: Net income attributable to noncontrolling interest	—			—			164			—			164
Net income attributable to partners	$	715		$	219		$	982		$	(1,201	)	$	715

Other comprehensive income	$	—		$	—		$	1		$	—		$	1
Comprehensive income	715			219			1,147			(1,201		)	880
Comprehensive income attributable to noncontrolling interest	—			—			164			—			164
Comprehensive income attributable to partners	$	715		$	219		$	983		$	(1,201	)	$	716



	Three Months Ended March 31, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,895		$	—		$	6,895
Operating costs, expenses, and other	—		—			6,212			—			6,212
Operating income	—		—			683			—			683
Interest expense, net	—		(42		)	(290		)	—			(332		)
Equity in earnings of unconsolidated affiliates	811		628			73			(1,439		)	73
Gains on interest rate derivatives	—		—			5			—			5
Other, net	—		—			19			—			19
Income before income tax expense	811		586			490			(1,439		)	448
Income tax expense	—		—			55			—			55
Net income	811		586			435			(1,439		)	393
Less: Net income attributable to noncontrolling interest	—		—			62			—			62
Net income attributable to partners	$	811	$	586		$	373		$	(1,439	)	$	331

Comprehensive income	811		586			435			(1,439		)	393
Comprehensive income attributable to noncontrolling interest	—		—			62			—			62
Comprehensive income attributable to partners	$	811	$	586		$	373		$	(1,439	)	$	331

* As adjusted. See Note 1.

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	Three Months Ended March 31, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	1,147		$	434		$	2,034		$	(1,841	)	$	1,774
Cash flows used in investing activities	(1,554		)	(431		)	(999		)	1,841			(1,143		)
Cash flows provided by (used in) financing activities	407			—			(898		)	—			(491		)
Change in cash	—			3			137			—			140
Cash at beginning of period	—			(3		)	309			—			306
Cash at end of period	$	—		$	—		$	446		$	—		$	446



	Three Months Ended March 31, 2017*
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	811		$	559		$	1,001		$	(1,439	)	$	932
Cash flows used in investing activities	(534		)	(11		)	(614		)	1,439			280
Cash flows used in financing activities	(277		)	(552		)	(452		)	—			(1,281		)
Change in cash	—			(4		)	(65		)	—			(69		)
Cash at beginning of period	—			41			319			—			360
Cash at end of period	$	—		$	37		$	254		$	—		$	291

* As adjusted. See Note 1.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Tabular dollar and unit amounts, except per unit data, are in millions)

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in the Partnership’s Annual Report on Form 10-K filed with the SEC on February 23, 2018. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part I – Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2017 filed with the SEC on February 23, 2018.

References to “we,” “us,” “our,” the “Partnership” and “ETP” shall mean Energy Transfer Partners, L.P. and its subsidiaries.

OVERVIEW

The primary activities and operating subsidiaries through which we conduct those activities are as follows:


•	Natural gas operations, including the following:


•	natural gas midstream and intrastate transportation and storage; and


•	interstate natural gas transportation and storage.


•	Crude oil, NGLs and refined product transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.

RECENT DEVELOPMENTS

Old Ocean Joint Venture Formation

In May 2018, ETP and Enterprise Products Partners L.P. announced the formation of a joint venture to resume service on the Old Ocean natural gas pipeline. The 24-inch diameter pipeline is expected to resume service in the second quarter of 2018 and ETP will be the operator. Additionally, both parties are in the process of expanding their jointly owned North Texas 36-inch pipeline that will provide more capacity from West Texas for deliveries into the Old Ocean pipeline. The North Texas pipeline expansion project is expected to be complete by late fourth quarter of 2018.

Series C Preferred Units Issuance

CDM Contribution

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New Ethane Export Facility Joint Venture

In March 2018, ETP and Satellite Petrochemical USA Corp. (“Satellite”) entered into definitive agreements to form a joint venture, Orbit Gulf Coast NGL Exports, LLC (“Orbit”), with the purpose of constructing a new export terminal on the United States Gulf Coast to provide ethane to Satellite for consumption at their ethane cracking facilities in China. At the terminal, Orbit will construct an 800 MBbls refrigerated ethane storage tank, a 175 MBbls/d ethane refrigeration facility and a 20-inch ethane pipeline originating at ETP’s Mont Belvieu Fractionators that will make deliveries to the terminal as well as domestic markets in the region. ETP will be the operator of the Orbit assets, provide storage and marketing services for Satellite and provide Satellite with approximately 150 MBbls/d of ethane under a long-term, demand-based agreement. Additionally, ETP will construct and wholly own the infrastructure that is required to both supply ethane to the pipeline and to load the ethane on to very large ethane carriers destined for Satellite’s newly constructed ethane crackers in China’s Jiangsu Province. Subject to Chinese Governmental approval, it is anticipated that the Orbit export terminal will be ready for commercial service in the fourth quarter of 2020.

Sunoco LP Common Unit Repurchase

Regulatory Update

Interstate Natural Gas Transportation Regulation

Effective December 22, 2017, the 2017 Tax and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, FERC addressed treatment of federal income tax allowances in regulated entity rates. FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost of service rates. FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. Requests for rehearing or clarification of the Revised Policy Statement which were filed on or before April 16, 2018, may change FERC’s policy on the treatment of income taxes and impacts that such changes may have on the rates ETP can charge for FERC regulated transportation services are unknown at this time.

FERC also issued a Notice of Inquiry (“2017 Tax Law NOI”) requesting comments on the effect of the Tax Act on FERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to FERC is whether, and if so how, FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the 2017 Tax Law NOI are due on or before May 21, 2018. It is unknown at this time what actions that FERC will take, if any, following receipt of responses to the 2017 Tax Law NOI and any potential impacts from final rules or policy statements issued following the 2017 Tax Law NOI on the rates ETP can charge for FERC regulated transportation services.

Included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. The NOPR proposes a new rule that will, if it becomes a final rule, require all FERC regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to make an election on how to treat its existing rates. The NOPR suggests that this information will allow FERC and other stakeholders to evaluate the impacts of the Tax Act and the Revised Policy Statement on each individual pipeline’s rates. The NOPR proposes that each FERC regulated natural gas pipeline will select one of four options: file a limited Natural Gas Act (“NGA”) Section 4 filing reducing its rates only as required related to the Tax Act and the Revised Policy Statement, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. Comments on the NOPR were due April 25, 2018, and following review of the comments, FERC may issue a final rule. At this time, we cannot predict the outcome of the NOPR, but adoption of the regulation in its proposed form could ultimately result in a rate proceeding that may impact the rates ETP is permitted to charge its customers for FERC regulated transportation services.

Even without action on the NOPR or NOI, the FERC or our shippers may challenge the cost of service rates we charge. FERC’s establishment of a just and reasonable rate is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’s determination of just and reasonable cost of service rates. Although changes in these two tax related components may decrease, other components in the cost of service rate calculation may increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. Moreover, we receive revenues from our pipelines based on

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a variety of rate structures, including cost of service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger Pipeline, LLC, MEP and FEP, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or any final regulations that may result from the March 15, 2018 proposals. The revenues we receive from natural gas transportation services we provide pursuant to cost of service based rates may decrease in the future as a result of the ultimate outcome of the NOI, the NOPR, and the Revised Policy Statement, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost of service rates, if any, will depend on a detailed review of all of ETP’s cost of service components and the outcomes of any challenges to our rates by the FERC or our shippers.

FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Interstate Liquids Transportation Regulation

FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index, or PPI. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23 percent. Many existing pipelines utilize the FERC liquids index to change transportation rates annually every July 1. With respect to liquids and refined products pipelines subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Act on the Page 700 of FERC Form No. 6. This information will be used by FERC in its next five year review of the liquids pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Act in the determination of indexed rates prospectively, effective July 1, 2021. FERC’s establishment of a just and reasonable rate, including the determination of the appropriate liquids pipeline index, is based on many components, and tax related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’s determination of the appropriate pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five year term of index rates, the Revised Policy Statement and tax effects related to the Tax Act may impact our revenues associated with any transportation services we may provide pursuant to cost of service based rates in the future, including indexed rates.

Results of Operations

Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section below titled “Segment Operating Results.” Total Segment Adjusted EBITDA, as presented below, is equal to the consolidated measure of Adjusted EBITDA, which is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures. Our definition of total or consolidated Adjusted EBITDA is consistent with the definition of Segment Adjusted EBITDA above.

As discussed in Note 1 of the Partnership’s consolidated financial statements included in “Item 1. Financial Statements,” 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. These changes

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have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.

Consolidated Results



	Three Months Ended March 31,
	2018			2017*			Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	192		$	169		$	23
Interstate transportation and storage	323			265			58
Midstream	377			320			57
NGL and refined products transportation and services	451			381			70
Crude oil transportation and services	464			187			277
All other	74			123			(49		)
Total	1,881			1,445			436
Depreciation, depletion and amortization	(603		)	(560		)	(43		)
Interest expense, net	(346		)	(332		)	(14		)
Gain on Sunoco LP common unit repurchase	172			—			172
Gains on interest rate derivatives	52			5			47
Non-cash compensation expense	(20		)	(23		)	3
Unrealized gains (losses) on commodity risk management activities	(87		)	64			(151		)
Adjusted EBITDA related to unconsolidated affiliates	(185		)	(239		)	54
Equity in earnings (losses) of unconsolidated affiliates	(72		)	73			(145		)
Other, net	47			15			32
Income before income tax (expense) benefit	839			448			391
Income tax (expense) benefit	40			(55		)	95
Net income	$	879		$	393		$	486

* As adjusted.

See the detailed discussion of Segment Adjusted EBITDA and Segment Operating Results.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased for the three months ended March 31, 2018 compared to the same period last year primarily due to additional depreciation from assets recently placed in service and recent acquisitions.

Interest Expense, net. Interest expense, net of capitalized interest, increased for the three months ended March 31, 2018 compared to the same period last year primarily attributable to increases in long-term debt, including increased borrowings under our revolving credit facilities.

Gain on Sunoco LP Common Unit Repurchase. In connection with Sunoco LP’s repurchase of its common units in February 2018, the Partnership recognized a gain of $172 million.

Gains on Interest Rate Derivatives. Gains on interest rate derivatives during the three months ended March 31, 2018 and 2017 resulted from increases in forward interest rates, which caused our forward-starting swaps to change in value.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional information on the unrealized gains (losses) on commodity risk management activities included in “Segment Operating Results” below.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings (Losses) of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.

Other, net. Includes amortization of regulatory assets and other income and expense amounts.

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Income Tax (Expense) Benefit. For the three months ended March 31, 2018 compared to the same period last year, income tax expense decreased primarily due to the decrease in federal corporate income tax rate per the Tax Act as well as a $67 million deferred benefit adjustment during the three months ended March 31, 2018 as the result of a state statutory rate reduction.

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:



	Three Months Ended March 31,
	2018			2017			Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	27		$	21		$	6
FEP	14			12			2
MEP	9			10			(1		)
HPC	3			7			(4		)
Sunoco LP	(151		)	(14		)	(137		)
Other	26			37			(11		)
Total equity in earnings (losses) of unconsolidated affiliates	$	(72	)	$	73		$	(145	)

Adjusted EBITDA related to unconsolidated affiliates⁽¹⁾:
Citrus	$	75		$	75		$	—
FEP	19			18			1
MEP	22			22			—
HPC	9			15			(6		)
Sunoco LP	29			54			(25		)
Other	31			55			(24		)
Total Adjusted EBITDA related to unconsolidated affiliates	$	185		$	239		$	(54	)

Distributions received from unconsolidated affiliates:
Citrus	$	46		$	41		$	5
FEP	17			—			17
MEP	13			73			(60		)
Sunoco LP	36			35			1
Other	21			23			(2		)
Total distributions received from unconsolidated affiliates	$	133		$	172		$	(39	)


⁽¹⁾	These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

Segment Operating Results

We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:


•	Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.


•	Unrealized gains or losses on commodity risk management activities. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.

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•	Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.


•	Adjusted EBITDA related to unconsolidated affiliates. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA.

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment Margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment Margin is similar to the GAAP measure of gross margin, except that Segment Margin excludes charges for depreciation, depletion and amortization.

In addition, for certain segments, the sections below include information on the components of Segment Margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of Segment Margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of Segment Margin are calculated consistent with the calculation of Segment Margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

Following is a reconciliation of segment margin to operating income, as reported in the Partnership’s consolidated statements of operations:



	Three Months Ended March 31,
	2018			2017
Intrastate transportation and storage	$	171		$	182
Interstate transportation and storage	316			235
Midstream	553			513
NGL and refined products transportation and services	600			559
Crude oil transportation and services	568			272
All other	95			102
Intersegment eliminations	(11		)	(18		)
Total segment margin	2,292			1,845

Less:
Operating expenses	604			492
Depreciation, depletion and amortization	603			560
Selling, general and administrative	112			110
Operating income	$	973		$	683

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Intrastate Transportation and Storage



	Three Months Ended March 31,
	2018			2017			Change
Natural gas transported (BBtu/d)	9,271			7,870			1,401
Withdrawals from storage natural gas inventory (BBtu)	17,703			23,093			(5,390		)
Revenues	$	875		$	816		$	59
Cost of products sold	704			634			70
Segment margin	171			182			(11		)
Unrealized losses on commodity risk management activities	53			15			38
Operating expenses, excluding non-cash compensation expense	(39		)	(38		)	(1		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(6		)	(6		)	—
Adjusted EBITDA related to unconsolidated affiliates	13			16			(3		)
Segment Adjusted EBITDA	$	192		$	169		$	23

Volumes. For the three months ended March 31, 2018 compared to the same period last year, transported volumes increased primarily due to higher demand for exports to Mexico, the addition of new pipelines and more favorable market pricing.

Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:



	Three Months Ended March 31,
	2018			2017			Change
Transportation fees	$	117		$	124		$	(7	)
Natural gas sales and other (excluding unrealized gains and losses)	91			33			58
Retained fuel revenues (excluding unrealized gains and losses)	13			13			—
Storage margin (excluding unrealized gains and losses)	3			27			(24		)
Unrealized losses on commodity risk management activities	(53		)	(15		)	(38		)
Total segment margin	$	171		$	182		$	(11	)

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:


•	an increase of $58 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; offset by


•	a decrease of $24 million in realized storage margin primarily due to an adjustment to the Bammel storage inventory;


•	a decrease of $7 million in transportation fees due to renegotiated contracts resulting in lower billed volumes;


•	an increase of $1 million in operating expenses primarily due to higher expense projects; and

•

a decrease of $3 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a decrease of $3 million from lower demand volumes related to renegotiation of a contract and a decrease of $3 million due to a reserve recorded in the prior period pursuant to the bankruptcy filing of a transport customer, partially offset by an increase of $3 million related to two new joint venture pipelines placed in service in 2017.

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Interstate Transportation and Storage



	Three Months Ended March 31,
	2018			2017			Change
Natural gas transported (BBtu/d)	8,204			5,656			2,548
Natural gas sold (BBtu/d)	17			17			—
Revenues	$	316		$	235		$	81
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(94		)	(74		)	(20		)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(17		)	(12		)	(5		)
Adjusted EBITDA related to unconsolidated affiliates	116			115			1
Other	2			1			1
Segment Adjusted EBITDA	$	323		$	265		$	58

Volumes. For the three months ended March 31, 2018 compared to the same period last year, transported volumes reflected an increase of 1,470 BBtu/d as a result of the partial in service of the Rover pipeline, an increase of 444 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale and deliveries into third party storage and the intrastate markets, and an increase of 402 BBtu/d and 229 BBtu/d on the Panhandle and Trunkline pipelines, respectively, resulting from higher demand due to colder weather.

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net effect of the following:


•	an increase of $49 million due to the partial in service of the Rover pipeline which reflected increases of $82 million in revenues, $26 million in operating expenses and $7 million in general and administrative expenses;


•	a decrease of $6 million in operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to lower allocated costs, reduction in project maintenance work and lower transportation and storage related expenses; and


•	a decrease of $2 million in general and administrative expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to lower allocated costs and insurance reserves.

Midstream



	Three Months Ended March 31,
	2018			2017			Change
Gathered volumes (BBtu/d)	11,306			10,232			1,074
NGLs produced (MBbls/d)	503			445			58
Equity NGLs (MBbls/d)	28			26			2
Revenues	$	1,614		$	1,637		$	(23	)
Cost of products sold	1,061			1,124			(63		)
Segment margin	553			513			40
Unrealized gains on commodity risk management activities	—			(16		)	16
Operating expenses, excluding non-cash compensation expense	(164		)	(161		)	(3		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(20		)	(23		)	3
Adjusted EBITDA related to unconsolidated affiliates	7			7			—
Other	1			—			1
Segment Adjusted EBITDA	$	377		$	320		$	57

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Volumes. For the three months ended March 31, 2018 compared to the same period last year, gathered volumes and NGL production increased primarily due to increases in the Permian and Northeast regions, partially offset by basin declines in the Ark-La-Tex, North Texas and Mid-Continent/Panhandle regions.

Segment Margin. The components of our midstream segment margin were as follows:



	Three Months Ended March 31,
	2018		2017		Change
Gathering and processing fee-based revenues	$	421	$	408	$	13
Non fee-based contracts and processing (excluding unrealized gains and losses)	132		89		43
Unrealized gains on commodity risk management activities	—		16		(16		)
Total segment margin	$	553	$	513	$	40

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net effects of the following:


•	an increase of $27 million in non fee-based margin due to increased throughput volumes in the Permian and South Texas regions;


•	an increase of $16 million in non fee-based margin due to an $11 million increase resulting from higher crude and NGL prices and a $5 million increase in settled price risk management activity;


•	an increase of $13 million in fee-based revenue due to growth in the Permian and Northeast regions, offset by declines in Ark-La-Tex, North Texas and the Mid-Continent/Panhandle regions; and


•	a decrease of $3 million in selling, general and administrative expenses due to lower employee costs and professional fees; offset by


•	an increase of $3 million in operating expenses primarily due to an increase of $2 million in employee costs and an increase of $1 million in ad valorem taxes.

NGL and Refined Products Transportation and Services



	Three Months Ended March 31,
	2018			2017			Change
NGL transportation volumes (MBbls/d)	936			816			120
Refined products transportation volumes (MBbls/d)	620			624			(4		)
NGL and refined products terminal volumes (MBbls/d)	702			790			(88		)
NGL fractionation volumes (MBbls/d)	472			433			39
Revenues	$	2,546		$	2,266		$	280
Cost of products sold	1,946			1,707			239
Segment margin	600			559			41
Unrealized gains on commodity risk management activities	(13		)	(50		)	37
Operating expenses, excluding non-cash compensation expense	(139		)	(127		)	(12		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(18		)	(19		)	1
Adjusted EBITDA related to unconsolidated affiliates	21			17			4
Other	—			1			(1		)
Segment Adjusted EBITDA	$	451		$	381		$	70

Volumes. For the three months ended March 31, 2018 compared to the same period last year, NGL transportation volumes increased primarily from the Permian region, Mariner West pipeline and Mariner South pipeline, partially offset by decreased throughput volumes on Mariner East I due to system downtime in March 2018.

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Refined products transportation volumes decreased slightly for the three months ended March 31, 2018 compared to the same period last year primarily due to lower throughput volumes from the Midwest and Northeast regions, partially offset by increased throughput volumes from the Southwest region.

NGL and refined products terminal volumes decreased for the three months ended March 31, 2018 compared to the same period last year primarily due to the sale of one of our refined product marketing terminals in April 2017, lower volumes loaded for export at our Nederland terminal and lower throughput volumes at our Marcus Hook Industrial Complex due to system downtime on our Mariner East I pipeline in March 2018.

Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased 11% for the three months ended March 31, 2018 compared to the same period last year primarily due to increased volumes from Permian producers.

Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:



	Three Months Ended March 31,
	2018		2017		Change
Fractionators and Refinery services margin	$	134	$	120	$	14
Transportation margin	266		233		33
Storage margin	56		57		(1		)
Terminal Services margin	94		87		7
Marketing margin	37		12		25
Unrealized gains on commodity risk management activities	13		50		(37		)
Total segment margin	$	600	$	559	$	41

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impact of the following:

•

an increase of $33 million in transportation margin due to a $33 million increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines and a $6 million increase due to higher throughput on Mariner West driven by end user facility constraints in the prior period. These increases were offset by a $6 million decrease resulting from lower throughput on Mariner East I due to system downtime in March 2018;


•	an increase of $25 million in marketing margin due to gains of $9 million from optimizing sales of purity product from our Mont Belvieu fractionators, as well as an $8 million increase from our butane blending operations and an $8 million increase from sales of domestic propane and other products at our Marcus Hook Industrial Complex;


•	an increase of $14 million in fractionation and refinery services margin primarily due to an $8 million increase resulting from higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility and a $7 million increase from blending gains as a result of improved market pricing;

•

an increase of $7 million in terminal services margin due to a $10 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018. This increase was offset by a $3 million decrease from our marketing terminal volumes primarily due to the sale of one of our terminals in April 2017; and


•	an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to annual true-up payments from one of our unconsolidated refined product pipelines recorded in January 2018; offset by


•	an increase of $12 million in operating expenses primarily due to a change in the classification of certain customer reimbursements previously recorded in operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018.

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Crude Oil Transportation and Services



	Three Months Ended March 31,
	2018			2017			Change
Crude transportation volumes (MBbls/d)	3,827			3,042			785
Crude terminals volumes (MBbls/d)	1,940			1,777			163
Revenues	$	3,745		$	2,575		$	1,170
Cost of products sold	3,177			2,303			874
Segment margin	568			272			296
Unrealized losses on commodity risk management activities	43			—			43
Operating expenses, excluding non-cash compensation expense	(127		)	(72		)	(55		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(22		)	(17		)	(5		)
Adjusted EBITDA related to unconsolidated affiliates	2			4			(2		)
Segment Adjusted EBITDA	$	464		$	187		$	277

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the following:

•

an increase of $339 million in segment margin (excluding unrealized losses on commodity risk management activities) due to a $222 million increase resulting primarily from placing our Bakken pipeline in service in the second quarter of 2017 as well as a $25 million increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets; an $85 million increase (excluding $43 million in unrealized losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets; and a $7 million increase from higher ship loading and throughput fees at our Nederland terminal due to an increase in exports; offset by

•

an increase of $55 million in operating expenses primarily due to a $26 million increase resulting from placing our Bakken pipeline in service in the second quarter of 2017; a $12 million increase resulting from the addition of certain joint venture crude transportation assets in the second quarter of 2017; and a $15 million increase from existing transportation assets mainly due to higher ad valorem taxes, management fees and pipeline loss allowance; and


•	an increase of $5 million in selling, general and administrative expenses due primarily to insurance and Bakken management fees.

All Other



	Three Months Ended March 31,
	2018			2017			Change
Revenues	$	571		$	770		$	(199	)
Cost of products sold	476			668			(192		)
Segment margin	95			102			(7		)
Unrealized (gains) losses on commodity risk management activities	4			(13		)	17
Operating expenses, excluding non-cash compensation expense	(31		)	(21		)	(10		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(18		)	(21		)	3
Adjusted EBITDA related to unconsolidated affiliates	26			80			(54		)
Other and eliminations	(2		)	(4		)	2
Segment Adjusted EBITDA	$	74		$	123		$	(49	)

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Amounts reflected in our all other segment primarily include:

•

our equity method investment in limited partnership units of Sunoco LP consisting of 26.2 million and 43.5 million units, representing 31.8% and 43.7% of Sunoco LP’s total outstanding common units as of March 31, 2018 and March 31, 2017, respectively. 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;


•	our natural gas marketing and compression operations;


•	a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and


•	our investment in coal handling facilities.

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased primarily due to the net impact of the following:

•

a decrease of $54 million in Adjusted EBITDA related to unconsolidated affiliates, primarily reflecting a decrease of $30 million from our investment in PES due to lower earnings and a decrease of $25 million from our investment in Sunoco LP primarily due to Sunoco LP’s sale of retail assets, as well as a decrease in our ownership interest in Sunoco LP subsequent to the repurchase of common units by Sunoco LP in February 2018;


•	an increase of $10 million in operating expenses primarily attributable to an increase of $8 million in the compression business; offset by


•	an increase of $11 million from commodity trading activities; and


•	a decrease of $3 million in selling, general and administrative expenses due to lower merger and acquisition costs.

LIQUIDITY AND CAPITAL RESOURCES

Overview

ETP’s ability to satisfy its obligations and pay distributions to its Unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

We currently expect capital expenditures in 2018 to be within the following ranges:



	Growth				Maintenance
	Low		High		Low		High
Intrastate transportation and storage	$	250	$	275	$	30	$	35
Interstate transportation and storage ⁽¹⁾	500		550		115		120
Midstream	800		850		120		130
NGL and refined products transportation and services	2,450		2,500		65		75
Crude oil transportation and services ⁽¹⁾	350		450		90		100
All other (including eliminations)	75		100		60		65
Total capital expenditures	$	4,425	$	4,725	$	480	$	525


⁽¹⁾	Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.

The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, we include these factors in our anticipated growth capital expenditures for each year.

We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally fund growth capital expenditures with proceeds of borrowings under credit facilities, long-term debt, the issuance of additional common units, dropdown proceeds or the monetization of non-core assets or a combination thereof.

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Cash Flows

Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, and other factors.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of derivative assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchase and sales of inventories, and the timing of advances and deposits received from customers.

Three months ended March 31, 2018 compared to three months ended March 31, 2017. Cash provided by operating activities during 2018 was $1.77 billion compared to $932 million for 2017 and net income was $879 million and $393 million for 2018 and 2017, respectively. The difference between net income and cash provided by operating activities for the three months ended March 31, 2018 primarily consisted of net changes in operating assets and liabilities of $392 million and non-cash items totaling $405 million.

The non-cash activity in 2018 and 2017 consisted primarily of depreciation, depletion and amortization of $603 million and $560 million, respectively, non-cash compensation expense of $20 million and $23 million, respectively, and equity in losses of unconsolidated affiliates of $72 million and equity in earnings of unconsolidated affiliates of $73 million, respectively. Non-cash activity in 2018 also included a gain on the sale of Sunoco LP units of $172 million and a decrease in deferred income taxes of $40 million. Non-cash activity in 2017 also included an increase in deferred income taxes of $54 million.

Cash paid for interest, net of interest capitalized, was $278 million and $351 million for the three months ended March 31, 2018 and 2017, respectively.

Capitalized interest was $80 million and $59 million for the three months ended March 31, 2018 and 2017, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

Three months ended March 31, 2018 compared to three months ended March 31, 2017. Cash used in investing activities during 2018 was $1.14 billion compared to $280 million provided by investing activities in 2017. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2018 were $1.70 billion compared to $1.38 billion for 2017. Additional detail related to our capital expenditures is provided in the table below. During 2018, we received $540 million in cash related to the Sunoco LP common unit repurchase. During 2017, we received $2.00 billion in cash related to the Bakken equity sale to MarEn Bakken Company, paid $280 million in cash for the acquisition of PennTex noncontrolling interest and paid $38 million in cash for all other acquisitions.

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The following is a summary of capital expenditures (net of contributions in aid of construction costs) for the three months ended March 31, 2018:



	Capital Expenditures Recorded During Period
	Growth		Maintenance		Total
Intrastate transportation and storage	$	139	$	15	$	154
Interstate transportation and storage	131		10		141
Midstream	194		25		219
NGL and refined products transportation and services	530		9		539
Crude oil transportation and services	58		8		66
All other (including eliminations)	31		21		52
Total capital expenditures	$	1,083	$	88	$	1,171

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures.

Three months ended March 31, 2018 compared to three months ended March 31, 2017. Cash used in financing activities during 2018 was $491 million compared to $1.28 billion for 2017. In 2018 and 2017, we received net proceeds from Common Unit offerings of $20 million and $826 million, respectively. During 2018, we had a net increase in our debt level of $416 million compared to a net decrease of $1.10 billion for 2017. We have paid distributions of $945 million to our partners in 2018 compared to $896 million in 2017. We have also paid distributions of $183 million to noncontrolling interests in 2018 compared to $148 million in 2017. In addition, we have received capital contributions of $229 million in cash from noncontrolling interests in 2018 compared to $106 million in 2017. During 2018, we also repurchased common units for cash of $24 million. During 2017, we also repurchased our outstanding Legacy ETP Preferred Units for cash of $53 million and incurred debt issuance costs of $19 million.

Off-Balance Sheet Arrangements

Guarantee of Sunoco LP Notes


•	$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.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	March 31, 2018			December 31, 2017
ETP Senior Notes	$	27,005		$	27,005
Transwestern Senior Notes	575			575
Panhandle Senior Notes	785			785
Credit facilities and commercial paper:
ETP $4.00 billion Revolving Credit Facility due December 2022 ⁽¹⁾	2,756			2,292
ETP $1.00 billion 364-Day Credit Facility due November 2018 ⁽²⁾	—			50
Bakken Project $2.50 billion Credit Facility due August 2019	2,500			2,500
Other long-term debt	4			5
Unamortized premiums, net of discounts and fair value adjustments	61			61
Deferred debt issuance costs	(173		)	(179		)
Total debt	33,513			33,094
Less: current maturities of long-term debt	404			407
Long-term debt, less current maturities	$	33,109		$	32,687


⁽¹⁾	Includes $1.93 billion and $2.01 billion of commercial paper outstanding at March 31, 2018 and December 31, 2017, respectively.


⁽²⁾	Borrowings under the 364-day credit facility were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.

Credit Facilities and Commercial Paper

ETP Five-Year Credit Facility

ETP 364-Day Facility

Bakken Credit Facility

Covenants Related to Our Credit Agreements

We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of March 31, 2018.

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CASH DISTRIBUTIONS

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

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

Distribution per Preferred Unit

Quarter Ended

Record Date

Payment Date

Series A

Series B

December 31, 2017

February 1, 2018

February 15, 2018

15.451

16.378

The total amounts of distributions declared for the periods presented (all from Available Cash from our operating surplus and are shown in the period with respect to which they relate):



	Three Months Ended March 31,
	2018			2017
Limited Partners:
Common Units held by public	$	642		$	567
Common Units held by ETE	16			15
General Partner interest and incentive distributions held by ETE	449			381
IDR relinquishments	(42		)	(157		)
Total distributions declared to partners	$	1,065		$	806

In connection with previous transactions, ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods:



	Total Year
2018 (remainder)	$	111
2019	128
Each year beyond 2019	33

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. We describe our significant accounting policies in Note 2 to our consolidated financial statements in the Partnership’s Annual Report on Form 10-K filed with the SEC on February 23, 2018. See Note 1 in “Item 1. Financial Statements” for information regarding recent changes to the Partnership’s critical accounting policies related to revenue recognition.

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RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 in “Item 1. Financial Statements” included in this Quarterly Report for information regarding recent accounting pronouncements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A included in the Partnership’s Annual Report on Form 10-K filed with the SEC on February 23, 2018, in addition to the accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed for the year ended December 31, 2017. Since December 31, 2017, there have been no material changes to our primary market risk exposures or how those exposures are managed.

Commodity Price Risk

The table below summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Dollar amounts are presented in millions.



	March 31, 2018							December 31, 2017
	Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	1,008		$	—		$	—	1,078		$	—		$	—
Basis Swaps IFERC/NYMEX ⁽¹⁾	82,493		6			—		48,510		2			1
Options – Puts	13,000		—			—		13,000		—			—
Options – Calls	460		—			—		—		—			—
Power (Megawatt):
Forwards	236,680		5			1		435,960		1			1
Futures	126,200		—			—		(25,760	)	—			—
Options – Puts	238,400		1			1		(153,600	)	—			1
Options – Calls	349,600		(1		)	1		137,600		—			—
Crude (MBbls) – Futures	—		—			—		—		1			—
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	9,750		(52		)	15		4,650		(13		)	4
Swing Swaps IFERC	(24,825	)	—			—		87,253		(2		)	1
Fixed Swaps/Futures	(4,620	)	1			7		(4,700	)	(1		)	2
Forward Physical Contracts	(224,178	)	1			—		(145,105	)	6			41
Natural Gas Liquid/Crude (MBbls) – Forwards/Swaps	38,875		(54		)	7		6,679		1			25
Refined Products (MBbls) – Futures	(1,219	)	(1		)	9		(3,783	)	(25		)	4
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(18,685	)	—			—		(39,770	)	(2		)	—
Fixed Swaps/Futures	(18,685	)	—			6		(39,770	)	14			11


⁽¹⁾	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

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The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

Interest Rate Risk

As of March 31, 2018, we had $5.86 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $59 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding (dollars in millions), none of which are designated as hedges for accounting purposes:



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	March 31, 2018		December 31, 2017
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	$	300	$	300
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		300
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		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.

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains and losses on interest rate derivatives) of $230 million as of March 31, 2018. For the $1.50 billion of interest rate swaps whereby we pay a floating rate and receive a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $11 million. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Under the supervision and with the participation of senior management, including the Chief Executive Officer (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of March 31, 2018 to ensure that information required to be disclosed by us in the reports

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we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

In connection with the Partnership’s adoption of ASC 606 effective January 1, 2018, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard. The Partnership’s adoption and implementation of ASC 606 is discussed in Note 1 to the consolidated financial statements included in “Item 1. Financial Statements.”

There have been no changes in our internal controls, other than those discussed above, over financial reporting (as defined in Rule 13(a)–15(f) or Rule 15d–15(f) of the Exchange Act) during the three months ended March 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Annual Report on Form 10-K filed with the SEC on February 23, 2018 and Note 10 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Partners, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2018.

Pursuant to the instructions to Form 10-Q, matters disclosed in this Part II, Item 1 include any reportable legal proceeding (i) that has been terminated during the period covered by this report, (ii) that became a reportable event during the period covered by this report, or (iii) for which there has been a material development during the period covered by this report.

In August 2017, the Delaware Department of Natural Resources & Environmental Control issued an Air NOV at the Marcus Hook Industrial Complex related to unpermitted sources going to the ethylene complex flare. In March 2018, we settled the matter under a reconciliation order for $750,000. The matter is now closed and all sources going to the flare are permitted.

In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover has implemented the suggestions in the assessment and additional voluntary protocols. The FERC has authorized Rover to resume HDD activities at all sites.

Energy Transfer Company Field Services received NOV REG-0569-1701 on June 6, 2017 for emission events that occurred January 1, 2017 through April 16, 2017 at the Jal 3 gas plant. On September 11, 2017, the New Mexico Environmental Department sent ETP a settlement offer to resolve the NOV for a penalty of $596,278. Negotiations for this settlement offer are ongoing.

Energy Transfer Field Services received NOV REG-0569-1702 on December 8, 2017 for emission events that occurred April 17, 2017 through September 23, 2017 at the Jal 3 gas plant. On January 31, 2018, ETP received a settlement offer to resolve the NOV for a penalty of $602,138. Negotiations for this settlement offer are ongoing.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed above were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $100,000.

ITEM 1A. RISK FACTORS

Except as set forth below, there have been no material changes from the risk factors described in Part I, Item 1A in the Partnership’s Annual Report on Form 10-K filed with the SEC on February 23, 2018 for our previous fiscal year ended December 31, 2017.

Our interstate natural gas pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.

Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of our interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs.

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We are required to file tariff rates (also known as recourse rates) with the FERC that shippers may pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. The FERC must approve or accept all rate filings for us to be allowed to charge such rates.

The FERC may review existing tariff rates on its own initiative or upon receipt of a complaint filed by a third party. The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several other pipeline companies. If the FERC were to initiate a proceeding against us and find that our rates were not just and reasonable or unduly discriminatory, the maximum rates we are permitted to charge may be reduced and the reduction could have an adverse effect on our revenues and results of operations.

The costs of our interstate pipeline operations may increase and we may not be able to recover all of those costs due to FERC regulation of our rates. If we propose to change our tariff rates, our proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit our proposed changes if we are unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. We also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or we may be constrained by competitive factors from charging our tariff rates.

To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for and obtain rate increases, our operating results would be negatively affected. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. We cannot guarantee that our interstate pipelines will be able to recover all of our costs through existing or future rates.

On December 22, 2017, the Tax Act was enacted, which reduced the highest marginal United States federal corporate income tax rate from 35 percent to 21 percent for tax years beginning after December 31, 2017. In a series of related proposals on March 15, 2018, the FERC has proposed a new policy that will no longer allow master limited partnerships to recover an income tax allowance in their cost of service rates, and the FERC also proposed rules for implementing this revised policy and the corporate income tax rate reduction pursuant to the Tax Act with respect to natural gas pipeline rates. The proposed rules, if they become final, would require all FERC regulated natural gas pipelines that have cost of service rates for service to make a one-time filing providing certain financial information that will allow the FERC and other stakeholders to evaluate the impacts of the revised policy and the corporate income tax rate reduction on each individual pipeline’s rates, and to select one of four options: file a limited NGA Section 4 filing reducing its rates only as required related to the revised policy and the Tax Act, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. See Recent Developments in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information regarding recent regulatory updates.

We cannot predict the outcome of the NOPR, but the cost of service rates we are permitted to charge our customers for transportation services could be impacted if any of our FERC regulated natural gas pipelines files a limited or general NGA Section 4 rate filing or if the FERC or customers challenge the cost of service rates that these entities are authorized to charge. If FERC requires us to establish new tariff rates for our regulated natural gas pipelines that receive revenue based on cost of service rates as a result of lower federal corporate income tax rates and the Revised Policy Statement, it is possible the new tariff rates would be lower than our current cost of services rates which could adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.

Our interstate natural gas pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect our business and results of operations.

In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of our interstate natural gas pipelines, including:

Compliance with these requirements can be costly and burdensome. In addition, we cannot guarantee that the FERC will authorize tariff changes and other activities we might propose and to undertake in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof may impair our access to capital markets or may impair the ability of our interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.


•	terms and conditions of service;


•	the types of services interstate pipelines may or must offer their customers;


•	construction of new facilities;

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•	acquisition, extension or abandonment of services or facilities;


•	reporting and information posting requirements;


•	accounts and records; and


•	relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

The Pipeline Certification NOI initiated a review of the FERC’s policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Rate regulation or market conditions may not allow us to recover the full amount of increases in the costs of our crude oil, NGL and products pipeline operations.

Transportation provided on our common carrier interstate crude oil, NGL and products pipelines is subject to rate regulation by the FERC, which requires that tariff rates for transportation on these oil pipelines be just and reasonable and not unduly discriminatory. If we propose new or changed rates, the FERC or interested persons may challenge those rates and the FERC is authorized to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unjust or unreasonable, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

The primary ratemaking methodology used by the FERC to authorize increases in the tariff rates of petroleum pipelines is price indexing. The FERC’s ratemaking methodologies may limit our ability to set rates based on our costs or may delay the use of rates that reflect increased costs. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (i) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15 percent for the prior two years; (ii) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5 percent above the barrel-mile cost changes; and (iii) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward the full indexed increase to a future period. The comment period with respect to the proposed rules ended March 17, 2017. FERC has not yet taken any further action on the proposed rule. If the FERC’s indexing methodology changes, the new methodology could materially and adversely affect our financial condition, results of operations or cash flows.

Under the United States Environmental Protection Agency Act of 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of our FERC regulated pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline’s costs. In such event, the FERC could order us to reduce pipeline rates prospectively and to pay refunds to shippers.

If the FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.

The FERC’s Revised Policy Statement requires the reduced maximum corporate tax rate to be reflected in initial liquids cost of service rates and cost of service rate changes going forward and in future filings of Page 700 of FERC Form No. 6. FERC will consider the information provided by pipelines in Page 700 of FERC Form No. in its 2020 five-year review of the liquids pipeline index level. See Recent Developments in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information regarding recent regulatory updates. We cannot predict the outcome of the 2020 liquids pipeline index five-year review, but the rates we are permitted to charge our customers for cost of service based liquids transportation services could be impacted. If FERC requires us to establish new tariff rates for our regulated liquids pipelines that reflect a lower federal corporate income tax rate and the Revised Policy Statement, it is possible the rates would be reduced, which could adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.

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Treatment of distributions on our preferred units as guaranteed payments for the use of capital creates a different tax treatment for the holders of preferred units than the holders of our common units and such distributions may not be eligible for the 20% deduction for qualified publicly traded partnership income.

The tax treatment of distributions on our preferred units is uncertain. We will treat each of the holders of the preferred units as partners for tax purposes and will treat distributions on the preferred units as guaranteed payments for the use of capital that will generally be taxable to each of the holders of preferred units as ordinary income. Holders of our preferred units will recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution). Otherwise, except in the case of our liquidation, the holders of preferred units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of preferred units. If the preferred units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to each of the holders the preferred units.

Although we expect that much of the income we earn is generally eligible for the 20 percent deduction for qualified publicly traded partnership income, it is uncertain whether a guaranteed payment for the use of capital may constitute an allocable or distributive share of such income. As a result the guaranteed payment for use of capital received by our preferred units may not be eligible for the 20% deduction for qualified publicly traded partnership income.

A holder of preferred units will be required to recognize gain or loss on a sale of preferred units, as applicable, equal to the difference between the amount realized by such holder and such holder’s tax basis in the preferred units, as applicable, sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such preferred units, as applicable. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a preferred unit, as applicable, will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of such preferred units, as applicable, to acquire such preferred unit, as applicable. Gain or loss recognized by a holder of preferred units on the sale or exchange of a preferred unit, as applicable, held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of preferred units will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

Investment in the preferred units by tax-exempt investors, such as employee benefit plans and individual retirement accounts, and non-United States persons raises issues unique to them. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes. Distributions to non-United States holders of preferred units will be subject to withholding taxes. If the amount of withholding exceeds the amount of United States federal income tax actually due, non-United States holders of preferred units may be required to file United States federal income tax returns in order to seek a refund of such excess.

All holders of our preferred units are urged to consult a tax advisor with respect to the consequences of owning our preferred units.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table discloses purchases of our common units made by us or on our behalf in the quarter ended March 31, 2018:



Period	Total Number of Units Purchased	Average Price Paid per Unit		Total Number of Units Not Purchased as Part of Publicly Announced Plans or Programs ⁽¹⁾	Total Number of Units Purchased as Part of Publicly Announced Plans or Programs
January 2018	1,182,745	$	20.06	1,182,745	—
February 2018	—	—		—	—
March 2018	—	—		—	—


⁽¹⁾	The units reported in this column represent purchases settled during the quarter ended March 31, 2018 relating to our purchases of units in open-market transactions to meet our obligations under our equity incentive plans for employees, officers and directors.

ITEM 5. OTHER INFORMATION

We are including information in this “Part II - Item 5. Other Information” in order to: (i) file Exhibit 99.1 hereto to replace in its entirety (a) the section under the heading “Material U.S. Federal Income Tax Considerations” that appears in the prospectus supplement we filed with the SEC on May 10, 2017 (the “ATM Prospectus”) and (b) the section under the heading “Material U.S. Federal Income Tax Consequences” that appears in the Registration Statement on Form S-3 (Registration File No. 333- 219224)

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we filed with the SEC on July 11, 2017 (the “DRIP Registration Statement”), in each case to provide updated disclosure regarding the material tax considerations associated with our operations and the purchase, ownership and disposition of our common units and (ii) provide the legal opinion of Vinson & Elkins L.L.P. relating to certain tax matters in connection with the ATM Prospectus and the DRIP Registration Statement, a copy of which is filed as Exhibit 8.1 hereto.

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ITEM 6. EXHIBITS

The exhibits listed below are filed or furnished, as indicated, as part of this report:



Exhibit Number		Description
2.1		Contribution Agreement, dated as of January 15, 2018, by and among USA Compression Partners, LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETC Compression, LLC, and solely for certain purposes therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to the Current Report of For 8-K filed January 16, 2018)
2.2		Purchase Agreement, dated as of January 15, 2018, by and among USA Compression Holdings, LLC, Energy Transfer Equity, L.P., Energy Transfer Partners, L.L.C., and solely for certain purposes therein R/C IV USACP Holdings, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed January 16, 2018)
3.1		Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 of Form S-1 Registration Statement filed October 22, 2001)
3.2		Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of August 28, 2015 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed September 1, 2015)
3.3		Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of April 28, 2017 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K filed April 28, 2017)
3.4		Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. dated as of April 28, 2017 (incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K filed April 28, 2017)
3.5		Amendment No. 1, dated November 16, 2017, to the Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated as of April 28, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed November 16, 2017)
3.6		Amendment No. 2, dated as of April 25, 2018, to Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated as of April 28, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed April 25, 2018)
8.1*		Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1		Registration Rights Agreement, dated as of April 2, 2018, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P., USA Compression Partners, LP and USA Compression Holdings, LLC. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed April 3, 2018)
10.2		Transition Services Agreement, dated as of April 2, 2018, by and among USA Compression Partners, LP, CDM Resource Management LLC, CDM Environmental & Technical Services LLC and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed April 3, 2018)
12.1*		Computation of Ratio of Earnings to Fixed Charges
23.1*		Consent of Vinson & Elkins L.L.P. (included in Exhibit 8.1 hereto)
31.1*		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*		Material U.S. Federal Income Tax Consequences
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document



*		Filed herewith.
**		Furnished herewith.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		ENERGY TRANSFER PARTNERS, L.P.

		By:	Energy Transfer Partners GP, L.P.
			its General Partner

		By:	Energy Transfer Partners, L.L.C.
			its General Partner

Date:	May 10, 2018	By:	/s/ A. Troy Sturrock
			A. Troy Sturrock
			Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant)