10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2017

OR

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

Commission file number 1-32740

ENERGY TRANSFER EQUITY, L.P.

(Exact name of registrant as specified in its charter)

Delaware	30-0108820
(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)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Units	New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes  ý    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes  ¨    No  ý

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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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.

Large accelerated filer  ý    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨ Emerging growth company  ¨

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

The aggregate market value as of June 30, 2017, of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such Common Units on the New York Stock Exchange on such date, was $14.11 billion. Common Units held by each executive officer and director and by each person who owns 5% or more of the outstanding Common Units have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

At February 16, 2018, the registrant had 1,079,145,561 Common Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

PART I
		PAGE
ITEM 1.	BUSINESS	1
ITEM 1A.	RISK FACTORS	34
ITEM 1B.	UNRESOLVED STAFF COMMENTS	70
ITEM 2.	PROPERTIES	70
ITEM 3.	LEGAL PROCEEDINGS	70
ITEM 4.	MINE SAFETY DISCLOSURES	73
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	74
ITEM 6.	SELECTED FINANCIAL DATA	75
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	76
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	117
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	120
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	120
ITEM 9A.	CONTROLS AND PROCEDURES	120
ITEM 9B.	OTHER INFORMATION	122
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	123
ITEM 11.	EXECUTIVE COMPENSATION	128
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	142
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	144
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	145
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	147
ITEM 16	FORM 10-K SUMMARY	148
	Signatures	152

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (the “Partnership” or “ETE”) 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,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “could,” “believe,” “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, estimated, projected, forecasted, expressed or expected 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 “Item 1.A Risk Factors” included in this annual report.

Definitions

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

/d	per day
Aloha	Aloha Petroleum, Ltd
AmeriGas	AmeriGas Partners, L.P.
AOCI	accumulated other comprehensive income (loss)
AROs	asset retirement obligations
Bbls	barrels
BBtu	billion British thermal units
Bcf	billion cubic feet
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 content
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 which owns 100% of FGT
CrossCountry	CrossCountry Energy, LLC
Dakota Access	Dakota Access, LLC
DOE	United States Department of Energy
DOJ	United States Department of Justice
DOT	United States Department of Transportation
Eagle Rock	Eagle Rock Energy Partners, L.P.
ELG	Edwards Lime Gathering, LLC
EPA	United States Environmental Protection Agency
ETC FEP	ETC Fayetteville Express Pipeline, LLC
ETC MEP	ETC Midcontinent Express Pipeline, L.L.C.

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ETC OLP	La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
ETCO	Energy Transfer Crude Oil Company, LLC
ETG	Energy Transfer Group, L.L.C.
ETE Holdings	ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE
ETP	Energy Transfer Partners, L.P.
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
ETP Convertible Preferred Units	ETP’s Series A Convertible Preferred Units
ETP Series A Preferred Units	Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
ETP Series B Preferred Units	Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Exchange Act	Securities Exchange Act of 1934
ExxonMobil	Exxon Mobil Corporation
FDOT/FTE	Florida Department of Transportation, Florida’s Turnpike Enterprise
FEP	Fayetteville Express Pipeline LLC
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company, LLC, which owns a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula
GAAP	accounting principles generally accepted in the United States of America
General Partner	LE GP, LLC, the general partner of ETE
HPC	RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP
IDRs	incentive distribution rights
KMI	Kinder Morgan Inc.
Lake Charles LNG	Lake Charles LNG Company, LLC
LCL	Lake Charles LNG Export Company, LLC
LIBOR	London Interbank Offered Rate
LNG	liquefied natural gas
LNG Holdings	Lake Charles LNG Holdings, LLC
Lone Star	Lone Star NGL LLC
LPG	liquefied petroleum gas
MACS	Mid-Atlantic Convenience Stores, LLC
MBbls	thousand barrels
MEP	Midcontinent Express Pipeline LLC
Sunoco Logistics Merger	The merger of Sunoco Logistics with and into ETP, with ETP surviving the merger as a wholly owned subsidiary of Sunoco Logistics
MMcf	million cubic feet
MTBE	methyl tertiary butyl ether

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NGA	Natural Gas Act of 1938
NGL	natural gas liquid, such as propane, butane and natural gasoline
NGPA	Natural Gas Policy Act of 1978
NYMEX	New York Mercantile Exchange
NYSE	New York Stock 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
PEP	Permian Express Partners LLC
PEPL	Panhandle Eastern Pipe Line Company, LP
PES	Philadelphia Energy Solutions
PHMSA	Pipeline Hazardous Materials Safety Administration
Phillips 66	Phillips 66 Partners LP
Ranch JV	Ranch Westex JV LLC
Regency	Regency Energy Partners LP
Retail Holdings	ETP Retail Holdings LLC, a subsidiary of ETP
RGS	Regency Gas Services, a wholly-owned subsidiary of Regency
RIGS	Regency Intrastate Gas System
Rover	Rover Pipeline LLC, a subsidiary of ETP
Sea Robin	Sea Robin Pipeline Company, LLC
SEC	Securities and Exchange Commission
Southwest Gas	Pan Gas Storage, LLC
Sunoco GP	Sunoco GP LLC, the general partner of Sunoco LP
Sunoco Logistics	Sunoco Logistics Partners L.P.
Sunoco LP	Sunoco LP (previously named Susser Petroleum Partners, LP)
Sunoco Partners	Sunoco Partners LLC, the general partner of Sunoco Logistics
Susser	Susser Holdings Corporation
TCEQ	Texas Commission on Environmental Quality
Transwestern	Transwestern Pipeline Company, LLC
TRRC	Texas Railroad Commission
Trunkline	Trunkline Gas Company, LLC, a subsidiary of Panhandle
USAC	USA Compression Partners, LP
USAC Holdings	USA Compression Holdings, LLC
WMB	The Williams Companies, Inc.
WTI	West Texas Intermediate Crude

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,

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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 (excluding lower of cost or market 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.

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PART I

ITEM 1.  BUSINESS

Overview

We were formed in September 2002 and completed our initial public offering in February 2006. We are a Delaware limited partnership with common units publicly traded on the NYSE under the ticker symbol “ETE.”

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle, Sunoco LP, and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

In January 2014 and July 2015, the Partnership completed two-for-one splits of its outstanding common units. All references to units and per unit amounts in this document have been adjusted to reflect the effect of the unit splits for all periods presented.

The historical common units for ETP 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, discussed below.

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and the Partnership’s ownership of Lake Charles LNG.

At January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.

The Parent Company’s primary cash requirements are for distributions to its partners, general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of subsidiaries. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its unitholders on a quarterly basis.

We expect our subsidiaries to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes.

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The following chart summarizes our organizational structure as of February 7, 2018. For simplicity, certain immaterial entities and ownership interests have not been depicted.

Significant Achievements in 2017 and Beyond

Our significant strategic transactions in 2017 and beyond included the following, as discussed in more detail herein:

Significant Achievements Related to ETE

• In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units.

• In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.

Significant Achievements Related to ETP

• In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a100%membership interest, sold a49%interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for$2.00 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access and ETCO. The remaining25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. As discussed below, in July 2017, ETP contributed a portion of its ownership interest in Dakota Access and ETCO to PEP. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

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• In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal.Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including$547 millionof intangible assets and$435 millionof property, plant and equipment.

• In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction, 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 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.

• In July 2017, ETP contributed an approximate15%ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets.ExxonMobil’s contribution resulted in an increase of$988 millionin noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

• In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a49.9%interest in the holding company that owns65%of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.

• In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which ETP will contribute to USAC 100% of the membership interests of CDM and CDM E&T for aggregate consideration of$1.7 billion, consisting of USAC common units, new USAC Class B units and cash. The Class B units will be substantially similar to USAC common units, except the Class B units will not receive distributions paid with respect to USAC common units prior to the one year anniversary of the closing date of the CDM Contribution Agreement. Each Class B Unit will convert into one USAC common unit on such one year anniversary. In connection with the foregoing, ETP entered into a purchase agreement with ETE, ETP LLC, USAC Holdings and, for certain limited purposes, R/C IV USACP Holdings, L.P., pursuant to which ETE and ETP LLC will acquire from USAC Holdings (i) all of the outstanding interests in the general partner of USAC and (ii) 12,466,912USAC common units for$250 million in cash. The transactions are expected to close in the first half of 2018, subject to customary closing conditions.

Significant Achievements Related to Sunoco LP

• On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which will be operated by a commission agent.

• On March 30, 2017, the Partnership purchased 12 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units was 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate would become a floating rate of 8.00% plus three-month LIBOR of the Liquidation Preference.

• In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.

• On January 23, 2018, Sunoco LP completed the sale of a portfolio of approximately 1,030 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the Laredo Taco Company, to 7-Eleven, Inc. for an aggregate purchase price of $3.3 billion (the “7-Eleven Transaction”).

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Business Strategy

Our primary business objective is to increase cash available for distributions to our unitholders by actively assisting our subsidiaries in executing their business strategies by assisting in identifying, evaluating and pursuing strategic acquisitions and growth opportunities. In general, we expect that we will allow our subsidiaries the first opportunity to pursue any acquisition or internal growth project that may be presented to us which may be within the scope of their operations or business strategies. In the future, we may also support the growth of our subsidiaries through the use of our capital resources, which could involve loans, capital contributions or other forms of credit support to our subsidiaries. This funding could be used for the acquisition by one of our subsidiaries of a business or asset or for an internal growth project. In addition, the availability of this capital could assist our subsidiaries in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.

Segment Overview

Our reportable segments are as follows:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the activities of the Parent Company.

The businesses within these segments are described below. See Note 15 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our reportable segments.

Investment in ETP

ETP’s operations include the following:

Intrastate Transportation and Storage Operations

ETP’s natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities and other pipelines. Through its intrastate transportation and storage operations, ETP owns and operates approximately 7,900 miles of natural gas transportation pipelines with approximately 15.2 Bcf/d of transportation capacity and three natural gas storage facilities located in the state of Texas. ETP also owns a 49.99% general partner interest in RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. ETP owns a 16% membership interest in the Trans-Pecos and Comanche Trail pipelines, a 338-mile intrastate pipeline system that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border.

Through ETC OLP, ETP owns the largest intrastate pipeline system in the United States with interconnects to Texas markets and to major consumption areas throughout the United States. ETP’s intrastate transportation and storage operations focus on the transportation of natural gas to major markets from various prolific natural gas producing areas through connections with other pipeline systems as well as through its Oasis pipeline, its East Texas pipeline, its natural gas pipeline and storage assets that are referred to as the ET Fuel System, and its HPL System, which are described below.

ETP’s intrastate transportation and storage operations results are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.

ETP also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and marketing companies on the HPL System. In addition, ETP’s intrastate transportation and storage operations generate revenues from fees charged for storing customers’ working natural gas in ETP’s storage facilities and from managing natural gas for its own account.

Interstate Transportation and Storage Operations

ETP’s natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities and other pipelines. Through its

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interstate transportation and storage operations, ETP directly owns and operates approximately 11,800 miles of interstate natural gas pipelines with approximately 10.3 Bcf/d of transportation capacity and has a 50% interest in the joint venture that owns the 185-mile Fayetteville Express pipeline and the 500-mile Midcontinent Express pipeline. ETP also owns a 50% interest in Citrus, which owns 100% of FGT, an approximately 5,360 mile pipeline system that extends from South Texas through the Gulf Coast to south Florida. ETP operates the FEP and FGT joint ventures.

ETP’s interstate transportation and storage operations include Panhandle, which owns and operates a large natural gas open-access interstate pipeline network.  The pipeline network, consisting of the Panhandle, Trunkline and Sea Robin transmission systems, serves customers in the Midwest, Gulf Coast and Midcontinent United States with a comprehensive array of transportation and storage services.  In connection with its natural gas pipeline transmission and storage systems, Panhandle has five natural gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma.  Southwest Gas operates four of these fields and Trunkline operates one.

The Rover Pipeline is a new713-mile natural gas pipeline designed to transport3.25Bcf/d of domestically produced natural gas from the Marcellus and Utica Shale production areas to markets across the United States as well as into the Union Gas Dawn Storage Hub in Ontario, Canada, for redistribution back into the United States or into the Canadian market. Currently under construction, portions of the pipeline are in service transporting gas from processing plants in Eastern Ohio for delivery to other pipeline interconnects in Eastern Ohio as well as the Midwest Hub near Defiance, Ohio, where the gas will be delivered for distribution to markets across the United States.The Rover Pipeline Phase 1A and 1B are in service with a capacity of approximately1.7 Bcf/d.

ETP also owns a 50% interest in the MEP pipeline system, which is operated by KMI, and has the capability to transport up to 1.8 Bcf/d of natural gas.

Gulf States is a small interstate pipeline that uses cost-based rates and terms and conditions of service for shippers wishing to secure capacity for interstate transportation service. Rates charged are largely governed by long-term negotiated rate agreements.

The results from ETP’s interstate transportation and storage operations are primarily derived from the fees ETP earns from natural gas transportation and storage services.

Midstream Operations

The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry consists of natural gas gathering, compression, treating, processing, storage and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells and the proximity of storage facilities to production areas and end-use markets.

The natural gas gathering process begins with the drilling of wells into gas-bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems, that collects natural gas from points near producing wells and transports it to larger pipelines for further transportation.

Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and to continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise might not be produced.

Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations is higher in carbon dioxide, hydrogen sulfide or certain other contaminants. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications.

Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas produced by a well, while not required to be processed, can be processed to take advantage of favorable margins for NGLs extracted from the gas stream. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream.

Through its midstream operations, ETP owns and operates natural gas and NGL gathering pipelines, natural gas processing plants, natural gas treating facilities and natural gas conditioning facilities with an aggregate processing, treating and conditioning capacity

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of approximately 12.3 Bcf/d. ETP’s midstream operations focus on the gathering, compression, treating, blending, and processing, of natural gas and its operations are currently concentrated in major producing basins and shales, including the Austin Chalk trend and Eagle Ford Shale in South and Southeast Texas, the Permian Basin in West Texas and New Mexico, the Barnett Shale and Woodford Shale in North Texas, the Bossier Sands in East Texas, the Marcellus Shale in West Virginia and Pennsylvania, and the Haynesville Shale in East Texas and Louisiana. Many of ETP’s midstream assets are integrated with its intrastate transportation and storage assets.

ETP’s midstream operations also include a 60% interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in South Texas, a 33.33% membership interest in Ranch Westex JV LLC, which processes natural gas delivered from the NGLs-rich shale formations in West Texas, a 75% membership interest in ORS, which operates a natural gas gathering system in the Utica shale in Ohio, and a 50% interest in Mi Vida JV, which operates a cryogenic processing plant and related facilities in West Texas, a 51% membership interest in Aqua – PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, and a 50% interest in Sweeny Gathering LP, which operates a natural gas gathering facility in South Texas.

The results from ETP’s midstream operations are primarily derived from margins ETP earns for natural gas volumes that are gathered, transported, purchased and sold through ETP’s pipeline systems and the natural gas and NGL volumes processed at its processing and treating facilities.

NGL and Refined Products Transportation and Services Operations

ETP’s NGL operations transport, store and execute acquisition and marketing activities utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets.

Liquids transportation pipelines transport mixed NGLs and other hydrocarbons from natural gas processing facilities to fractionation plants and storage facilities. NGL storage facilities are used for the storage of mixed NGLs, NGL products and petrochemical products owned by third parties in storage tanks and underground wells, which allow for the injection and withdrawal of such products at various times of the year to meet demand cycles.NGL fractionators separate mixed NGL streams into purity products, such as ethane, propane, normal butane, isobutane and natural gasoline.

ETP’s NGL and refined products transportation and services operations include approximately 4,300 miles of NGL pipelines, five NGL and propane fractionation facilities with an aggregate capacity of 545 MBbls/d and NGL storage facilities with aggregate working storage capacity of approximately 53 million Bbls. Four of ETP’s NGL and propane fractionation facilities and 50 million Bbls of ETP’s NGL storage capacity are located at Mont Belvieu, Texas, one NGL fractionation facility is located in Geismar, Louisiana, and the segment has 3 million Bbls of salt dome storage capacity near Hattiesburg, Mississippi. ETP is currently constructing a fifth and sixth fractionator in Mont Belvieu, Texas, which are expected to be operational in the third quarter of 2018 and the second quarter of 2019, respectively. The NGL pipelines primarily transport NGLs from the Permian and Delaware basins and the Barnett and Eagle Ford Shales to Mont Belvieu.

Terminalling services are facilitated by approximately 7 million Bbls of NGLs storage capacity, including approximately 1 million Bbls of storage at ETP’s Nederland, Texas terminal facility, 1 million Bbls of storage at our Inkster, Michigan terminal facility and 5 million Bbls at ETP’s Marcus Hook, Pennsylvania terminal facility (the “Marcus Hook Industrial Complex”). These operations also support ETP’s NGLs blending activities, including the use of ETP’s patented butane blending technology.

Liquids transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are market-based, negotiated with customers and competitive with regional regulated pipelines.

NGL fractionation revenue is principally generated from fees charged to customers under take-or-pay contracts. Take-or-pay contracts have minimum payment obligations for throughput commitments requiring the customer to pay regardless of whether a fixed volume is fractionated from raw make into purity NGL products. Fractionation fees are market-based, negotiated with customers and competitive with other fractionators along the Gulf Coast.

NGL storage revenues are derived from base storage fees and throughput fees. Base storage fees are firm take or pay contracts on the volume of capacity reserved, regardless of the capacity actually used. Throughput fees are charged for providing ancillary services, including receipt and delivery and custody transfer fees.

This segment also includes revenues earned from the marketing of NGLs and processing and fractionating refinery off-gas. Marketing of NGLs primarily generates margin from selling ratable NGLs to end users and from optimizing storage assets.

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Processing and fractionation of refinery off-gas margin is generated from a percentage-of-proceeds of O-grade product sales and income sharing contracts, which are subject to market pricing of olefins and NGLs.

ETP’s refined products operations provide transportation and terminalling services, through the use of approximately 2,200 miles of refined products pipelines and approximately 40 active refined products marketing terminals. ETP’s marketing terminals are located primarily in the northeast, midwest and southwest United States, with approximately 8 million Bbls of refined products storage capacity. ETP’s refined products operations include its Eagle Point facility in New Jersey, which has approximately 6 million Bbls of refined products storage capacity. The operations also include ETP’s equity ownership interests in four refined products pipeline companies. The operations also perform terminalling activities at ETP’s Marcus Hook Industrial Complex. ETP’s refined products operations utilize its integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions in the United States.

Crude Oil Transportation and Services Operations

ETP’s crude oil operations provide transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Included within the operations are approximately 9,360 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States and equity ownership interests in two crude oil pipelines. ETP’s crude oil terminalling services operate with an aggregate storage capacity of approximately 33 million Bbls, including approximately 26 million Bbls at ETP’s Gulf Coast terminal in Nederland, Texas and approximately 3 million Bbls at ETP’s Fort Mifflin terminal complex in Pennsylvania. ETP’s crude oil acquisition and marketing activities utilize its pipeline and terminal assets, its proprietary fleet crude oil tractor trailers and truck unloading facilities, as well as third-party assets, to service crude oil markets principally in the mid-continent United States.

Revenues throughout ETP’s crude oil pipeline systems are generated from tariffs paid by shippers utilizing its transportation services. These tariffs are filed with the FERC and other state regulatory agencies, as applicable.

ETP’s crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil primarily in the mid-continent United States. Specifically, the crude oil acquisition and marketing activities include:

• purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;

• storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);

• buying and selling crude oil of different grades, at different locations in order to maximize value;

• transporting crude oil using the pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and

• marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.

In November 2016, ETP purchased a crude oil acquisition and marketing business from Vitol, with operations based in the Permian Basin, Texas. Included in the acquisition was a significant acreage dedication from an investment-grade Permian producer.

ETP’s Other Operations and Investments

ETP’s other operations and investments include the following:

• ETP owns an equity method investment in limited partner units of Sunoco LP. As of December 31, 2017, ETP’s investment consisted of 43.5 millionunits, representing43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, ETP’s investment consists of 26.2 millionunits, representing31.8%of Sunoco LP’s total outstanding common units.

• ETP’s wholly-owned subsidiary, Sunoco, Inc., owns an approximate 33% non-operating interest in PES, a refining joint venture with The Carlyle Group, L.P., which owns a refinery in Philadelphia.

• PES Holdings, LLC ("PES Holdings") and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018 in the United States Bankruptcy Court for the District of Delaware to implement a prepackaged reorganization plan that will allow its shareholders to retain a minority stake. PES Holdings' Chapter 11 Plan (“Plan”) proposes to inject $260 million in new capital into PES Holdings, cut debt service obligations by about $35 million per year and remove debt maturities before 2022.  Under that Plan, PES Holdings’ non-debtor parent, PES, in which ETP holds an indirect 33% equity interest, will provide a $65 million cash contribution in exchange for a 25% stake in the reorganized debtor. After the restructuring, the proportionate ownership of Carlyle Group, L.P. and ETP in PES Holdings will be 16.26% and 8.13%, respectively. Finally,

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Sunoco Logistics Partners Operations L.P. (“SXL Operating Partnership”), a subsidiary of ETP, is providing an additional $75 million exit loan ranked pari passu with the other debt.  SXL Operating Partnership’s, PES Holdings’ and ETP’s current contracts will be assumed, without any impairments, in the Chapter 11, and business operations will continue uninterrupted.  The financial reorganization is expected to complete in the first quarter of 2018.

• ETP conducts marketing operations in which it markets the natural gas that flows through its gathering and intrastate transportation assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other suppliers and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation. For the off-system gas, ETP purchases gas or acts as an agent for small independent producers that may not have marketing operations.

• ETP owns a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.

• ETP owns 100% of the membership interests of ETG, which owns all of the partnership interests of Energy Transfer Technologies, Ltd. (“ETT”). ETT provides compression services to customers engaged in the transportation of natural gas, including ETP’s other operations.

• ETP owns a 40% interest in the parent of LCL, which is developing a LNG liquefaction project.

• ETP owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. ETP also owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. These assets are primarily owned through CDM and CDM E&T. As discussed in “Recent Developments” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in January 2018, ETP entered into an agreement to contribute these assets to USAC.

• ETP is involved in the management of coal and natural resources properties and the related collection of royalties. ETP also earns 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.

• ETP also owns PEI Power Corp. and PEI Power II, which own and operate a facility in Pennsylvania that generates a total of 75 megawatts of electrical power.

Investment in Sunoco LP

Sunoco LP is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites.

Wholesale Operations

Sunoco LP is a wholesale distributor of motor fuels and other petroleum products which Sunoco LP supplies to its retail operations, to third-party dealers and distributors, to independent operators of commission agent locations and other consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.

Sunoco LP is the exclusive wholesale supplier of the iconic Sunoco-branded motor fuel, supplying an extensive distribution network of approximately 5,322 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest South Central and Southeast regions of the United States, including 245 company operated Sunoco-branded Stripes locations in Texas. Sunoco LP believes it is one of the largest independent motor fuel distributors by gallons in Texas and one of the largest distributors of Chevron, Exxon, Shell and Valero branded motor fuel in the United States. In addition to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it leases or subleases.

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Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distribute it across more than 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States, as well as Hawaii to approximately:

• 1,348 convenience stores and fuel outlets.

• 153 independently operated consignment locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators;

• 5,501 convenience stores and retail fuel outlets operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and

• 2,222 other commercial customers, including unbranded convenience stores, other fuel distributors, school districts and municipalities and other industrial customers.

On January 23, 2018, Sunoco LP sold a portfolio of 1,030 company-operated retail fuel outlets to 7-Eleven.

Retail Operations

As of December 31, 2017, prior to the closing of the amended and restated purchasing agreement with 7-Eleven, Sunoco LP’s retail segment operated approximately1,348convenience stores and retail fuel outlets. Sunoco LP’s retail convenience stores operates under several brands, including its proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. Sunoco LP has company operated sites in more than 20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.

As of December 31, 2017, Sunoco LP operated approximately 746 Stripes convenience stores in Texas, New Mexico, Oklahoma and Louisiana. Each store offers a customized merchandise mix based on local customer demand and preferences. Sunoco LP built approximately 265 large-format convenience stores from January 2000 through December 31, 2017. Sunoco LP has implemented its proprietary, in-house Laredo Taco Company restaurant concept in approximately 477 Stripes convenience stores. Sunoco LP also owns and operates ATM and proprietary money order systems in most Stripes stores and provides other services such as lottery, prepaid telephone cards, wireless services and car washes.

As of December 31, 2017, Sunoco LP operated approximately 441 retail convenience stores and fuel outlets, primarily under its proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 404 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise, as well as motor fuel and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.

As of December 31, 2017, Sunoco LP operated approximately 161 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2017, MACS operated approximately 107 retail convenience stores and Aloha operated approximately 54 Aloha, Shell, and Mahalo branded fuel stations.

Investment in Lake Charles LNG

Lake Charles LNG provides terminal services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long term contracts with a wholly-owned subsidiary of BG Group plc (“BG”).

Lake Charles LNG is currently developing a natural gas liquefaction facility with BG for the export of LNG. In December 2015, Lake Charles LNG received authorization from the FERC to site, construct, and operate facilities for the liquefaction and export of natural gas. On February 15, 2016, Royal Dutch Shell plc completed its acquisition of BG. Shell announced in the second quarter of 2016 that they will delay making a final investment decision (“FID”) for the Lake Charles LNG project and Shell has not advised LCL of any change in the status of the project. In the event that each of LCL and Shell elect to make an affirmative FID, construction of the project would be expected to commence promptly thereafter and first LNG exports would commence about four years later.

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Asset Overview

Investment in ETP

The descriptions below include summaries of significant assets within ETP’s operations. Amounts, such as capacities, volumes and miles included in the descriptions below are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.

The following details the assets in ETP’s operations:

Intrastate Transportation and Storage

The following details pipelines and storage facilities in ETP’s intrastate transportation and storage operations:

Description of Assets	Ownership Interest (%)		Miles of Natural Gas Pipeline	Pipeline Throughput Capacity (Bcf/d)	Working Storage Capacity (Bcf/d)
ET Fuel System	100	%	2,780	5.2	11.2
Oasis Pipeline	100	%	750	2.3	—
HPL System	100	%	3,920	5.3	52.5
East Texas Pipeline	100	%	460	2.4	—
RIGS Haynesville Partnership Co.	49.99	%	450	2.1	—
Comanche Trail Pipeline	16	%	195	1.1	—
Trans-Pecos Pipeline	16	%	143	1.4	—

The following information describes ETP’s principal intrastate transportation and storage assets:

• The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.

The ET Fuel System also includes the Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and the Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.

In addition, the ET Fuel System is integrated with ETP’s Godley processing plant which gives ETP the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.

• The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.

The Oasis pipeline is integrated with ETP’s Southeast Texas System and is an important component to maximizing its Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing ETP to bypass its processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.

• The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas

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in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing ETP to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, as well as ETP’s Bammel storage facility.

The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to provide a physical backup for on-system and off-system customers. As of December 31, 2017, ETP had approximately 10.8 Bcf committed under fee-based arrangements with third parties and approximately 36.9 Bcf stored in the facility for ETP’s own account.

• The East Texas Pipeline connects three treating facilities, one of which ETP owns, with its Southeast Texas System. The East Texas pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansions include the 36-inch East Texas extension to connect ETP’s Reed compressor station in Freestone County to its Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting ETP’s Cleburne to Carthage pipeline to the HPL System.

• RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. The Partnership owns a 49.99% general partner interest in RIGS.

• Comanche Trail is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.

• Trans-Pecos is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.

Interstate Transportation and Storage

The following information describes ETP’s principal interstate transportation and storage assets:

Description of Assets	Ownership Interest (%)		Miles of Natural Gas Pipeline	Pipeline Throughput Capacity (Bcf/d)	Working Gas Capacity (Bcf/d)
Florida Gas Transmission Pipeline	50	%	5,360	3.1	—
Transwestern Pipeline	100	%	2,570	2.1	—
Panhandle Eastern Pipe Line	100	%	5,980	2.8	83.9
Trunkline Gas Pipeline	100	%	2,220	0.9	13.0
Tiger Pipeline	100	%	195	2.4	—
Fayetteville Express Pipeline	50	%	185	2.0	—
Sea Robin Pipeline	100	%	830	2.0	—
Rover Pipeline	32.6	%	713	3.25	—
Midcontinent Express Pipeline	50	%	500	1.8	—
Gulf States	100	%	10	0.1	—

• The Florida Gas Transmission Pipeline (“FGT”) is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,360 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 66% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains over 81 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrials and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture between ETP and KMI.

• The Transwestern Pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of West Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern Pipeline has bi-directional capabilities and access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwestern New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandles. Natural

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gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s Phoenix Lateral Pipeline, with a throughput capacity of 660 MMcf/d, connects the Phoenix area to the Transwestern mainline. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.

• The Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan.

• The Trunkline Gas Pipeline’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.

• The Tiger Pipeline is an approximately 195-mile interstate natural gas pipeline with bi-directional capabilities, that connects to ETP’s dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.

• The Fayetteville Express Pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.

• The Sea Robin Pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico.

• The Rover Pipeline is a new713-mile natural gas pipeline designed to transport3.25Bcf/d of domestically produced natural gas from the Marcellus and Utica Shale production areas to markets across the United States as well as into the Union Gas Dawn Storage Hub in Ontario, Canada, for redistribution back into the United States or into the Canadian market.

• The Midcontinent Express Pipeline is an approximately 500-mile interstate pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline System in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI.

• Gulf States owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

Midstream

The following details ETP’s assets in its midstream operations:

Description of Assets	Net Gas Processing Capacity (MMcf/d)	Net Gas Treating Capacity (MMcf/d)
South Texas Region:
Southeast Texas System	410	510
Eagle Ford System	1,920	1,808
Ark-La-Tex Region	1,025	1,186
North Central Texas Region	715	212
Permian Region	1,943	1,580
Mid-Continent Region	885	20
Eastern Region	—	70

The following information describes ETP’s principal midstream assets:

South Texas Region:

• The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the East Texas Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plant (La Grange and Alamo) with aggregate capacity of 410 MMcf/d and natural gas treating facilities with aggregate capacity of 510 MMcf/d. The La Grange and Alamo processing plants are natural gas processing plants that process

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the rich gas that flows through ETP’s gathering system to produce residue gas and NGLs. Residue gas is delivered into its intrastate pipelines and NGLs are delivered into ETP’s NGL pipelines to Lone Star.

ETP’s treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into ETP’s system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.

• The Eagle Ford Gathering System consists of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both ETP’s King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of 1,920 MMcf/d and multiple natural gas treating facilities with combined capacity of 1,808 MMcf/d. ETP’s Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to its intrastate transportation pipeline systems for deliveries of residue gas and are also connected with ETP’s NGL pipelines for delivery of NGLs to Lone Star.

Ark-La-Tex Region:

• ETP’s Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including ETP’s Tiger Pipeline. ETP’s Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1,186 MMcf/d.

• ETP’s PennTex Midstream System is primarily located in Lincoln Parish, Louisiana, and consists of the Lincoln Parish plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Arcadia, Louisiana, the Mt. Olive plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Ruston, Louisiana, with on-site liquids handling facilities for inlet gas; a 35-mile rich gas gathering system that provides producers with access to ETP’s processing plants and third-party processing capacity; a 15-mile residue gas pipeline that provides market access for natural gas from ETP’s processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region; and a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from ETP’s processing plants.

• The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, and an interstate NGL pipeline. Collectively, the eight natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada and Brookeland) have an aggregate capacity of 1,025 MMcf/d.

• Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, ETP offers producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.

North Central Texas Region:

• The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. ETP’s North Central Texas assets include its Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of 715 MMcf/d and aggregate treating capacity of 212 MMcf/d. The Godley plant is integrated with the ET Fuel System.

Permian Region:

• The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of ETP’s system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that ETP gathers and processes, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes ten processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther and Rebel) with an aggregate processing capacity of 1,618 MMcf/d, treating capacity of 1,580 MMcf/d, and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.

• ETP owns a 50% membership interest in Mi Vida JV, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. ETP operates the plant and related facilities on behalf of Mi Vida JV.

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• ETP owns a 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.

Mid-Continent Region:

• The Mid-Continent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. ETP’s Mid-Continent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Mid-Continent Systems include fourteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray and Gray) with an aggregate capacity of 885 MMcf/d and one natural gas treating facility with aggregate capacity of 20 MMcf/d.

• ETP operates its Mid-Continent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.

• ETP also owns the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.

Eastern Region:

• The Eastern Region assets are located in nine counties in Pennsylvania, three counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. ETP’s Eastern Region assets include approximately 500 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems. The fresh water pipeline system and Ohio gathering assets are held by jointly-owned entities.

• ETP also owns a 51% membership interest in Aqua – PVR, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.

• ETP and Traverse ORS LLC, a subsidiary of Traverse Midstream Partners LLC, own a 75% and 25% membership interest, respectively, in the ORS joint venture. On behalf of ORS, ETP operates ORS’s Ohio Utica River System (the “ORS System”), which consists of 47 miles of 36-inch and 13 miles of 30-inch gathering trunklines that delivers up to 2.1 Bcf/d to Rockies Express Pipeline (“REX”), Texas Eastern Transmission, and others.

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NGL and Refined Products Transportation and Services

The following details the assets in ETP’s NGL and refined products transportation and services operations:

Description of Assets	Miles of Liquids Pipeline (2)	Pipeline Throughput Capacity (MBbls/d)	NGL Fractionation / Processing Capacity (MBbls/d)	Working Storage Capacity (MBbls)
Liquids Pipelines:
Lone Star Express	535	507	—	—
West Texas Gateway Pipeline	512	240	—	—
Lone Star	1,617	120	—	—
Mariner East	300	70
Mariner South	67	200
Mariner West	395	50
Other NGL Pipelines	645	591	—	—
Liquids Fractionation and Services Facilities:
Mont Belvieu Facilities	163	42	520	50,000
Sea Robin Processing Plant1	—	—	26	—
Refinery Services1	103	—	25	—
Hattiesburg Storage Facilities	—	—	—	3,000
NGLs Terminals:
Nederland	—	—	—	1,000
Marcus Hook Industrial Complex	—	—	90	5,000
Inkster	—	—	—	1,000
Refined Products Pipelines	2,200	800	—	—
Refined Products Terminals:
Eagle Point	—	—	—	6,000
Marcus Hook Industrial Complex	—	—	—	1,000
Marcus Hook Tank Farm	—	—	—	2,000
Marketing Terminals	—	—	—	8,000

⁽¹⁾  Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of 850 MMcf/d and 54 MMcf/d, respectively.

⁽²⁾  Miles of pipeline as reported to PHMSA.

The following information describes ETP’s principal NGL and refined products transportation and services assets:

• The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.

• The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.

• The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including ETP’s Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, will expand the total takeaway capacity to 345 MBbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the second quarter of 2018.

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• The Mariner South pipeline is part of a joint project with Lone Star to deliver export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to ETP’s marine terminal in Nederland, Texas.

• The Mariner West pipeline provides transportation of ethane from the Marcellus shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarter of 2013, with capacity to transport approximately 50 MBbls/d.

• Refined products pipelines include approximately 2,200 miles of refined products pipelines in several regions of the United States. The pipelines primarily provide transportation in the northeast, midwest, and southwest United States markets. These operations include ETP’s controlling financial interest in Inland Corporation (“Inland”). The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term. The products transported in these pipelines include multiple grades of gasoline, and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.

• Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375 MBbls/d, the 45-mile Freedom pipeline with a capacity of 56 MBbls/d, the 20-mile Spirit pipeline with a capacity of 20 MBbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140 MBbls/d.

• ETP’s Mont Belvieu storage facility is an integrated liquids storage facility with over 50 million Bbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined product pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.

• ETP’s Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator V is currently under construction and is scheduled to be operational by the third quarter of 2018.

• Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.

• Refinery Services consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana.  The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components.  The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 103 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.

• The Hattiesburg storage facility is an integrated liquids storage facility with approximately 3 million Bbls of salt dome capacity, providing 100% fee-based cash flows.

• The Nederland terminal, in addition to crude oil activities, also provides approximately 1 million Bbls of storage and distribution services for NGLs in connection with the Mariner South pipeline, which provides transportation of propane and butane products from the Mont Belvieu region to the Nederland terminal, where such products can be exported via ship.

• The Marcus Hook Industrial Complex includes fractionation, terminalling and storage assets, with a capacity of approximately 2 million Bbls of NGL storage capacity in underground caverns, 3 million Bbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 million Bbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLs storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for the Mariner East 1 pipeline, and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.

• The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million Bbls of NGLs. ETP uses the Inkster terminal's storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.

• ETP has approximately 40 refined products terminals with an aggregate storage capacity of approximately 8 million Bbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.

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• In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 6 million Bbls, and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.

• The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million Bbls of refined products storage. The tank farm historically served Sunoco Inc.’s Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.’s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on ETP’s refined products pipelines.

• The Eastern refined products pipelines consists of approximately 470 miles of 6-inch to 24-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, approximately 162 miles of 8-inch refined products pipeline in western New York and approximately 182 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).

• The Mid-Continent refined products pipelines primarily consists of approximately 212 miles of 3-inch to 12-inch refined products pipelines in Ohio, approximately 85 miles of 6-inch to 12-inch refined products pipeline in Western Pennsylvania and approximately 52 miles of 8-inch refined products pipeline in Michigan.

• The Southwest refined products pipelines is located in Eastern Texas and consists primarily of approximately 300 miles of 8-inch diameter refined products pipeline.

• The Inland refined products pipeline, approximately 350 miles of pipeline in Ohio, consists of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 205 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 53 miles of 8-inch diameter refined products pipeline in western Ohio and the remaining refined products pipeline primarily consists of 5-inch diameter pipeline in Northeast Ohio.

Crude Oil Transportation and Services

The following details ETP’s pipelines and terminals in its crude oil transportation and services operations:

Description of Assets	Miles of Crude Pipeline (1)	Working Storage Capacity (MBbls)
Dakota Access Pipeline	1,172	—
Energy Transfer Crude Oil Pipeline	743	—
Bayou Bridge Pipeline	49	—
Permian Express Pipelines	1,712	—
Other Crude Oil Pipelines	5,682	—
Nederland Terminal	—	26,000
Fort Mifflin Terminal	—	570
Eagle Point Terminal	—	1,000
Midland Terminal	—	2,000
Marcus Hook Industrial Complex	—	1,000
Patoka, Illinois Terminal	—	2,000

⁽¹⁾  Miles of pipeline as reported to PHMSA.

ETP’s crude oil operations consist of an integrated set of pipeline, terminalling, and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details ETP’s assets in its crude oil transportation and services operations:

Crude Oil Pipelines

ETP’s crude oil pipelines consist of approximately 9,358 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States, including ETP’s wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC (“PET”), and Mid-Valley Pipeline Company (“Mid-Valley”). Additionally, ETP has equity ownership interests in two crude oil pipelines.

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ETP’s crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. ETP’s crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.

• Bakken Pipeline. Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915 mile pipeline with an initial capacity of 470 MBbls/d, expandable to 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including ETP’s crude terminal in Nederland Texas.

The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.

Dakota Access went into service on June 1, 2017 and consists of approximately 1,172 miles of 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the ETCO Pipeline for delivery to the Gulf Coast, or can be transported via other pipelines to refining markets throughout the Midwest.

ETCO went into service on June 1, 2017 and consists of more than 743 miles consisting of 678 miles of mostly 30-inch converted natural gas pipeline and 65 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.

• Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETP and Phillips 66, in which ETP has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which will consist of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, is expected to be completed in the second half of 2018.

When completed the Bayou Bridge Pipeline will have a capacity expandable to approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.

• Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Pegasus pipelines contributed to this joint venture by ExxonMobil. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, which origins in multiple locations in Western Texas.

• Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.

In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies its Marathon Petroleum Corporation’s refinery in Detroit, Michigan.

We also own and operate crude oil pipeline and gathering systems in Oklahoma. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. We are one of the largest purchasers of crude oil from producers in the state, and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.

Crude Oil Terminals

• Nederland. The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 26 million Bbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.

The Nederland terminal can receive crude oil at four of its five ship docks and four barge berths. The four ship docks are capable of receiving over 2 million Bbls/d of crude oil. In addition to ETP’s crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United

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States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 million Bbls.

The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has two ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million Bbls/d of crude oil to ETP’s crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.

• Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin terminal complex by charging fees based on throughput.

The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.

The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the other of which can accommodate some smaller crude oil vessels.

The Darby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery, which is operated by PES under a joint venture with Sunoco, Inc. This facility has a total storage capacity of approximately 3 million Bbls. Darby Creek receives crude oil from the Fort Mifflin terminal and Hog Island wharf via ETP’s pipelines. The tank farm then stores the crude oil and transports it to the PES refinery via ETP’s pipelines.

• Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1 million Bbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.

• Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million Bbls of crude oil storage, a combined 14 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.

• Marcus Hook Industrial Complex. The Marcus Hook Industrial Complex can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 million Bbls.

• Patoka, Illinois Terminal. The Patoka, Illinois terminal is a tank farm and was contributed by ExxonMobil to the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 2 million Bbls of crude oil storage.

Crude Oil Acquisition and Marketing

ETP’s crude oil acquisition and marketing operations are conducted using ETP’s assets, which include approximately 370 crude oil transport trucks and approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets.

All Other

Equity Method Investments

• Sunoco LP. ETP has an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, ETP’s investment consisted of 43.5 millionunits, representing43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, ETP’s investment consists of 26.2 millionunits, representing31.8%of Sunoco LP’s total outstanding common units.

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• PES. ETP has a non-controlling interest in PES, comprising33% of PES’ outstanding common units. As discussed in “ETP’s Other Operations and Investments” above, PES Holdings and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018.

Contract Services Operations

ETP owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. ETP’s contract treating services are primarily located in Texas, Louisiana and Arkansas.

Compression

ETP owns all of the outstanding equity interests of CDM, which operates a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas. As discussed in “Strategic Transactions,” in January 2018, ETP entered into an agreement to contribute CDM to USAC.

ETP owns 100% of the membership interests of ETG, which owns all of the partnership interests of ETT. ETT provides compression services to customers engaged in the transportation of natural gas, including ETP’s other operations.

Natural Resources Operations

ETP’s Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. ETP also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2017, ETP owned or controlled approximately 766 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.

Liquefaction Project

LCL, an entity whose parent is owned60%by ETE and40%by ETP, is in the process of developing a liquefaction project at the site of ETE’s existing regasification facility in Lake Charles, Louisiana. The project development agreement previously entered into in September 2013 with BG Group plc (now "Shell") related to this project expired in February 2017.On June 28, 2017, LCL signed a memorandum of understanding with Korea Gas Corporation and Shell to study the feasibility of a joint development of the Lake Charles liquefaction project. The project would utilize existing dock and storage facilities owned by ETE located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia).  Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.

The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of exporting and importing LNG. Shell is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project would be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.

The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL. In March 2013, LCL obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”). The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively.

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ETP has received its wetlands permits from the United States Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.

Investment in Sunoco LP

The following details the assets of Sunoco LP:

Wholesale Subsidiaries

• Sunoco LLC, a Delaware limited liability company, primarily distributes motor fuel across 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama and the Greater Dallas, Texas metroplex.

• Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands.

Retail Subsidiaries

• Susser Petroleum Property Company LLC, a Delaware limited liability company, primarily owns and leases convenience store properties.

• Susser, a Delaware corporation, sells motor fuel and merchandise in Texas, New Mexico, and Oklahoma through Stripes-branded convenience stores.

• Sunoco Retail, a Pennsylvania limited liability company, owns and operates convenience stores that sell motor fuel and merchandise primarily in Pennsylvania, New York, and Florida.

• MACS Retail LLC, a Virginia limited liability company, owns and operates convenience stores in Virginia, Maryland, and Tennessee.

• Aloha Petroleum, Ltd., a Hawaii corporation, owns and operates convenience stores on the Hawaiian Islands.

As of December 31, 2017, prior to the closing of the amended and restated purchasing agreement with 7-Eleven, Sunoco LP’s retail segment operated approximately1,348convenience stores and retail fuel outlets. Sunoco LP’s retail convenience stores operates under several brands, including its proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. Sunoco LP has company operated sites in more than 20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.

As of December 31, 2017, Sunoco LP operated approximately 746 Stripes convenience stores in Texas, New Mexico, Oklahoma and Louisiana. Each store offers a customized merchandise mix based on local customer demand and preferences. Sunoco LP built approximately 265 large-format convenience stores from January 2000 through December 31, 2017. Sunoco LP has implemented its proprietary, in-house Laredo Taco Company restaurant concept in approximately 477 Stripes convenience stores. Sunoco LP also owns and operates ATM and proprietary money order systems in most Stripes stores and provides other services such as lottery, prepaid telephone cards, wireless services and car washes.

As of December 31, 2017, Sunoco LP operated approximately 441 retail convenience stores and fuel outlets, primarily under its proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 404 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise, as well as motor fuel and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.

As of December 31, 2017, Sunoco LP operated approximately 161 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2017, MACS operated approximately 107 retail convenience stores and Aloha operated approximately 54 Aloha, Shell, and Mahalo branded fuel stations.

Investment in Lake Charles LNG

Regasification Facility

Lake Charles LNG, a wholly-owned subsidiary of ETE, owns a LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/day.

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Liquefaction Project

LCL, an entity owned 60% by ETE and 40% by ETP, is in the process of developing the liquefaction project in conjunction with BG pursuant to a project development agreement entered into in September 2013 and scheduled to expire at the end of February 2017, subject to the parties’ right to mutually extend the term. Pursuant to this agreement, each of LCL and BG are obligated to pay 50% of the development expenses for the liquefaction project, subject to reimbursement by the other party if such party withdraws from the project prior to both parties making an affirmative FID to become irrevocably obligated to fully develop the project, subject to certain exceptions. The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility will become a bi-directional facility capable of exporting and importing LNG. BG is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project is expected to be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.

The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of exporting and importing LNG. Shell is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project would be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.

The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL. In March 2013, LCL obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”).  In July 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”).  The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively. 

In addition, We have received our wetlands permits from the United States Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.

Competition

Natural Gas

The business of providing natural gas gathering, compression, treating, transporting, storing and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage operations are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.

We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.

In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

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NGL

In markets served by our NGL pipelines, we face competition with other pipeline companies, including those affiliated with major oil, petrochemical and natural gas companies, and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service. We face competition with other storage facilities based on fees charged and the ability to receive and distribute the customer’s products. We compete with a number of NGL fractionators in Texas and Louisiana. Competition for such services is primarily based on the fractionation fee charged.

Crude Oil and Products

In markets served by our products and crude oil pipelines, we face competition from other pipelines as well as rail and truck transportation. Generally, pipelines are the lowest cost method for long-haul, overland movement of products and crude oil. Therefore, the most significant competitors for large volume shipments in the areas served by our pipelines are other pipelines. In addition, pipeline operations face competition from rail and trucks that deliver products in a number of areas that our pipeline operations serve. While their costs may not be competitive for longer hauls or large volume shipments, rail and trucks compete effectively for incremental and marginal volume in many areas served by our pipelines.

With respect to competition from other pipelines, the primary competitive factors consist of transportation charges, access to crude oil supply and market demand. Competitive factors in crude oil purchasing and marketing include price and contract flexibility, quantity and quality of services, and accessibility to end markets.

Our refined product terminals compete with other independent terminals with respect to price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

Wholesale Fuel Distribution and Retail Marketing

In our wholesale fuel distribution business, we compete primarily with other independent motor fuel distributors. The markets for distribution of wholesale motor fuel and the large and growing convenience store industry are highly competitive and fragmented, which results in narrow margins. We have numerous competitors, some of which may have significantly greater resources and name recognition than we do. Significant competitive factors include the availability of major brands, customer service, price, range of services offered and quality of service, among others. We rely on our ability to provide value-added and reliable service and to control our operating costs in order to maintain our margins and competitive position.

In our retail business, we face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations of large integrated oil companies, independent gasoline service stations, convenience stores, fast food stores, supermarkets, drugstores, dollar stores, club stores and other similar retail outlets, some of which are well-recognized national or regional retail systems. The number of competitors varies depending on the geographical area. It also varies with gasoline and convenience store offerings. The principal competitive factors affecting our retail marketing operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of operation, store safety, customer loyalty and brand recognition. We compete by pricing gasoline competitively, combining our retail gasoline business with convenience stores that provide a wide variety of products, and using advertising and promotional campaigns.

Credit Risk and Customers

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

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

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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.

Natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. The discovery and development of new shale formations across the United States has created an abundance of natural gas and crude oil resulting in a negative impact on prices in recent years for natural gas and crude oil. As a result, some of our exploration and production customers have been adversely impacted; however, we are monitoring these customers and mitigating credit risk as necessary.

During the year ended December 31, 2017, none of our customers individually accounted for more than 10% of our consolidated revenues.

Regulation of Interstate Natural Gas Pipelines.The FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the Natural Gas Act (“NGA”), the FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage and other services. The Florida Gas Transmission, Transwestern, Panhandle Eastern, Trunkline Gas, Tiger, Fayetteville Express, Sea Robin, Gulf States and Midcontinent Express pipelines transport natural gas in interstate commerce and thus each qualifies as a “natural-gas company” under the NGA subject to the FERC’s regulatory jurisdiction. We also hold certain natural gas storage facilities that are subject to the FERC’s regulatory oversight under the NGA.

The FERC’s NGA authority includes the power to:

• approve the siting, construction and operation of new facilities;

• review and approve transportation rates;

• determine the types of services our regulated assets are permitted to perform;

• regulate the terms and conditions associated with these services;

• permit the extension or abandonment of services and facilities;

• require the maintenance of accounts and records; and

• authorize the acquisition and disposition of facilities.

Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The maximum rates to be charged by NGA-jurisdictional natural gas companies and their terms and conditions for service are required to be on file with the FERC. Most natural gas companies are authorized to offer discounts from their FERC-approved maximum just and reasonable rates when competition warrants such discounts. Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer a cost-based recourse rate available to a prospective shipper as an alternative to the negotiated rate. Natural gas companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory. Existing tariff rates may be challenged by complaint or on FERC’s own motion, and if found unjust and unreasonable, may be altered on a prospective basis from no earlier than the date of the complaint or initiation of a proceeding by the FERC. The FERC must also approve all rate changes. We cannot guarantee that the FERC will allow us to charge rates that fully recover our costs or continue to pursue its approach of pro-competitive policies.

For two of our NGA-jurisdictional natural gas companies, Tiger and Fayetteville Express, the large majority of capacity in those pipelines is subscribed for lengthy terms under FERC-approved negotiated rates.  However, as indicated above, cost-based recourse rates are also offered under their respective tariffs.

Pursuant to the FERC’s rules promulgated under the Energy Policy Act of 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of electric energy or natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction: (i) to defraud using any device, scheme or artifice; (ii) to make any untrue statement of material fact or omit a material fact; or (iii) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act (“CEA”). With regard to our physical purchases and sales of natural gas, NGLs or other energy commodities; our gathering or transportation of these energy commodities; and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability

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to assess or seek civil penalties of up to approximately $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Failure to comply with the NGA, the Energy Policy Act of 2005, the CEA and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.

Regulation of Intrastate Natural Gas and NGL Pipelines.  Intrastate transportation of natural gas and NGLs is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates and terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”). The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates and terms and conditions of some transportation and storage services provided on the Oasis pipeline, HPL System, East Texas pipeline, ET Fuel System, Trans-Pecos and Comanche Trail are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.

Our intrastate natural gas operations are also subject to regulation by various agencies in Texas, principally the TRRC. Our intrastate pipeline and storage operations in Texas are also subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or TRRC complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.

Our NGL pipelines and operations may also be or become subject to state public utility or related jurisdiction which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL gathering facilities. In addition, the rates, terms and conditions for shipments of NGLs on our pipelines are subject to regulation by FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (the “EPAct of 1992”) if the NGLs are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all NGLs shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

Regulation of Sales of Natural Gas and NGLs.The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to federal or state regulation.

To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to the use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.

Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those operations of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action in a manner that is materially different from other natural gas marketers with whom we compete.

Regulation of Gathering Pipelines.  Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines in Texas, Louisiana and West Virginia that we believe meet the traditional tests the FERC uses to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject

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of substantial litigation and varying interpretations, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by the FERC, the courts and Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.

In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.

Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, our Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering system.

We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Regulation of Interstate Crude Oil, NGL and Products Pipelines. Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the ICA, the EPAct of 1992, and related rules and orders. The ICA requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. This statute also permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically not suspended for the maximum allowable period. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the rate was in effect. 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 FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariff rates charged by us ultimately will be upheld if challenged, management believes that the tariff rates now in effect for our pipelines are within the maximum rates allowed under current FERC policies and precedents.

For many locations served by our product and crude pipelines, we are able to establish negotiated rates.  Otherwise, we are permitted to charge cost-based rates, or in many cases, grandfathered rates based on historical charges or settlements with our customers. To the extent we rely on cost-of-service ratemaking to establish or support our rates, the issue of the proper allowance for federal and state income taxes could arise. In 2005, FERC issued a policy statement stating that it would permit common carriers, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. Whether a pipeline’s owners have such actual or potential income tax liability is subject to review by FERC on a case-by-case basis. Although this policy is generally favorable for common carriers that are organized as pass-through entities, it still entails rate risk due to the FERC’s case-by-case review approach. The application of this policy, as well as any decision by

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FERC regarding our cost of service, may also be subject to review in the courts. In December 2016, FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs. FERC requested comments regarding how to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The comment period with respect to the notice of inquiry ended on April 7, 2017. The outcome of the inquiry is still pending.

Finally, in November 2017 FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline.  In particular, FERC’s November 2017 order prohibits  buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service  is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss.  Several parties have requested that FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order.  We are unable to predict how FERC will respond to such requests.  Depending on how FERC responds, it could have an impact on the rates we are permitted to charge.

EPAct 1992 required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted 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 for Finished Goods, or PPIFG. FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2011 and ending June 30, 2016, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPIFG plus 2.65%. Beginning July 1, 2016, the indexing method provided for annual changes equal to the change in PPIFG plus 1.23%. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) 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% for the prior 2 years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) 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 on March 17, 2017. FERC has taken no further action on the proposed rule to date.

Finally, in November 2017 FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline.  In particular, FERC’s November 2017 order prohibits  buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service  is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss.  Several parties have requested that FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order.  We are unable to predict how FERC will respond to such requests.  Depending on how FERC responds, it could have an impact on the rates we are permitted to charge.

Regulation of Intrastate Crude Oil, NGL and Products Pipelines. Some of our crude oil, NGL and products pipelines are subject to regulation by the TRRC, the PA PUC, and the Oklahoma Corporation Commission. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.

In addition, as noted above, the rates, terms and conditions for shipments of crude oil, NGLs or products on our pipelines could be subject to regulation by FERC under the ICA and the EPAct of 1992 if the crude oil, NGLs or products are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, NGLs or products shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

Regulation of Pipeline Safety.Our pipeline operations are subject to regulation by the DOT, through the PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA,

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as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Failure to comply with the pipeline safety laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays in permitting or the performance of projects, or the issuance of injunctions limiting or prohibiting some or all of our operations in the affected area.

The HLPSA and NGPSA have been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”). The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1 million to $2 million for a related series of violations, but provided that these maximum penalty caps do not apply to certain civil enforcement actions. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $209,002 per day, with a maximum of $2,090,022 for a series of violations. The 2016 Pipeline Safety Act extended PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or natural gas pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.

In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which we conduct operations typically have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines. Under such state regulatory programs, states have the authority to conduct pipeline inspections, to investigate accidents and to oversee compliance and enforcement, safety programs and record maintenance and reporting. Congress, PHMSA and individual states may pass or implement additional safety requirements that could result in increased compliance costs for us and other companies in our industry. For example, federal construction, maintenance and inspection standards under the NGPSA that apply to pipelines in relatively populated areas may not apply to gathering lines running through rural regions. This “rural gathering exemption” under the NGPSA presently exempts substantial portions of our gathering facilities located outside of cities, towns or any area designated as residential or commercial from jurisdiction under the NGPSA, but does not apply to our intrastate natural gas pipelines. In recent years, the PHMSA has considered changes to this rural gathering exemption, including publishing an advance notice of proposed rulemaking relating to gas pipelines in 2011, in which the agency sought public comment on possible changes to the definition of “high consequence areas” and “gathering lines” and the strengthening of pipeline integrity management requirements. In April 2016, pursuant to one of the requirements of the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that, among other things, would expand certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; require natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and require certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines. PHMSA has not yet finalized the March 2016 proposed rulemaking.

In January 2017, PHMSA issued a final rule amending federal safety standards for hazardous liquid pipelines. The final rule is the latest step in a lengthy rulemaking process that began in 2010 with a request for comments and continued with publication of a rulemaking proposal in October 2015. The general effective date of this final rule is six months from publication in the Federal Register, but it is currently subject to further administrative review in connection with the transition of Presidential administrations and thus, implementation of this final rule remains uncertain. The final rule addresses several areas including reporting requirements for gravity and unregulated gathering lines, inspections after weather or climatic events, leak detection system requirements, revisions to repair criteria and other integrity management revisions. In addition, PHMSA issued regulations on January 23, 2017, on operator qualification, cost recovery, accident and incident notification and other pipeline safety changes that are now effective. These regulations are also subject, however, to potential further review in connection with the transition of Presidential

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administrations. Historically, our pipeline safety costs have not had a material adverse effect on our business or results of operations but there is no assurance that such costs will not be material in the future, whether due to elimination of the rural gathering exemption or otherwise due to changes in pipeline safety laws and regulations.

In another example of how future legal requirements could result in increased compliance costs, notwithstanding the applicability of the federal OSHA’s Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Planning (“RMP”) requirements at regulated facilities, PHMSA and one or more state regulators, including the Texas Railroad Commission, have in recent years, expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. To the extent that these actions are pursued by PHMSA, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.

Environmental Matters

General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering, processing, storage and transmission of natural gas and the storage and transportation of NGLs, crude oil and refined products is subject to stringent federal, tribal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and criminal sanctions, third-party claims for personal injury or property damage, capital expenditures to retrofit or upgrade our facilities and programs, or curtailment or cancellation of permits on operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of planning, permitting, constructing and operating our plants, pipelines and other facilities. As a result of these laws and regulations, our construction and operation costs include capital, operating and maintenance cost items necessary to maintain or upgrade our equipment and facilities.

We have implemented procedures designed to ensure that governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. Historically, our environmental compliance costs have not had a material adverse effect on our business, results of operations or financial condition; however, there can be no assurance that such costs will not be material in the future. For example, we cannot be certain, however, that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent environmental laws and regulations or unanticipated events will not arise in the future and give rise to environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.

Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be subject to strict, joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition or that may be subject to other waste disposal laws and regulations. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed.

We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, as amended, (“RCRA”) and comparable state statutes. We are not currently required to comply with a substantial

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portion of the RCRA hazardous waste requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent non-hazardous management standards. From time to time, the EPA has considered or third parties have petitioned the agency on the adoption of stricter handling, storage and disposal standards for nonhazardous wastes, including certain wastes associated with the exploration, development and production of crude oil and natural gas. For example, following the filing of a lawsuit by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the United States District Court for the District of Columbia on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes such as these examples in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense and, in the case of our oil and natural gas exploration and production customers, could result in increased operating costs for those customers and a corresponding decrease in demand for our processing, transportation and storage services.

We currently own or lease sites that have been used over the years by prior owners and lessees and by us for various activities related to gathering, processing, storage and transmission of natural gas, NGLs, crude oil and products. Waste disposal practices within the oil and gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or otherwise released on or under various sites during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these releases may have occurred during the ownership or operation of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.

As of December 31, 2017 and 2016, accruals of $372 million and $344 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover estimated material environmental liabilities including, for example, certain matters assumed in connection with our acquisition of the HPL System, our acquisition of Transwestern, potential environmental liabilities for three sites that were formerly owned by Titan Energy Partners, L.P. or its predecessors, and the predecessor owner’s share of certain environmental liabilities of ETC OLP.

The Partnership is subject to extensive and frequently changing federal, tribal, state and local laws and regulations, including those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and composition of fuels. These laws and regulations require environmental assessment and remediation efforts at many of Sunoco, Inc.’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $284 million and $289 million at December 31, 2017 and 2016, respectively, which is included in the total accruals above. These legacy sites that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that are no longer operated by Sunoco, Inc., closed and/or sold refineries and other formerly owned sites. In December 2013, a wholly-owned captive insurance company was established for these legacy 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. As of December 31, 2017 the captive insurance company held $207 million of cash and investments.

The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.

Under various environmental laws, including the RCRA, the Partnership has initiated corrective remedial action at certain of its facilities, formerly owned facilities and at certain third-party sites. At the Partnership’s major manufacturing facilities, we have typically assumed continued industrial use and a containment/remediation strategy focused on eliminating unacceptable risks to human health or the environment. The remediation accruals for these sites reflect that strategy. Accruals include amounts designed to prevent or mitigate off-site migration and to contain the impact on the facility property, as well as to address known, discrete

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areas requiring remediation within the plants. Remedial activities include, for example, closure of RCRA waste management units, recovery of hydrocarbons, handling of impacted soil, mitigation of surface water impacts and prevention or mitigation of off-site migration. A change in this approach as a result of changing the intended use of a property or a sale to a third party could result in a comparatively higher cost remediation strategy in the future.

In general, a remediation site or issue is typically evaluated on an individual basis based upon information available for the site or issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (for example, service station sites) in determining the amount of probable loss accrual to be recorded. The estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance allows us the minimum amount of the range to accrue. Accordingly, the low end of the range often represents the amount of loss which has been recorded.

In addition to the probable and estimable losses which have been recorded, management believes it is reasonably possible (that is, it is less than probable but greater than remote) that additional environmental remediation losses will be incurred. At December 31, 2017, the aggregate of such additional estimated maximum reasonably possible losses, which relate to numerous individual sites, totaled approximately $5 million, which amount is in excess of the $372 million in environmental accruals recorded on December 31, 2017. This estimate of reasonably possible losses comprises estimates for remediation activities at current logistics and retail assets, and in many cases, reflects the upper end of the loss ranges which are described above. Such estimates include potentially higher contractor costs for expected remediation activities, the potential need to use more costly or comprehensive remediation methods and longer operating and monitoring periods, among other things.

In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years, but management can provide no assurance that it would be over many years. If changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could materially and adversely impact multiple facilities, formerly owned facilities and third-party sites at the same time.  As a result, from time to time, significant charges against income for environmental remediation may occur. And while management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position, it can provide no assurance.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by PCBs, and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is $5 million, which is included in the total environmental accruals mentioned above. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. Such future costs are not expected to have a material impact on our financial position, results of operations or cash flows, but management can provide no assurance.

Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. We will incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities. Historically, our costs for compliance with existing Clean Air Act and comparable state law requirements have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. The EPA and state agencies are often considering, proposing or finalizing new regulations that could impact our existing operations and the costs and timing of new infrastructure development. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering

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the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the United States counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for the remaining areas of the United States not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.

Clean Water Act. The Federal Water Pollution Control Act of 1972, as amended, (“Clean Water Act”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the United States. Pursuant to the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In May 2015, the EPA issued a final rule that attempts to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the United States Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. In June 2015, the EPA and the United States Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States, but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the United States Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested May 2015 rule would not take effect until two years after the November 2017 proposed rule was finalized and published in the Federal Register. Recently, on January 22, 2018, the United States Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. On January 31, 2018, the EPA and Corps finalized a rule that would delay applicability of the rule to two years from the rule’s publication in the Federal Register. As a result of these recent developments, future implementation of the June 2015 rule is uncertain at this time but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, our operations as well as our exploration and production customers’ drilling programs could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

Spills. Our operations can result in the discharge of regulated substances, including NGLs, crude oil or other products. The Clean Water Act, as amended by the federal Oil Pollution Act of 1990, as amended, (“OPA”), and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States. The Clean Water Act and comparable state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges. The OPA subjects owners of covered facilities to strict joint and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release of oil. The PHMSA, the EPA, or various state regulatory agencies, has approved our oil spill emergency response plans that are to be used in the event of a spill incident.

In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our results of operations, financial position or expected cash flows.

Endangered Species Act. The Endangered Species Act, as amended, restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may operate in areas that are currently designated as a habitat for endangered or threatened species or where the discovery of previously unidentified endangered species, or the designation of additional species as endangered or threatened may occur in which event such one or more developments could cause us to incur additional costs, to develop habitat conservation plans, to become subject to expansion or operating restrictions, or bans in the affected areas. Moreover, such designation of previously unprotected species as threatened or endangered in areas where our oil and natural gas exploration and production customers operate could cause our

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customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.

Climate Change. Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, the Subpart OOOOa standards have been subject to attempts by the EPA to stay portions of those standards, and the agency proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. This rule, should it remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the United States State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is

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difficult to predict how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Employee Health and Safety. We are subject to the requirements of the federal OSHA and comparable state laws that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Historically, our costs for OSHA required activities, including general industry standards, recordkeeping 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.

Employees

As of December 31, 2017, ETE and its consolidated subsidiaries employed an aggregate of 29,486 employees, 1,544 of which are represented by labor unions. We and our subsidiaries believe that our relations with our employees are satisfactory.

SEC Reporting

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

We provide electronic access, free of charge, to our periodic and current reports, and amendments to these reports, on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.

ITEM 1A.  RISK FACTORS

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in our securities. ETP, Panhandle and Sunoco LP file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information. The risk factors set forth below, and those included in ETP’s, Panhandle’s and Sunoco LP’s Annual Reports, are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.

Risks Inherent in an Investment in Us

Cash distributions are not guaranteed and may fluctuate with our performance or other external factors.

The Parent company’s principal source of earnings and cash flow is cash distributions from ETP and Sunoco LP. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETP and Sunoco LP make to their partners. ETP and Sunoco LP may not be able to continue to make quarterly distributions at their current level or increase their quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETP or Sunoco LP increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP or Sunoco LP to us.

Our ability to distribute cash received from ETP and Sunoco LP to our Unitholders is limited by a number of factors, including:

• interest expense and principal payments on our indebtedness;

• restrictions on distributions contained in any current or future debt agreements;

• our general and administrative expenses;

• expenses of our subsidiaries other than ETP and Sunoco LP, including tax liabilities of our corporate subsidiaries, if any; and

• reserves our General Partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

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We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our Unitholders will depend on numerous factors, many of which are beyond our control or the control of our General Partner.

Our cash flow depends primarily on the cash distributions we receive from our partnership interests, including the incentive distribution rights, in ETP and Sunoco LP and, therefore, our cash flow is dependent upon the ability of ETP and Sunoco LP to make distributions in respect of those partnership interests.

We do not have any significant assets other than our partnership interests in ETP and Sunoco LP and our LNG business. As a result, our cash flow depends on the performance of ETP and Sunoco LP and their respective subsidiaries and ETP’s and Sunoco LP’s ability to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP and Sunoco LP.

The amount of cash that ETP and Sunoco LP can distribute to their partners, including us, each quarter depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter and will depend upon, among other things:

• the amount of natural gas, NGLs, crude oil and refined products transported through ETP’s pipelines and gathering systems;

• the level of throughput in processing and treating operations;

• the fees charged and the margins realized by ETP and Sunoco LP for their services;

• the price of natural gas, NGLs, crude oil and refined products;

• the relationship between natural gas, NGL and crude oil prices;

• the amount of cash distributions ETP receives with respect to the Sunoco LP common units that ETP or its subsidiaries own;

• the weather in their respective operating areas;

• the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;

• the level of their respective operating costs and maintenance and integrity capital expenditures;

• the tax profile on any blocker entities treated as corporations for federal income tax purposes that are owned by any of our subsidiaries;

• prevailing economic conditions; and

• the level and results of their respective derivative activities.

In addition, the actual amount of cash that ETP and Sunoco LP will have available for distribution will also depend on other factors, such as:

• the level of capital expenditures they make;

• the level of costs related to litigation and regulatory compliance matters;

• the cost of acquisitions, if any;

• the levels of any margin calls that result from changes in commodity prices;

• debt service requirements;

• fluctuations in working capital needs;

• their ability to borrow under their respective revolving credit facilities;

• their ability to access capital markets;

• restrictions on distributions contained in their respective debt agreements; and

• the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct of their respective businesses.

ETE does not have any control over many of these factors, including the level of cash reserves established by the board of directors and ETP’s General Partners. Accordingly, we cannot guarantee that ETP and Sunoco LP will have sufficient available cash to pay a specific level of cash distributions to its partners.

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Furthermore, Unitholders should be aware that the amount of cash that ETP and Sunoco LP have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, ETP and Sunoco LP may declare and/or pay cash distributions during periods when they record net losses. Please read “Risks Related to the Businesses of our Subsidiaries” included in this Item 1A for a discussion of further risks affecting ETP’s and Sunoco LP’s ability to generate distributable cash flow.

We may issue an unlimited number of limited partner interests or other classes of equity without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.

Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approval of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:

• our Unitholders’ current proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on each Common Unit or partnership security may decrease;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding Common Unit may be diminished; and

• the market price of our Common Units may decline.

In addition, ETP and Sunoco LP may sell an unlimited number of limited partner interests without the consent of the respective Unitholders, which will dilute existing interests of the respective Unitholders, including us. The issuance of additional Common Units or other equity securities by ETP or Sunoco LP will have essentially the same effects as detailed above.

ETP and Sunoco LP may issue additional Common Units, which may increase the risk that each Partnership will not have sufficient available cash to maintain or increase its per unit distribution level.

The partnership agreements of ETP and Sunoco LP allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by each respective partnership will have the following effects:

• Unitholders’ current proportionate ownership interest in each partnership will decrease;

• the amount of cash available for distribution on each common unit or partnership security may decrease;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding common unit may be diminished; and

• the market price of each partnership’s common units may decline.

The payment of distributions on any additional units issued by ETP and Sunoco LP may increase the risk that either partnership may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.

Unitholders have limited voting rights and are not entitled to elect the General Partner or its directors. In addition, even if Unitholders are dissatisfied, they cannot easily remove the General Partner.

Unlike the holders of common stock in a corporation, Unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our General Partner and will have no right to elect our General Partner or the officers or directors of our General Partner on an annual or other continuing basis.

Furthermore, if our Unitholders are dissatisfied with the performance of our General Partner, they may be unable to remove our General Partner. Our General Partner may not be removed except, among other things, upon the vote of the holders of at least 66 ²/3% of our outstanding units. As of December 31, 2017, our directors and executive officers directly or indirectly own approximately 27% of our outstanding Common Units. It will be particularly difficult for our General Partner to be removed without the consent of our directors and executive officers. As a result, the price at which our Common Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

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Furthermore, Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the General Partner and its affiliates, cannot be voted on any matter.

Our General Partner may, in its sole discretion, approve the issuance of partnership securities and specify the terms of such partnership securities.

Pursuant to our partnership agreement, our General Partner has the ability, in its sole discretion and without the approval of the Unitholders, to approve the issuance of securities by the Partnership at any time and to specify the terms and conditions of such securities. The securities authorized to be issued may be issued in one or more classes or series, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership securities), as shall be determined by our General Partner, including:

• the right to share in the Partnership’s profits and losses;

• the right to share in the Partnership’s distributions;

• the rights upon dissolution and liquidation of the Partnership;

• whether, and the terms upon which, the Partnership may redeem the securities;

• whether the securities will be issued, evidenced by certificates and assigned or transferred; and

• the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.

Please see “—We may issue an unlimited number of limited partner interests without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.” above.

The control of our General Partner may be transferred to a third party without Unitholder consent.

The General Partner may transfer its general partner interest to a third party without the consent of the Unitholders. Furthermore, the members of our General Partner may transfer all or part of their ownership interest in our General Partner to a third party without the consent of the Unitholders. Any new owner or owners of our General Partner or the general partner of the General Partner would be in a position to replace the directors and officers of our General Partner with its own choices and to control the decisions made and actions taken by the board of directors and officers.

We are dependent on third parties, including key personnel of ETP under a shared services agreement, to provide the financial, accounting, administrative and legal services necessary to operate our business.

We rely on the services of key personnel of ETP, including the ongoing involvement and continued leadership of Kelcy L. Warren, one of the founders of ETP’s midstream business. Mr. Warren has been integral to the success of ETP’s midstream and intrastate transportation and storage businesses because of his ability to identify and develop strategic business opportunities. Losing the leadership of Mr. Warren could make it difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s ability to increase the cash distributions paid on its partnership interests.

ETP’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.

Cost reimbursements due to our General Partner may be substantial and may reduce our ability to pay the distributions to our Unitholders.

Prior to making any distributions to our Unitholders, we will reimburse our General Partner for all expenses it has incurred on our behalf. In addition, our General Partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our General Partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to our Unitholders. Our General Partner has sole discretion to determine the amount of these expenses and fees.

In addition, under Delaware partnership law, our General Partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our General Partner.

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To the extent our General Partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our General Partner, our General Partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available for distribution to our Unitholders and cause the value of our Common Units to decline.

A reduction in ETP’s or Sunoco LP’s distributions will disproportionately affect the amount of cash distributions to which ETE is entitled.

ETE indirectly owns all of the IDRs of ETP and Sunoco LP. These IDRs entitle the holder to receive increasing percentages of total cash distributions made by each of ETP and Sunoco LP as such entity reaches established target cash distribution levels as specified in its partnership agreement. ETE currently receives its pro rata share of cash distributions from ETP and Sunoco LP based on the highest sharing level of 48% and 50% in respect of the ETP IDRs and Sunoco LP IDRs, respectively.

A decrease in the amount of distributions by ETP to ETE to less than $0.2638 per unit per quarter would reduce ETE’s percentage of the incremental cash distributions from ETP above $0.0958 per unit per quarter from 48% to 35%, and a decrease in the amount of distributions by Sunoco LP to ETE to less than $0.6563 per unit per quarter would reduce ETE’s percentage of the incremental cash distributions from Sunoco LP above $0.5469 per unit per quarter from 50% to 25%. As a result, any such reduction in quarterly cash distributions from the ETP or Sunoco LP would have the effect of disproportionately reducing the amount of all distributions that ETE and ETP receive, based on their ownership interest in the IDRs as compared to cash distributions they receive from their general partner interest and common units in such entity.

The consolidated debt level and debt agreements of ETP and Sunoco LP and those of their subsidiaries may limit the distributions we receive from ETP and Sunoco LP, as well as our future financial and operating flexibility.

ETP’s and Sunoco LP’s levels of indebtedness affect their operations in several ways, including, among other things:

• a significant portion of ETP’s and Sunoco LP’s and their subsidiaries’ cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions to us;

• covenants contained in ETP’s and Sunoco LP’s and their subsidiaries’ existing debt agreements require ETP, Sunoco LP and their subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;

• ETP’s and Sunoco LP’s and their subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;

• ETP and Sunoco LP may be at a competitive disadvantage relative to similar companies that have less debt;

• ETP and Sunoco LP may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels;

• failure by ETP, Sunoco LP or their subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact ETP’s and Sunoco LP’s ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions to us and their unitholders.

We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt or to repay debt at maturity.

Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our Available Cash (as defined in our partnership agreement) to our Unitholders of record and our General Partner. Available Cash is generally all of our cash on hand as of the end of a quarter, adjusted for cash distributions and net changes to reserves. Our General Partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries in amounts it determines in its reasonable discretion to be necessary or appropriate:

• to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);

• to provide funds for distributions to our Unitholders and our General Partner for any one or more of the next four calendar quarters; or

• to comply with applicable law or any of our loan or other agreements.

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A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.

A downgrade of our credit ratings might increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:

• economic downturns;

• deteriorating capital market conditions;

• declining market prices for crude oil, natural gas, NGLs and other commodities;

• terrorist attacks or threatened attacks on our facilities or those of other energy companies; and

• the overall health of the energy industry, including the bankruptcy or insolvency of other companies.

Our subsidiaries are not prohibited from competing with us.

Neither our partnership agreement nor the partnership agreements of our subsidiaries, including ETP and Sunoco LP, prohibit our subsidiaries from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.

Capital projects will require significant amounts of debt and equity financing, which may not be available to ETP on acceptable terms, or at all.

ETP plans to fund its growth capital expenditures, including any new future pipeline construction projects and improvements or repairs to existing facilities that ETP may undertake, with proceeds from sales of ETP’s debt and equity securities and borrowings under its revolving credit facility; however, ETP cannot be certain that it will be able to issue debt and equity securities on terms satisfactory to it, or at all. In addition, ETP may be unable to obtain adequate funding under its current revolving credit facility because ETP’s lending counterparties may be unwilling or unable to meet their funding obligations. If ETP is unable to finance its expansion projects as expected, ETP could be required to seek alternative financing, the terms of which may not be attractive to ETP, or to revise or cancel its expansion plans.

A significant increase in ETP’s indebtedness that is proportionately greater than ETP’s issuance of equity could negatively impact ETP’s credit ratings or its ability to remain in compliance with the financial covenants under its revolving credit agreement, which could have a material adverse effect on ETP’s financial condition, results of operations and cash flows.

Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.

In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates. Approximately $9.86 billion of our consolidated debt as of December 31, 2017 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates. We manage a portion of our interest rate exposures by utilizing interest rate swaps.

An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our Common Units. Any such reduction in demand for our Common Units resulting from other more attractive investment opportunities may cause the trading price of our Common Units to decline.

Unitholders may have liability to repay distributions.

Under certain circumstances, Unitholders may have to repay us amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law, will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.

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We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to pay distributions to our Unitholders and to service our debt depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. If we are unable to obtain funds from our subsidiaries we may not be able to pay distributions to our Unitholders or to pay interest or principal on our debt when due.

Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.

Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.

Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Our partnership agreement allows the general partner to incur obligations on our behalf that are expressly non-recourse to the general partner. The general partner has entered into such limited recourse obligations in most instances involving payment liability and intends to do so in the future.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Our debt level and debt agreements may limit our ability to make distributions to Unitholders and may limit our future financial and operating flexibility and may require asset sales.

As of December 31, 2017, we had approximately $6.70 billion of debt on a stand-alone basis and approximately $44.08 billion of consolidated debt, excluding the debt of our joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:

• a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;

• covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;

• our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;

• we may be at a competitive disadvantage relative to similar companies that have less debt;

• we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and

• failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.

In order for us to manage our debt levels, we may need to sell assets, issue additional equity securities, reduce the cash distributions we pay to our unitholders or a combination thereof. In the event that we sell assets, the future cash generating capacity of our remaining asset base may be diminished. In the event that we issue additional equity securities, we may need to issue these securities at a time when our common unit price is depressed and therefore we may not receive favorable prices for our common units or favorable prices or terms for other types of equity securities. In the event we reduce cash distributions on our common units, the public trading price of our common units could decline significantly.

Our General Partner has a limited call right that may require Unitholders to sell their units at an undesirable time or price.

If at any time our General Partner and its affiliates own more than 90% of our outstanding units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, Unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2017, the directors and executive officers of our General Partner owned approximately 27% of our Common Units.

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Litigation commenced by WMB against ETE and its affiliates could cause ETE to incur substantial costs, may present material distractions and, if decided adverse to ETE, could negatively impact ETE’s financial position and credit ratings.

WMB filed a complaint against ETE and its affiliates in the Delaware Court of Chancery, alleging that the defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates.  Following a ruling by the Court on June 24, 2016, which allowed for the subsequent termination of the merger agreement by ETE on June 29, 2016, WMB filed a notice of appeal to the Supreme Court of Delaware.  WMB filed an amended complaint on September 16, 2016 and seeks a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement. The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and seek a $1.48 billion termination fee under the Merger Agreement and additional damages caused by WMB’s misconduct. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that WMB breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, WMB filed a motion to dismiss the ETE Defendants’ amended counterclaims and to strike certain of the ETE Defendants’ affirmative defenses. Following briefing by the parties on WMB’s motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision.  On January 11, 2017, the parties held oral argument before the Delaware Supreme Court on WMB’s appeal of the June 24 ruling. The Delaware Supreme Court has taken the matter under advisement. These lawsuits could result in substantial costs to ETE, including litigation costs and settlement costs. ETE believes that the time required by the management of ETE and its counsel to defend against the allegations made by WMB in the litigation against ETE and its affiliates is likely to be substantial and the time required by the officers and employees of LE GP, assuming WMB actively pursues such litigation, is also likely to be substantial. The defense or settlement of any lawsuit or claim that remains unresolved may result in negative media attention, and may adversely affect ETE’s business, reputation, financial condition, results of operations, cash flows and market price.

Risks Related to Conflicts of Interest

Although we control ETP and Sunoco LP through our ownership of their general partners, ETP’s and Sunoco LP’s general partners owe fiduciary duties to ETP and ETP’s unitholders and Sunoco LP and Sunoco LP’s unitholders, respectively, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and ETP and Sunoco LP and their respective limited partners, on the other hand. The directors and officers of ETP’s and Sunoco LP’s General Partners have fiduciary duties to manage ETP and Sunoco LP, respectively, in a manner beneficial to us. At the same time, the General Partners have fiduciary duties to manage ETP and Sunoco LP in a manner beneficial to ETP and Sunoco LP and their respective limited partners. The boards of directors of ETP’s and Sunoco LP’s General Partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.

For example, conflicts of interest with ETP and Sunoco LP may arise in the following situations:

• the allocation of shared overhead expenses to ETP, Sunoco LP and us;

• the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP and Sunoco LP, on the other hand;

• the determination of the amount of cash to be distributed to ETP’s and Sunoco LP’s partners and the amount of cash to be reserved for the future conduct of ETP’s and Sunoco LP’s businesses;

• the determination whether to make borrowings under ETP’s and Sunoco LP’s revolving credit facilities to pay distributions to their respective partners;

• the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of ETP and Sunoco LP is made available for ETP and Sunoco LP to pursue; and

• any decision we make in the future to engage in business activities independent of ETP and Sunoco LP.

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The fiduciary duties of our General Partner’s officers and directors may conflict with those of ETP’s or Sunoco LP’s respective general partners.

Conflicts of interest may arise because of the relationships among ETP, Sunoco LP, their general partners and us. Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our General Partner’s directors are also directors and officers of ETP’s general partner or Sunoco LP’s general partner, and have fiduciary duties to manage the respective businesses of ETP and Sunoco LP in a manner beneficial to ETP, Sunoco LP and their respective Unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.

Potential conflicts of interest may arise among our General Partner, its affiliates and us. Our General Partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.

Conflicts of interest may arise among our General Partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:

• Our General Partner is allowed to take into account the interests of parties other than us, including ETP and Sunoco LP and their respective affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.

• Our General Partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, Unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

• Our General Partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.

• Our General Partner determines which costs it and its affiliates have incurred are reimbursable by us.

• Our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.

• Our General Partner controls the enforcement of obligations owed to us by it and its affiliates.

• Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

Our partnership agreement limits our General Partner’s fiduciary duties to us and restricts the remedies available for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

• permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

• provides that our General Partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;

• generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Audit and Conflicts Committee of the board of directors of our General Partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

• provides that unless our General Partner has acted in bad faith, the action taken by our General Partner shall not constitute a breach of its fiduciary duty;

• provides that our General Partner may resolve any conflicts of interest involving us and our General Partner and its affiliates, and any resolution of a conflict of interest by our General Partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the partnership agreement;

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• provides that our General Partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the General Partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us; and

• provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

The general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our Unitholders.

Our partnership agreement requires the general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, our partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.

Risks Related to the Businesses of our Subsidiaries

Since our cash flows consist exclusively of distributions from our subsidiaries, risks to the businesses of our subsidiaries are also risks to us. We have set forth below risks to the businesses of our subsidiaries, the occurrence of which could have a negative impact on their respective financial performance and decrease the amount of cash they are able to distribute to us.

ETP does not control, and therefore may not be able to cause or prevent certain actions by, certain of its joint ventures.

Certain of ETP’s joint ventures have their own governing boards, and ETP may not control all of the decisions of those boards. Consequently, it may be difficult or impossible for ETP to cause the joint venture entity to take actions that ETP believes would be in their or the joint venture’s best interests. Likewise, ETP may be unable to prevent actions of the joint venture.

ETP and Sunoco LP are exposed to the credit risk of their respective customers and derivative counterparties, and an increase in the nonpayment and nonperformance by their respective customers or derivative counterparties could reduce their respective ability to make distributions to their Unitholders, including to us.

The risks of nonpayment and nonperformance by ETP’s and Sunoco LP’s respective customers are a major concern in their respective businesses. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP and Sunoco LP are subject to risks of loss resulting from nonpayment or nonperformance by their respective customers, especially during the current low commodity price environment impacting many oil and gas producers. As a result, the current commodity price volatility and the tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by ETP’s and Sunoco LP’s customers. To the extent one or more of our customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or our derivative counterparties could reduce our ability to make distributions to our Unitholders. Any substantial increase in the nonpayment and nonperformance by ETP’s or Sunoco LP’s customers could have a material adverse effect on ETP’s or Sunoco LP’s respective results of operations and operating cash flows.

The use of derivative financial instruments could result in material financial losses by ETP and Sunoco LP.

From time to time, ETP and Sunoco LP have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by their trading, marketing and/or system optimization activities. To the extent that either ETP or Sunoco LP hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change favorably. In addition, ETP’s and Sunoco LP’s derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to ETP’s or Sunoco LP’s physical or financial positions, or internal hedging policies and procedures are not followed.

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The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

In addition, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.

The inability to continue to access lands owned by third parties, including tribal lands, could adversely affect ETP’s and Sunoco LP’s ability to operate and adversely affect their financial results.

ETP’s ability to operate its pipeline systems and terminal facilities on certain lands owned by third parties, including lands held in trust by the United States for the benefit of a Native American tribe, will depend on their success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. Securing extensions of existing and any additional rights-of-way is also critical to ETP’s ability to pursue expansion projects. ETP cannot provide any assurance that they will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants or that all of the rights-of-way will be obtainable in a timely fashion. Transwestern’s existing right-of-way agreements with the Navajo Nation, Southern Ute, Pueblo of Laguna and Fort Mojave tribes extend through November 2029, September 2020, December 2022 and April 2019, respectively. ETP’s financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.

Further, whether ETP has the power of eminent domain for its pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state. In either case, ETP must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect ETP’s business if they were to lose the right to use or occupy the property on which their pipelines are located. For example, following a recent decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. Any loss of rights with respect to ETP’s real property, through its inability to renew right-of-way contracts or otherwise, could have a material adverse effect on its business, results of operations, financial condition and ability to make cash distributions.

In addition, Sunoco LP does not own all of the land on which their retail service stations are located. Sunoco LP has rental agreements for approximately 35.2% of the company-operated retail service stations where Sunoco LP currently controls the real estate and has rental agreements for certain logistics facilities. As such, Sunoco LP is subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Sunoco LP is also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by Sunoco LP are leased from third parties for specific periods. Sunoco LP’s inability to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on its financial condition, results of operations and cash flows.

ETP and Sunoco LP may not be able to fully execute their growth strategies if they encounter increased competition for qualified assets.

ETP and Sunoco LP have strategies that contemplate growth through the development and acquisition of a wide range of midstream, retail and wholesale fuel distribution assets and other energy infrastructure assets while maintaining strong balance sheets. These strategies include constructing and acquiring additional assets and businesses to enhance their ability to compete effectively and diversify their respective asset portfolios, thereby providing more stable cash flow. ETP and Sunoco LP regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that ETP and Sunoco LP believe will present opportunities to realize synergies and increase cash flow.

Consistent with their strategies, managements of ETP and Sunoco LP may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP and Sunoco LP management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP and Sunoco LP believe it is the only party or one of a very limited number of potential buyers

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in negotiations with the potential seller. We cannot assure that ETP’s or Sunoco LP’s acquisition efforts will be successful or that any acquisition will be completed on favorable terms.

In addition, ETP and Sunoco LP are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in ETP or Sunoco LP losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s and Sunoco LP’s ability to fully execute their respective growth strategies. Inability to execute their respective growth strategies may materially adversely impact ETP’s and Sunoco LP’s results of operations.

An impairment of goodwill and intangible assets could reduce our earnings.

As of December 31, 2017, our consolidated balance sheets reflected $4.77 billion of goodwill and $6.12 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.

During the fourth quarter of 2017, we performed goodwill impairment tests on our reporting units and recognized goodwill impairments at both ETP and Sunoco LP. The goodwill impairments at ETP consisted of $262 million in its interstate transportation and storage operations, $79 million in its NGL and refined products transportation and services operations and $452 million in its all other operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. During the year 2017, Sunoco LP recorded a goodwill impairment charge of $102 million on its retail reporting unit.

During the fourth quarter of 2016, we performed goodwill impairment tests on our reporting units and recognized goodwill impairments at both ETP and Sunoco LP. The goodwill impairments recognized at ETP consisted of $638 million related to ETP’s interstate transportation and storage operations and $32 million related to ETP’s midstream operations. These impairments are primarily due to decreases in projected future revenues and cash flows driven by reduced volumes as a result of overall declining commodity prices and changes in the markets that these assets serve. During the fourth quarter of 2016, Sunoco LP recognized a goodwill impairment of $641 million in its retail reporting unit primarily due to changes in assumptions related to projected future revenues and cash flows from the dates this goodwill was originally recorded. During the fourth quarter of 2016, Sunoco LP also recognized a $32 million impairment on its Laredo Taco brand name intangible asset primarily due to changes in Sunoco LP’s construction plan for new-to-industry sites and decreases in sales volume in oil field producing regions where Sunoco LP has operations.

If ETP and Sunoco LP do not make acquisitions on economically acceptable terms, their future growth could be limited.

ETP’s and Sunoco LP’s results of operations and their ability to grow and to increase distributions to Unitholders will depend in part on their ability to make acquisitions that are accretive to their respective distributable cash flow.

ETP and Sunoco LP may be unable to make accretive acquisitions for any of the following reasons, among others:

• inability to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

• inability to raise financing for such acquisitions on economically acceptable terms; or

• inability to outbid by competitors, some of which are substantially larger than ETP or Sunoco LP and may have greater financial resources and lower costs of capital.

Furthermore, even if ETP or Sunoco LP consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP or Sunoco LP may:

• fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;

• decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;

• significantly increase its interest expense or financial leverage if the acquisition is financed with additional debt;

• encounter difficulties operating in new geographic areas or new lines of business;

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• incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which there is no indemnity or the indemnity is inadequate;

• be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;

• less effectively manage its historical assets, due to the diversion of management’s attention from other business concerns; or

• incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

If ETP and Sunoco LP consummate future acquisitions, their respective capitalization and results of operations may change significantly. As ETP and Sunoco LP determine the application of their funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that ETP and Sunoco LP will consider.

Integration of assets acquired in past acquisitions or future acquisitions with our existing business will be a complex and time-consuming process. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash available for distribution to our unitholders.

The difficulties of integrating past and future acquisitions with our business include, among other things:

• operating a larger combined organization in new geographic areas and new lines of business;

• hiring, training or retaining qualified personnel to manage and operate our growing business and assets;

• integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;

• diversion of management’s attention from our existing business;

• assimilation of acquired assets and operations, including additional regulatory programs;

• loss of customers or key employees;

• maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and

• integrating new technology systems for financial reporting.

If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions resulting in a negative impact to our future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.

Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems, and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, may not be observable even when an inspection is undertaken.

Legal actions related to the Dakota Access Pipeline could cause an interruption to operations, which could have an adverse effect on our business and results of operations.

On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. The Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (the “Court”) against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline and claimed violations of the National Historic Preservation Act (“NHPA”). Dakota Access intervened in the case.

In February 2017, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. The SRST and Cheyenne River Sioux Tribe (“CRST”) (which had intervened in the lawsuit brought by SRST), amended their complaints to incorporate religious freedom and other claims related to treaties and use of government property. The Oglala and

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Yankton Sioux tribes, and various individual members, filed related lawsuits in opposition to the Dakota Access pipeline. These lawsuits have been consolidated into the action initiated by the SRST.

On June 14, 2017, the Court ruled that the USACE substantially complied with all relevant statutes in connection with the issuance of the permits and easement, but remanded to the USACE three discrete issues for further analysis and explanation of its prior determination under certain of these statutes. On October 11, 2017, the Court ruled that the pipeline could continue to transport crude oil during the pendency of the remand, but requested briefing from the parties as to whether any conditions on the continued operation of the pipeline during this period. On December 4, 2017, the Court determined to impose three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. Second, the Court directed Dakota Access to continue its work with the tribes and the USACE to revise and finalize its response planning for the section of the pipeline crossing Lake Oahe. Third, the Court directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information recommended by PHMSA.

While we believe that the pending lawsuits are unlikely to adversely affect the continued operation of the pipeline, we cannot assure this outcome. At this time, we cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.

In addition, lawsuits of this nature could result in interruptions to construction or operations of future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.

Income from ETP’s midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs and crude oil that are beyond our control.

The prices for natural gas, NGLs and crude oil (including refined petroleum products) reflect market demand that fluctuates with changes in global and United States economic conditions and other factors, including:

• the level of domestic natural gas, NGL, and crude oil production;

• the level of natural gas, NGL, and crude oil imports and exports, including liquefied natural gas;

• actions taken by natural gas and oil producing nations;

• instability or other events affecting natural gas and oil producing nations;

• the impact of weather and other events of nature on the demand for natural gas, NGLs and crude oil;

• the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;

• the price, availability and marketing of competitive fuels;

• the demand for electricity;

• activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;

• the cost of capital needed to maintain or increase production levels and to construct and expand facilities

• the impact of energy conservation and fuel efficiency efforts; and

• the extent of governmental regulation, taxation, fees and duties.

In the past, the prices of natural gas, NGLs and crude oil have been extremely volatile, and we expect this volatility to continue.

Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs or crude oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGLs and crude oil commodities could materially affect our profitability.

ETP is affected by competition from other midstream, transportation and storage and retail marketing companies.

We experience competition in all of our business segments. With respect to ETP’s midstream operations, ETP competes for both natural gas supplies and customers for its services. Competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas.

ETP’s natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers in the transportation and storage of natural gas and NGLs. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas

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and NGLs also compete with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits also affects competitive outcomes.

In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer’s products.

ETP’s crude oil and refined products pipeline operations face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in areas served by Sunoco Logistics’ pipelines. Further, our refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

ETP may be unable to retain or replace existing midstream, transportation, terminalling and storagecustomers or volumes due to declining demand or increased competition in crude oil, natural gas and NGL markets, which would reduce revenues and limit future profitability.

The retention or replacement of existing customers and the volume of services that ETP provides at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including the price of and demand for crude oil, natural gas, and NGLs in the markets we serve and competition from other service providers.

A significant portion of ETP’s sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of these customers also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in natural gas sales markets primarily on the basis of price.

ETP also receives a substantial portion of revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of their services are sold under long-term contracts for reserved service, they also provide service on an unreserved or short-term basis. Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production resulting in less use of services, while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may attract our customers’ business. If demand declines or competition increases, we may not be able to sustain existing levels of unreserved service or renew or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.

Revenue from ETP’s NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. ETP receives substantially all of their transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to their transportation system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under dedicated contracts and lower demand for our services. In addition, ETP’s refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers, a portion of its revenue is derived from fungible storage and throughput arrangements, under which ETP’s revenue is more dependent upon demand for storage from its customers.

The volume of crude oil and products transported through ETP’s oil pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or products could lead to a decline in drilling activity, production and refining of crude oil, or import levels in these areas. A period of sustained increases in the price of crude oil or products supplied from or delivered to any of these areas could materially reduce demand for crude oil or products in these areas. In either case, the volumes of crude oil or products transported in our oil pipelines and terminal facilities could decline.

The loss of existing customers by ETP’s midstream, transportation, terminalling and storage facilities or a reduction in the volume of the services customers purchase from them, or their inability to attract new customers and service volumes would negatively affect revenues, be detrimental to growth, and adversely affect results of operations.

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ETP’s midstream facilities and transportation pipelines are attached to basins with naturally declining production, which it may not be able to replace with new sources of supply.

In order to maintain or increase throughput levels on ETP’s gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, ETP must continually contract for new natural gas supplies and natural gas transportation services.

A substantial portion of ETP’s assets, including its gathering systems and processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. ETP’s gas transportation pipelines are also dependent upon natural gas production in areas served by our gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. ETP may not be able to obtain additional contracts for natural gas supplies for its natural gas gathering systems, and may be unable to maintain or increase the levels of natural gas throughput on its transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near our gathering systems or in areas that provide access to its transportation pipelines or markets to which ETP’s systems connect. ETP has no control over the level of drilling activity in its areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, ETP has no control over producers or their production and contracting decisions.

While a substantial portion of ETP’s services are provided under long-term contracts for reserved service, it also provides service on an unreserved basis. The reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities may decline and may not be replaced by other sources of supply. A decrease in development or production activity could cause a decrease in the volume of unreserved services ETP provides and a decrease in the number and volume of its contracts for reserved transportation service over the long run, which in each case would adversely affect revenues and results of operations.

If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely affected.

The profitability of certain activities in ETP’s natural gas gathering, processing, transportation and storage operations is largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.

For a portion of the natural gas gathered on ETP’s systems, they purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where they typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins realized under these arrangements decrease in periods of low natural gas prices.

ETP also enters into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which they agree to gather and process natural gas received from the producers.

Under percent-of-proceeds arrangements, ETP generally sells the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, ETP delivers an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes kept to third parties at market prices. Under these arrangements, ETP’s revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on ETP’s revenues and results of operations.

Under keep-whole arrangements, ETP generally sells the NGLs produced from their gathering and processing operations at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, ETP must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, gross margins generally decrease when the price of natural gas increases relative to the price of NGLs.

When ETP processes the gas for a fee under processing fee agreements, they may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, ETP may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.

ETP also receives fees and retains gas in kind from natural gas transportation and storage customers. The fuel retention fees and the value of gas that ETP retains in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease these fuel retention fees and the value of retained gas.

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In addition, ETP receives revenue from their off-gas processing and fractionating system in south Louisiana primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of ETP’s off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for their off-gas processing and fractionation services and could have an adverse effect on their results of operations.

For ETP’s midstream operations, gross margin is generally analyzed based on fee-based margin (which includes revenues from processing fee arrangements) and non-fee based margin (which includes gross margin earned on percent-of-proceeds and keep-whole arrangements). For the years ended December 31, 2017, 2016 and 2015, gross margin from ETP’s midstream operations totaled $2.18 billion, $1.80 billion, and $1.79 billion, respectively, of which fee-based revenues constituted 78%, 86% and 88%, respectively, and non-fee based margin constituted 22%, 14% and 12%, respectively. The amount of gross margin earned by ETP’s midstream operations from fee-based and non-fee based arrangements (individually and as a percentage of total revenues) will be impacted by the volumes associated with both types of arrangements, as well as commodity prices; therefore, the dollar amounts and the relative magnitude of gross margin from fee-based and non-fee based arrangements in future periods may be significantly different from results reported in previous periods.

ETP’s revenues depend on its customers’ ability to use ETP’s pipelines and third-party pipelines over which we have no control.

ETP’s natural gas transportation, storage and NGL businesses depend, in part, on their customers’ ability to obtain access to pipelines to deliver gas to and receive gas from ETP. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third-party pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in terms and conditions of service could have a material adverse effect on ETP’s ability, and the ability of their customers, to transport natural gas to and from their pipelines and facilities and a corresponding material adverse effect on their transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from ETP’s s facilities affect the utilization and value of their storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on storage revenues.

Shippers using ETP’s oil pipelines and terminals are also dependent upon their pipelines and connections to third-party pipelines to receive and deliver crude oil and products. Any interruptions or reduction in the capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in ETP’s pipelines or through their terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to ETP existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in their pipelines or through their terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on ETP’s results of operations, financial position, or cash flows.

If ETP does not continue to construct new pipelines, their future growth could be limited.

ETP’s results of operations and their ability to grow and to increase distributable cash flow per unit will depend, in part, on their ability to construct pipelines that are accretive to their respective distributable cash flow. ETP may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:

• inability to identify pipeline construction opportunities with favorable projected financial returns;

• inability to raise financing for its identified pipeline construction opportunities; or

• inability to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.

Furthermore, even if ETP constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or fail to achieve results projected prior to commencement of construction.

Expanding ETP’s business by constructing new pipelines and related facilities subjects ETP to risks.

One of the ways that ETP has grown their business is through the construction of additions to existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline and related facilities (or the improvement and repair of existing facilities) involves numerous regulatory, environmental, political and legal uncertainties beyond ETP’s control and requires the expenditure of significant amounts of capital to be financed through borrowings, the issuance of additional equity or from operating cash flow. If ETP undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. A variety of factors outside ETP’s control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors may result in increased costs or delays

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in construction. Cost overruns or delays in completing a project could have a material adverse effect on ETP’s results of operations and cash flows. Moreover, revenues may not increase immediately following the completion of a particular project. For instance, if ETP builds a new pipeline, the construction will occur over an extended period of time, but ETP may not materially increase its revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of oil and natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as ETP’s ability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, ETP may construct facilities to capture anticipated future growth in oil or natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s expected investment return, which could adversely affect its results of operations and financial condition.

ETP depends on certain key producers for a significant portion of their supplies of natural gas. The loss of, or reduction in, any of these key producers could adversely affect ETP’s business and operating results.

ETP relies on a limited number of producers for a significant portion of their natural gas supplies. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, ETP will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. ETP may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on ETP’s business, results of operations, and financial condition.

ETP depends on key customers to transport natural gas through their pipelines.

ETP relies on a limited number of major shippers to transport certain minimum volumes of natural gas on their respective pipelines. The failure of the major shippers on ETP’s or their joint ventures’ pipelines or of other key customers to fulfill their contractual obligations under these contracts could have a material adverse effect on the cash flow and results of operations of us, ETP or their joint ventures, as applicable, were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

ETP’s contract compression operations depend on particular suppliers and are vulnerable to parts and equipment shortages and price increases, which could have a negative impact on results of operations.

The principal manufacturers of components for ETP’s natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers and Ariel Corporation for compressors and frames. ETP’s reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. ETP also relies primarily on two vendors, Spitzer Industries Corp. and Standard Equipment Corp., to package and assemble its compression units. ETP does not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on our results of operations and could damage our customer relationships.

A material decrease in demand or distribution of crude oil available for transport through ETP’s pipelines or terminal facilities could materially and adversely affect our results of operations, financial position, or cash flows.

The volume of crude oil transported through ETP’s crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by its assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to ETP’s customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported in ETP’s crude oil pipelines and terminal facilities could decline, and it could likely be difficult to secure alternative sources of attractively priced crude oil supply in a timely fashion or at all. If ETP is unable to replace any significant volume declines with additional volumes from other sources, its results of operations, financial position, or cash flows could be materially and adversely affected.

An interruption of supply of crude oil to ETP’s facilities could materially and adversely affect our results of operations and revenues.

While ETP is well positioned to transport and receive crude oil by pipeline, marine transport and trucks, rail transportation also serves as a critical link in the supply of domestic crude oil production to United States refiners, especially for crude oil from regions such as the Bakken that are not sourced near pipelines or waterways that connect to all of the major United States refining centers. Federal regulators have issued a safety advisory warning that Bakken crude oil may be more volatile than many other North American crude oils and reinforcing the requirement to properly test, characterize, classify, and, if applicable, sufficiently degasify hazardous materials prior to and during transportation. The domestic crude oil received by our facilities, especially from the Bakken region, may be transported by railroad. If the ability to transport crude oil by rail is disrupted because of accidents,

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weather interruptions, governmental regulation, congestion on rail lines, terrorism, other third-party action or casualty or other events, then ETP could experience an interruption of supply or delivery or an increased cost of receiving crude oil, and could experience a decline in volumes received. Recent railcar accidents in Quebec, Alabama, North Dakota, Pennsylvania and Virginia, in each case involving trains carrying crude oil from the Bakken region, have led to increased legislative and regulatory scrutiny over the safety of transporting crude oil by rail. In 2015, the DOT, through the PHMSA, issued a rule implementing new rail car standards and railroad operating procedures. Changing operating practices, as well as new regulations on tank car standards and shipper classifications, could increase the time required to move crude oil from production areas of facilities, increase the cost of rail transportation, and decrease the efficiency of transportation of crude oil by rail, any of which could materially reduce the volume of crude oil received by rail and adversely affect our financial condition, results of operations, and cash flows.

A portion of ETP’s general and administrative services have been outsourced to third-party service providers. Fraudulent activity or misuse of proprietary data involving its outsourcing partners could expose us to additional liability.

ETP utilizes both affiliate entities and third parties in the processing of its information and data. Breaches of its security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about ETP or its customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose ETP to a risk of loss or misuse of this information, result in litigation and potential liability for ETP, lead to reputational damage, increase compliance costs, or otherwise harm its business.

Sunoco LP is entirely dependent upon third parties for the supply of refined products such as gasoline and diesel for its retail marketing business.

Sunoco LP is required to purchase refined products from third party sources, including the joint venture that acquired Sunoco, Inc.’s Philadelphia refinery. Sunoco LP may also need to contract for new ships, barges, pipelines or terminals which it has not historically used to transport these products to its markets. The inability to acquire refined products and any required transportation services at favorable prices may adversely affect Sunoco LP’s business and results of operations.

A significant decrease in demand for motor fuel, including increased consumer preference for alternative motor fuels or improvements in fuel efficiency, in the areas Sunoco LP serves would reduce their ability to make distributions to unitholders.

Sales of refined motor fuels account for approximately 93% of Sunoco LP’s total revenues and 62% of continuing operations gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and their ability to make or increase distributions to unitholders. Sunoco LP revenues are dependent on various trends, such as trends in commercial truck traffic, travel and tourism in their areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may also affect demand for motor fuel. Because certain of Sunoco LP’s operating costs and expenses are fixed and do not vary with the volumes of motor fuel distributed, their costs and expenses might not decrease ratably or at all should they experience such a reduction. As a result, Sunoco LP may experience declines in their profit margin if fuel distribution volumes decrease.

Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could reduce demand for the conventional petroleum based motor fuels Sunoco LP currently sells. Additionally, a shift toward electric, hydrogen, natural gas or other alternative-power vehicles could fundamentally change customers' shopping habits or lead to new forms of fueling destinations or new competitive pressures.

New technologies have been developed and governmental mandates have been implemented to improve fuel efficiency, which may result in decreased demand for petroleum-based fuel. Any of these outcomes could result in fewer visits to Sunoco LP’s convenience stores or independently operated commission agents and dealer locations, a reduction in demand from their wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.

The industries in which Sunoco LP operates are subject to seasonal trends, which may cause our operating costs to fluctuate, affecting our cash flow.

Sunoco LP relies in part on customer travel and spending patterns, and may experience more demand for gasoline in the late spring and summer months than during the fall and winter. Travel, recreation and construction are typically higher in these months in the geographic areas in which Sunoco LP or its commission agents and dealers operate, increasing the demand for motor fuel that they sell and distribute. Therefore, Sunoco LP’s revenues and cash flows are typically higher in the second and third quarters of our fiscal year. As a result, Sunoco LP’s results from operations may vary widely from period to period, affecting Sunoco LP’s cash flow.

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Sunoco LP’s financial condition and results of operations are influenced by changes in the prices of motor fuel, which may adversely impact margins, customers’ financial condition and the availability of trade credit.

Sunoco LP’s operating results are influenced by prices for motor fuel. General economic and political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East and South America, could significantly impact crude oil supplies and petroleum costs. Significant increases or high volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it difficult to predict the impact that future petroleum costs fluctuations may have on Sunoco LP’s operating results and financial condition. Sunoco LP is subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors could materially impact both wholesale and retail fuel margins, the volume of motor fuel distributed or sold at retail, and overall customer traffic, each of which in turn could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.

Significant increases in wholesale motor fuel prices could impact Sunoco LP as some of their customers may have insufficient credit to purchase motor fuel from us at their historical volumes. Higher prices for motor fuel may also reduce access to trade credit support or cause it to become more expensive.

The dangers inherent in the storage and transportation of motor fuel could cause disruptions in Sunoco LP’s operations and could expose them to potentially significant losses, costs or liabilities.

Sunoco LP stores motor fuel in underground and aboveground storage tanks. Sunoco LP transports the majority of its motor fuel in its own trucks, instead of by third-party carriers. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to its properties and the properties of others. Any such event not covered by Sunoco LP’s insurance could have a material adverse effect on its business, financial condition, results of operations and cash available for distribution to unitholders.

Sunoco LP’s fuel storage terminals are subject to operational and business risks which may adversely affect their financial condition, results of operations, cash flows and ability to make distributions to unitholders.

Sunoco LP’s fuel storage terminals are subject to operational and business risks, the most significant of which include the following:

• the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all;

• the dependence on third parties to supply their fuel storage terminals;

• outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes;

• the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;

• the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services;

• the effects of a sustained recession or other adverse economic conditions;

• the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel storage terminals or reduce the demand by consumers for petroleum products;

• competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and

• climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.

The occurrence of any of the above situations, amongst others, may affect operations at their fuel storage terminals and may adversely affect Sunoco LP’s business, financial condition, results of operations, cash flows and ability to make distributions to unitholders.

Negative events or developments associated with Sunoco LP’s branded suppliers could have an adverse impact on its revenues.

Sunoco LP believes that the success of its operations is dependent, in part, on the continuing favorable reputation, market value, and name recognition associated with the motor fuel brands sold at Sunoco LP’s convenience stores and at stores operated by its independent, branded dealers and commission agents. Erosion of the value of those brands could have an adverse impact on the

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volumes of motor fuel Sunoco LP distributes, which in turn could have a material adverse effect on its business, financial condition, results of operations and ability to make distributions to its unitholders.

The wholesale motor fuel distribution industry and convenience store industry are characterized by intense competition and fragmentation and impacted by new entrants. Failure to effectively compete could result in lower margins.

The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. Sunoco LP has numerous competitors, some of which may have significantly greater resources and name recognition than it does. Sunoco LP relies on its ability to provide value-added, reliable services and to control its operating costs in order to maintain our margins and competitive position. If Sunoco LP fails to maintain the quality of its services, certain of its customers could choose alternative distribution sources and margins could decrease. While major integrated oil companies have generally continued to divest retail sites and the corresponding wholesale distribution to such sites, such major oil companies could shift from this strategy and decide to distribute their own products in direct competition with Sunoco LP, or large customers could attempt to buy directly from the major oil companies. The occurrence of any of these events could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.

The geographic areas in which Sunoco LP operates and supplies independently operated commission agent and dealer locations are highly competitive and marked by ease of entry and constant change in the number and type of retailers offering products and services of the type we and our independently operated commission agents and dealers sell in stores. Sunoco LP competes with other convenience store chains, independently owned convenience stores, motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass merchants and local restaurants. Over the past two decades, several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry, particularly in the geographic areas in which Sunoco LP operates, by entering the motor fuel retail business. These non-traditional motor fuel retailers have captured a significant share of the motor fuels market, and Sunoco LP expects their market share will continue to grow.

In some of Sunoco LP’s markets, its competitors have been in existence longer and have greater financial, marketing, and other resources than they or their independently operated commission agents and dealers do. As a result, Sunoco LP’s competitors may be able to better respond to changes in the economy and new opportunities within the industry. To remain competitive, Sunoco LP must constantly analyze consumer preferences and competitors’ offerings and prices to ensure that they offer a selection of convenience products and services at competitive prices to meet consumer demand. Sunoco LP must also maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. Sunoco LP may not be able to compete successfully against current and future competitors, and competitive pressures faced by Sunoco LP could have a material adverse effect on its business, results of operations and cash available for distribution to unitholders.

Sunoco LP expect to generate a significant portion of its motor fuel sales under a fuel supply agreement with 7-Eleven, and any loss, or change in the economic terms, of such arrangement could adversely affect Sunoco LP’s business, financial condition and results of operations.

Sunoco LP expect that a significant portion of its motor fuel sales in 2018 will be derived from its fuel supply agreement with 7-Eleven. The 7-Eleven fuel supply agreement is a 15-year fixed margin, “take or pay” fuel supply arrangement with certain affiliates of 7-Eleven. The loss or change in economics of such arrangement and the inability to enter into new contracts on similar economically acceptable terms could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations.

Wholesale cost increases in tobacco products, including excise tax increases on cigarettes, could adversely impact Sunoco LP’s revenues and profitability.

Significant increases in wholesale cigarette costs and tax increases on cigarettes may have an adverse effect on unit demand for cigarettes. Cigarettes are subject to substantial and increasing excise taxes at both a state and federal level. Sunoco LP cannot predict whether this trend will continue into the future. Increased excise taxes may result in declines in overall sales volume and reduced gross profit percent, due to lower consumption levels and to a shift in consumer purchases from the premium to the non-premium or discount segments or to other lower-priced tobacco products or to the import of cigarettes from countries with lower, or no, excise taxes on such items.

Currently, major cigarette manufacturers offer rebates to retailers. Sunoco LP includes these rebates as a component of its gross margin from sales of cigarettes. In the event these rebates are no longer offered, or decreased, Sunoco LP’s wholesale cigarette costs will increase accordingly. In general, Sunoco LP attempts to pass price increases on to its customers. However, due to competitive pressures in our markets, it may not be able to do so. These factors could materially impact Sunoco LP’s retail price of cigarettes, cigarette unit volume and revenues, merchandise gross profit and overall customer traffic, which could in turn have a material adverse effect on Sunoco LP’s business and results of operations.

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Failure to comply with state laws regulating the sale of alcohol and cigarettes may result in the loss of necessary licenses and the imposition of fines and penalties, which could have a material adverse effect on Sunoco LP’s business.

State laws regulate the sale of alcohol and cigarettes. A violation of or change in these laws could adversely affect Sunoco LP’s business, financial condition and results of operations because state and local regulatory agencies have the power to approve, revoke, suspend or deny applications for, and renewals of, permits and licenses relating to the sale of these products and can also seek other remedies. Such a loss or imposition could have a material adverse effect on Sunoco LP’s business and results of operations.

Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. A disruption in supply or a change in either relationship could have a material adverse effect on its business.

Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. If any of Sunoco LP’s principal suppliers elect not to renew their contracts, Sunoco LP may be unable to replace the volume of merchandise inventory and products and ingredients currently purchased from them on similar terms or at all in those operating areas. Further, a disruption in supply or a significant change in Sunoco LP’s relationship with any of these suppliers could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations and cash available for distribution to unitholders.

Sunoco LP may be subject to adverse publicity resulting from concerns over food quality, product safety, health or other negative events or developments that could cause consumers to avoid its retail locations or independently operated commission agent or dealer locations.

Sunoco LP may be the subject of complaints or litigation arising from food-related illness or product safety which could have a negative impact on its business. Negative publicity, regardless of whether the allegations are valid, concerning food quality, food safety or other health concerns, food service facilities, employee relations or other matters related to its operations may materially adversely affect demand for its food and other products and could result in a decrease in customer traffic to its retail stores or independently operated commission agent or dealer locations.

It is critical to Sunoco LP’s reputation that they maintain a consistent level of high quality at their food service facilities and other franchise or fast food offerings. Health concerns, poor food quality or operating issues stemming from one store or a limited number of stores could materially and adversely affect the operating results of some or all of their stores and harm the company-owned brands, continuing favorable reputation, market value and name recognition.

Sunoco LP has outsourced various functions related to its retail marketing business to third-party service providers, which decreases its control over the performance of these functions. Disruptions or delays of its third-party outsourcing partners could result in increased costs, or may adversely affect service levels. Fraudulent activity or misuse of proprietary data involving its outsourcing partners could expose it to additional liability.

Sunoco LP has previously outsourced various functions related to its retail marketing business to third parties and expects to continue this practice with other functions in the future. While outsourcing arrangements may lower its cost of operations, they also reduce its direct control over the services rendered. It is uncertain what effect such diminished control will have on the quality or quantity of products delivered or services rendered, on its ability to quickly respond to changing market conditions, or on its ability to ensure compliance with all applicable domestic and foreign laws and regulations. Sunoco LP believes that it conducts appropriate due diligence before entering into agreements with its outsourcing partners. Sunoco LP relies on its outsourcing partners to provide services on a timely and effective basis. Although Sunoco LP continuously monitor the performance of these third parties and maintain contingency plans in case they are unable to perform as agreed, it does not ultimately control the performance of its outsourcing partners. Much of its outsourcing takes place in developing countries and, as a result, may be subject to geopolitical uncertainty. The failure of one or more of its third-party outsourcing partners to provide the expected services on a timely basis at the prices Sunoco LP expect, or as required by contract, due to events such as regional economic, business, environmental or political events, information technology system failures, or military actions, could result in significant disruptions and costs to its operations, which could materially adversely affect its business, financial condition, operating results and cash flow. Sunoco LP’s failure to generate significant cost savings from these outsourcing initiatives could adversely affect its profitability and weaken its competitive position. Additionally, if the implementation of its outsourcing initiatives is disruptive to its retail marketing business, Sunoco LP could experience transaction errors, processing inefficiencies, and the loss of sales and customers, which could cause its business and results of operations to suffer. As a result of these outsourcing initiatives, more third parties are involved in processing its retail marketing information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about its retail marketing business or its clients, including the potential loss or disclosure of such information or data as a result of fraud or other forms of

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deception, could expose it to a risk of loss or misuse of this information, result in litigation and potential liability for it, lead to reputational damage to the Sunoco brand, increase its compliance costs, or otherwise harm its business.

ETP’s 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 ETP’s 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.

ETP is required to file tariff rates (also known as recourse rates) with the FERC that shippers may elect to 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. ETP must also file with the FERC all negotiated rates that do not conform to our tariff rates and all changes to our tariff or negotiated 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 ETP and find that its rates were not just and reasonable or unduly discriminatory, the maximum rates customers could elect to pay ETP may be reduced and the reduction could have an adverse effect on our revenues and results of operations.

The costs of ETP’s interstate pipeline operations may increase and ETP may not be able to recover all of those costs due to FERC regulation of its rates. If ETP proposes to change its tariff rates, its proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit ETP’s proposed changes if ETP is unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. ETP 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 ETP may be constrained by competitive factors from charging their tariff rates.

To the extent ETP’s costs increase in an amount greater than its revenues increase, or there is a lag between its cost increases and ability to file for and obtain rate increases, ETP’s 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. ETP cannot guarantee that its interstate pipelines will be able to recover all of their costs through existing or future rates.

The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. It is currently the FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, to the extent that the ultimate owners have an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Under the FERC’s policy, ETP thus remains eligible to include an income tax allowance in the tariff rates ETP charges for interstate natural gas transportation. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. FERC issued the Notice of Inquiry in response to a remand from the United States Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. FERC requested comments regarding how to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The comment period with respect to the notice of inquiry ended on April 7, 2017. The outcome of the inquiry is still pending. ETP cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax allowances or return on equity calculations for pipeline companies organized as part of a master limited partnership. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as part of a master limited partnership or decreases the return on equity for such pipelines could result in an adverse impact on ETP’s revenues associated with the transportation and storage services ETP provides pursuant to cost-based rates.

Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. Following the 2017 Tax Cuts and Jobs Act being signed into law, filings have been made at FERC requesting that FERC require pipelines to lower their transportation rates to account for lower taxes. Following the effective date of the law, the FERC orders granting certificates to construct proposed pipeline facilities have directed pipelines proposing new rates for service on those facilities to re-file such rates so that the rates reflect the reduction in the corporate tax rate, and

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FERC has issued data requests in pending certificate proceedings for proposed pipeline facilities requesting pipelines to explain the impacts of the reduction in the corporate tax rate on the rate proposals in those proceedings and to provide re-calculated initial rates for service on the proposed pipeline facilities. FERC may enact other regulations or issue further requests to pipelines regarding the impact of the corporate tax rate change on the rates. The FERC’s establishment of a just and reasonable rate is based on many components, and the reduction in the corporate tax rate may impact two of such components: the allowance for income taxes and the amount for accumulated deferred income taxes. Because ETP’s existing jurisdictional rates were established based on a higher corporate tax rate, FERC or ETP’s shippers may challenge these rates in the future, and the resulting new rate may be lower than the rates ETP currently charges.

ETP’s interstate natural gas pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect its business and operations.

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

• operating terms and conditions of service;

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

• construction of new facilities;

• 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.

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

The current FERC Chairman announced in December 2017 that FERC will review 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. ETP is unable to predict what, if any, changes may be proposed that will affect its natural gas pipeline business or when such proposals, if any, might become effective. ETP does not expect that any change in this policy would affect them in a materially different manner than any other similarly sized natural gas pipeline company operating in the United States.

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

Transportation provided on ETP’s 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 ETP proposes 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: (1) 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% for the prior two years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) 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.

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Under the EPAct 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.

State regulatory measures could adversely affect the business and operations of ETP’s midstream and intrastate pipeline and storage assets.

ETP’s midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects their business and the market for their products. The rates, terms and conditions of service for the interstate services they provide in their intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. ETP’s HPL System, East Texas pipeline, Oasis pipeline and ET Fuel System provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than ETP’s costs of service, their cash flow would be negatively affected.

ETP’s midstream and intrastate gas and oil transportation pipelines and their intrastate gas storage operations are subject to state regulation. All of the states in which they operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which ETP operates have ratable take statutes, which generally require gatherers to take, without undue discrimination, production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, ETP’s businesses may be adversely affected.

ETP’s intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the TRRC. Texas gas utilities must publish the rates they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law unless challenged in a complaint.

ETP is subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations of state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.

Certain of ETP’s assets may become subject to regulation.

The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of extensive litigation and may be determined by the FERC on a case-by-case basis, although the FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.

Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. Lone Star’s NGL Pipeline transports NGLs within the state of Texas and is subject to regulation by the TRRC. This NGLs transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. In 2013, Lone Star’s NGL pipeline also commenced the interstate transportation of NGLs, which is subject to FERC’s jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992. Both intrastate and interstate NGL transportation services must be provided in a manner that is just, reasonable, and non-discriminatory. The tariff rates established for interstate services were based on a negotiated agreement; however, if FERC’s ratemaking methodologies were imposed, they may, among other things, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. In addition, the rates, terms and conditions for shipments of crude oil, petroleum products and NGLs on our pipelines are subject to regulation by FERC if the NGLs are transported in interstate or foreign commerce, whether by our pipelines or other means of transportation.

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Since we do not control the entire transportation path of all crude oil, petroleum products and NGLs on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

In addition, if any of our pipelines were found to have provided services or otherwise operated in violation of the NGA, NGPA, or ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC. Any of the foregoing could adversely affect revenues and cash flow related to these assets.

ETP may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

Pursuant to authority under the NGPSA and HLPSA, as amended, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect HCAs which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas.

These regulations require operators of covered pipelines to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline operations that could impact a high consequence area;

• improve data collection, integration and analysis;

• repair and remediate the pipeline as necessary; and

• implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Any changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, in January 2017, PHMSA issued a final rule for hazardous liquid pipelines that significantly expands the reach of certain PHMSA integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a HCA. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal Register is uncertain given the recent change in Presidential Administrations. In a second example, in April 2016, PHMSA published a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressure (“MOAP”); and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements and also require consideration of seismicity in evaluating threats to pipelines. The changes adopted or proposed by these rulemakings or made in future legal requirements could have a material adverse effect on ETP’s results of operations and costs of transportation services.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The NGPSA and HLPSA were amended by the 2011 Pipeline Safety Act. Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the MAOP of certain interstate natural gas transmission pipelines. Effective April 27, 2017, maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $209,002 per day, with a maximum of $2,090,022 for a series of violations. In June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural

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gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of natural gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as further amended by the 2016 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require ETP to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in ETP incurring increased operating costs that could be significant and have a material adverse effect on ETP’s results of operations or financial condition.

ETP’s business involves the generation, handling and disposal of hazardous substances, hydrocarbons and wastes, which activities are subject to environmental and worker health and safety laws and regulations that may cause ETP to incur significant costs and liabilities.

ETP’s business is subject to stringent federal, tribal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for the construction and operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit, or prevent emissions, discharges or releases of various materials from ETP’s pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from ETP’s construction and operations activities. Several governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective obligations, the occurrence of delays in permitting and completion of projects, and the issuance of injunctive relief. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or released, even under circumstances where the substances, hydrocarbons or wastes have been released by a predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property and natural resource damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or wastes into the environment.

ETP may incur substantial environmental costs and liabilities because of the underlying risk arising out of its operations. Although we have established financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased remediation costs, liabilities or natural resource damages that could substantially increase our costs for site remediation projects. Accordingly, we cannot assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.

Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on ETP’s operations or financial position. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the NAAQS for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the United States counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for the remaining areas of the United States not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to ETP’s customers’ operations. Compliance with this final rule or any other new regulations could, among other things, require installation of new emission controls on some of ETP’s equipment, result in longer permitting timelines or new restrictions or prohibitions with respect to permits or projects, and significantly increase its capital expenditures and operating costs, which could adversely impact its business. Historically, ETP has been able to satisfy the more stringent nitrogen oxide emission reduction requirements that affect its compressor units in ozone non-attainment areas at reasonable cost, but there is no assurance that it will not incur material costs in the future to meet the new, more stringent ozone standard.

Product liability claims and litigation could adversely affect our subsidiaries business and results of operations.

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.

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Along with other refiners, manufacturers and sellers of gasoline, Sunoco, Inc. is a defendant in numerous lawsuits that allege methyl tertiary butyl ether (“MTBE”) contamination in groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking compensatory damages (and in some cases injunctive relief, punitive damages and attorneys’ fees) for claims relating to the alleged manufacture and distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the plaintiffs’ legal theories or the facts that would be relevant to an analysis of the ultimate liability to Sunoco, Inc. An adverse determination of liability related to these allegations or other product liability claims against Sunoco, Inc. could have a material adverse effect on our business or results of operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the services we provide.

Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting "best available control technology" standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, the Subpart OOOOa standards have been subject to attempts by the EPA to stay portions of those standards, and the agency proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. This rule, should it remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to ETP’s operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect ETP’s business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the United States State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on ETP’s business, financial condition, demand for its services, results of operations, and cash flows. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded

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that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on ETP’s assets.

The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse effect on our ability to use derivative instruments to mitigate the risks of changes in commodity prices and interest rates and other risks associated with our business.

Provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and rules adopted by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other prudential regulators establish federal regulation of the physical and financial derivatives, including over-the-counter derivatives market and entities, such as us, participating in that market. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTC continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, any new regulations or modifications to existing regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability and/or liquidity of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

The CFTC has re-proposed speculative position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied. The CFTC has also finalized a related aggregation rule that requires market participants to aggregate their positions with certain other persons under common ownership and control, unless an exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position limits rule and its finalized companion rule on aggregation may create additional implementation or operational exposure. In addition to the CFTC federal speculative position limit regime, designated contract markets (“DCMs”) also maintain speculative position limit and accountability regimes with respect to contracts listed on their platform as well as aggregation requirements similar to the CFTC’s final aggregation rule. Any speculative position limit regime, whether imposed at the federal-level or at the DCM-level may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.

The Dodd-Frank Act requires that certain classes of swaps be cleared on a derivatives clearing organization and traded on a DCM or other regulated exchange, unless exempt from such clearing and trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The CFTC and prudential regulators have also adopted mandatory margin requirements for uncleared swaps entered into between swap dealers and certain other counterparties. We currently qualify for and rely upon an end-user exception from such clearing and margin requirements for the swaps we enter into to hedge our commercial risks. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirements to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.

In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.

A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail ETP’s operations and otherwise materially adversely affect their cash flow.

Some of ETP’s operations involve risks of personal injury, property damage and environmental damage, which could curtail its operations and otherwise materially adversely affect its cash flow. For example, natural gas pipeline and other facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Virtually all of ETP’s operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.

If one or more facilities that are owned by ETP or that deliver natural gas or other products to ETP are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by ETP’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s cash available for paying distributions to its Unitholders, including us.

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As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s financial position and results of operations, as applicable. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Terrorist attacks aimed at our facilities could adversely affect its business, results of operations, cash flows and financial condition.

The United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on ETP’s or Sunoco LP’s facilities or pipelines, those of their customers, or in some cases, those of other pipelines could have a material adverse effect on ETP’s or Sunoco LP’s business, financial condition and results of operations.

Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration and oil spill-response plans, and other related restrictions arising after the Deepwater Horizon incident in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

In recent years, the federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies of the United States Department of the Interior, have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.

In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional costs, delays, restrictions, or obligations with respect to oil and natural gas exploration and production operations conducted offshore by certain of ETP’s customers. For example, in April 2016, the BOEM published a proposed rule that would update existing air-emissions requirements relating to offshore oil and natural-gas activity on federal Outer Continental Shelf waters. However, in May 2017, Order 3350 was issued by the Department of the Interior Secretary Ryan Zinke, directing the BOEM to reconsider a number of regulatory initiatives governing oil and gas exploration in offshore waters, including, among other things, a cessation of all activities to promulgate the April 2016 proposed rulemaking (“Order 3350”). In an unrelated legal initiative, BOEM issued a Notice to Lessees and Operators (“NTL #2016-N01”) that became effective in September 2016 and imposes more stringent requirements relating to the provision of financial assurance to satisfy decommissioning obligations. Together with a recent re-assessment by BSEE in 2016 in how it determines the amount of financial assurance required, the revised BOEM-administered offshore financial assurance program that is currently being implemented is expected to result in increased amounts of financial assurance being required of operators on the OCS, which amounts may be significant. However, as directed under Order 3350, the BOEM has delayed implementation of NTL #2016-N01 so that it may reconsider this regulatory initiative and, currently, this NTL’s implementation timeline has been extended indefinitely beyond June 30, 2017, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. The April 2016 proposed rule and NTL #2016-N01, should they be finalized and/or implemented, as well as any new rules, regulations, or legal initiatives could delay or disrupt our customers operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, limit activities in certain areas, or cause our customers’ to incur penalties, or shut-in production or lease cancellation. Also, if material spill events were to occur in the future, the United States or other countries could elect to issue directives to temporarily cease drilling activities offshore and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development. The overall costs imposed on ETP’s customers to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete. We cannot predict with any certainty the full impact of any new laws or regulations on ETP’s customers’ drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. The occurrence of any one or more of these developments could result in decreased demand for ETP’s services, which could have a material adverse effect on its business as well as its financial position, results of operation and liquidity.

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Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.

The petroleum products that we store and transport through ETP’s operations are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

In addition, our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.

Our business could be affected adversely by union disputes and strikes or work stoppages by Panhandle’s and Sunoco LP’s unionized employees.

As of December 31, 2017, approximately 5% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that Panhandle or Sunoco, Inc. will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.

Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, have a significant impact on our retail marketing business.

Federally mandated standards for use of renewable biofuels, such as ethanol and biodiesel in the production of refined products, are transforming traditional gasoline and diesel markets in North America. These regulatory mandates present production and logistical challenges for both the petroleum refining and ethanol industries, and may require us to incur additional capital expenditures or expenses particularly in our retail marketing business. We may have to enter into arrangements with other parties to meet our obligations to use advanced biofuels, with potentially uncertain supplies of these new fuels. If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits. There also will be compliance costs related to these regulations. We may experience a decrease in demand for refined petroleum products due to new federal requirements for increased fleet mileage per gallon or due to replacement of refined petroleum products by renewable fuels. In addition, tax incentives and other subsidies making renewable fuels more competitive with refined petroleum products may reduce refined petroleum product margins and the ability of refined petroleum products to compete with renewable fuels. A structural expansion of production capacity for such renewable biofuels could lead to significant increases in the overall production, and available supply, of gasoline and diesel in markets that we supply. In addition, a significant shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel, or otherwise, also could lead to a decrease in demand, and reduced margins, for the refined petroleum products that we market and sell.

It is possible that any, or a combination, of these occurrences could have a material adverse effect on Sunoco, Inc.’s business or results of operations.

Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.

Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.

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Cybersecurity breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of our operations, damage to our reputation, and loss of confidence in our products and services, which could adversely affect our business.

Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-today operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.

The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results.

Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their employees. The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values, changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Partnership’s future consolidated financial results. While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged by the Partnership’s regulated businesses, the Partnership’s subsidiaries may not recover all of the costs and those rates are generally not immediately responsive to current market conditions or funding requirements. Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.

Mergers among customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced crude oil marketing margins or volumes.

Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of our systems in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.

The liquefaction project is dependent upon securing long-term contractual arrangements for the off-take of LNG on terms sufficient to support the financial viability of the project

LCL, an entity whose parent is owned60%by ETE and40%by ETP, is in the process of developing a liquefaction project at the site of ETE’s existing regasification facility in Lake Charles, Louisiana. The project development agreement previously entered into in September 2013 with BG Group plc (now "Shell") related to this project expired in February 2017.On June 28, 2017, LCL signed a memorandum of understanding with Korea Gas Corporation and Shell to study the feasibility of a joint development of the Lake Charles liquefaction project. The project would utilize existing dock and storage facilities owned by ETE located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia).  Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.

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The construction of the liquefaction project remains subject to further approvals and some approvals may be subject to further conditions, review and/or revocation.

While LCL has received authorization from the DOE to export LNG to non-FTA countries, the non-FTA authorization is subject to review, and the DOE may impose additional approval and permit requirements in the future or revoke the non-FTA authorization should the DOE conclude that such export authorization is inconsistent with the public interest.  The failure by LCL to timely maintain the approvals necessary to complete and operate the liquefaction project could have a material adverse effect on its operations and financial condition.

Sunoco LP is subject to federal laws related to the Renewable Fuel Standard.

New laws, new interpretations of existing laws, increased governmental enforcement of existing laws or other developments could require us to make additional capital expenditures or incur additional liabilities. For example, certain independent refiners have initiated discussions with the EPA to change the way the Renewable Fuel Standard (RFS) is administered in an attempt to shift the burden of compliance from refiners and importers to blenders and distributors. Under the RFS, which requires an annually increasing amount of biofuels to be blended into the fuels used by U.S. drivers, refiners/importers are obligated to obtain renewable identification numbers (“RINS”) either by blending biofuel into gasoline or through purchase in the open market. If the obligation was shifted from the importer/refiner to the blender/distributor, the Partnership would potentially have to utilize the RINS it obtains through its blending activities to satisfy a new obligation and would be unable to sell RINS to other obligated parties, which may cause an impact on the fuel margins associated with Sunoco LP’s sale of gasoline.

The occurrence of any of the events described above could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.

Sunoco LP is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it purchases, stores, transports, and sells to its distribution customers.

Various federal, state, and local government agencies have the authority to prescribe specific product quality specifications for certain commodities, including commodities that Sunoco LP distributes. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce Sunoco LP’s ability to procure product, require it to incur additional handling costs and/or require the expenditure of capital. If Sunoco LP is unable to procure product or recover these costs through increased selling price, it may not be able to meet its financial obligations. Failure to comply with these regulations could result in substantial penalties for Sunoco LP.

The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements.

Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to stockholders of corporations that are subject to all of the corporate governance requirements of the applicable stock exchange.

Tax Risks to Unitholders

Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat us, ETP or Sunoco LP as a corporation for federal income tax purposes or if we, ETP or Sunoco LP become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The value of our investments in ETP and Sunoco LP depend largely on ETP and Sunoco LP being treated as partnerships for federal income tax purposes. Despite the fact that we, ETP and Sunoco LP are each a limited partnership under Delaware law, we would each be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we, ETP and Sunoco LP satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us, ETP or Sunoco LP to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we, ETP or Sunoco LP were treated as a corporation, we would pay federal income tax at the corporate tax rate and we would likely pay additional state income taxes at varying rates. Distributions to Unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to Unitholders. Because a tax would then be imposed upon us as a corporation, our cash available for distribution to Unitholders would be substantially reduced. Therefore,

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treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Unitholders, likely causing a substantial reduction in the value of our Common Units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our Unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or to additional taxation as an entity for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing United States federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for United States federal income tax purposes.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for United States federal income tax purposes.

However, any modification to the United States federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for United States federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

If the IRS contests the federal income tax positions we take, the market for our Common Units may be adversely affected and the costs of any such contest will reduce cash available for distributions to our Unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by us reducing the cash available for distribution to our Unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our Unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each Unitholder and former Unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our Unitholders and former Unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current Unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such Unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our Unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

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Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which will be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.

Tax gain or loss on disposition of our Common Units could be more or less than expected.

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income the unitholder was allocated for a unit, which decreased their tax basis in that unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.

Investment in our units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to Unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be “unrelated business taxable income” and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.

Non-United States Unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.

Non-United States unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a United States trade or business.  As a result, distributions to a Non-United States unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-United States unitholder who sells or otherwise disposes of a unit will also be subject to United States federal income tax on the gain realized from the sale or disposition of that unit. 

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-United States unitholder’s sale or exchange of an interest in a partnership that is engaged in a United States trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges.  It is not clear if or when such regulations or other guidance will be issued.  Non-United States unitholders should consult a tax advisor before investing in our units.

We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

Even though we (as a partnership for United States federal income tax purposes) are not subject to United States federal income tax, some of our operations are conducted through subsidiaries that are organized as corporations for United States federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for United States federal income tax purposes, is subject to corporate-level United States federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

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We treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the Common Units.

Because we cannot match transferors and transferees of Common Units and because of other reasons, we have adopted depreciation, depletion and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our Unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units and could have a negative impact on the value of our Common Units or result in audit adjustments to tax returns of our Unitholders. Moreover, because we have subsidiaries that are organized as C corporations for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary having a greater tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our Unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, and if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.

A Unitholder whose units are the subject of a securities loan (e.g. a loan to a “short seller”) to cover a short sale of units may be considered as having disposed of those units. If so, the Unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a Unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the Unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the Unitholder and any cash distributions received by the Unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies in determining Unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain on the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

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Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.

In addition to federal income taxes, the Unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or our subsidiaries conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. We currently own property or conduct business in many states, most of which impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions. Further, Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, our unitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. Although the interest limitation does not apply to certain regulated pipeline businesses, application of the interest limitation to tiered businesses like ours that hold interests in regulated and unregulated businesses is not clear. Pending further guidance specific to this issue, we have not yet determined the impact the limitation could have on our unitholders’ ability to deduct our interest expense, but it is possible that our unitholders’ interest expense deduction will be limited.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

A description of our properties is included in “Item 1. Business.” In addition, we own office buildings for our executive offices in Dallas, Texas and office buildings in Newton Square, Pennsylvania and Houston, Corpus Christi and San Antonio, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.

We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.

Substantially all of our subsidiaries’ pipelines, which are described in “Item 1. Business,” are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. Our subsidiaries have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our subsidiaries’ pipelines were built were purchased in fee. ETP also owns and operates multiple natural gas and NGL storage facilities and owns or leases other processing, treating and conditioning facilities in connection with its midstream operations.

ITEM 3. LEGAL PROCEEDINGS

Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As ofDecember 31, 2017, Sunoco, Inc. is a defendant insevencases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico.

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The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Fourof these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland.

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. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

In January 2012, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. ETP also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of$100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas.  The proposed penalties are in excess of$100,000. The case went to hearing in November 2016 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows, or financial position.

In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of$100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

In December 2016, we received multiple Notice of Violations (“NOVs”) from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at our Marcus Hook Industrial Complex (“MHIC”) in July 2016. We also entered in a Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to our tank inspection plan at MHIC.These actions propose penalties in excess of$100,000, and we are currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these matters 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.

The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred during construction of the Rover pipeline project. The alleged violations include inadvertent returns of drilling muds and fluids at horizontal directional drilling (“HDD”) locations in Ohio that affected waters of the State, storm water control violations, improper disposal of spent drilling mud containing diesel fuel residuals, and open burning. The alleged violations occurred from April 2017 to July 2017.Although Rover has successfully completed clean-up mitigation for the alleged violations to Ohio EPA’s satisfaction, the Ohio EPA has proposed penalties of approximately$2.6 millionin connection with the alleged violations and is seeking certain injunctive relief. The Ohio Attorney General filed a complaint in the Court of Common Pleas of Stark County, Ohio to obtain these remedies and that case remains pending and is in the early stages. The timing or outcome of this matter cannot be reasonably

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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.

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 notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. In response, FERC authorized Rover to resume HDD activities at certain sites. On January 24, 2018, FERC ordered Rover to cease HDD activities at the Tuscarawas River HDD site pending FERC review of additional information from Rover. Rover continues to correspond with regulators regarding drilling operations and drilling plans at the HDD sites where Rover has not yet completed HDD activities, including the Tuscarawas River HDD site. The timing or outcome of this matter cannot be reasonably determined at this time. We do not expect there to be a material impact to its results of operations, cash flows or financial position.

In late 2016, FERC Enforcement Staff began a non-public investigation of Rover’s demolition of the Stoneman House, a potential historic structure, in connection with Rover’s application for permission to construct a new interstate natural gas pipeline and related facilities.  Rover and ETP are cooperating with the investigation.  In March and April 2017, Enforcement Staff provided Rover its non-public preliminary findings regarding its investigation.  The company disagrees with those findings and intends to vigorously defend against any potential penalty. Given the stage of the proceeding, and the non-public nature of the preliminary findings and investigation, ETP is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any.

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.  The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”).  On August 10, 2017 the parties reached a final settlement requiring 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.

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.

On January 18, 2018, PHMSA issued a NOPV and a Proposed Civil Penalty in connection with alleged violations on ETP’s East Boston jet fuel pipeline in Boston, MA. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

On January 18, PHMSA issued a NOPV and a PCO in connection with alleged violations on Eastern Area refined products and crude oil pipeline system in the States of MI, OH, PA, NY, NJ and DE. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

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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 environmental governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $100,000.

For a description of other legal proceedings, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Parent Company

Market Price of and Distributions on Common Units and Related Unitholder Matters

The Parent Company’s common units are listed on the NYSE under the symbol “ETE.” The following table sets forth, for the periods indicated, the high and low sales prices per ETE Common Unit, as reported on the NYSE Composite Tape, and the amount of cash distributions paid per ETE Common Unit for the periods indicated.

	Price Range				Cash Distribution (1)
	High		Low
Fiscal Year 2017:
Fourth Quarter	$	18.71	$	15.64	$	0.3050
Third Quarter	18.50		16.18		0.2950
Second Quarter	19.82		15.03		0.2850
First Quarter	20.05		17.62		0.2850
Fiscal Year 2016:
Fourth Quarter	$	19.99	$	13.77	$	0.2850
Third Quarter	19.44		13.45		0.2850
Second Quarter	15.13		6.40		0.2850
First Quarter	14.39		4.00		0.2850

⁽¹⁾  Distributions are shown in the quarter with respect to which they relate. Please see “Cash Distribution Policy” below for a discussion of our policy regarding the payment of distributions.

Description of Units

As of February 16, 2018, there were approximately 158,922 individual common unitholders, which includes common units held in street name. Common units represent limited partner interest in us that entitle the holders to the rights and privileges specified in the Parent Company’s Third Amended and Restated Agreement of Limited Partnership, as amended to date (the “Partnership Agreement”).

As of December 31, 2017, limited partners own an aggregate 94.4% limited partner interest in us. Our General Partner owns an aggregate 0.2% General Partner interest in us. Our common units are registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and are listed for trading on the NYSE. Each holder of a common unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all common units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The common units are entitled to distributions of Available Cash as described below under “Cash Distribution Policy.”

On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on

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a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.

The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $450 million carrying value as of December 31, 2017.

Cash Distribution Policy

General.  The Parent Company will distribute all of its “Available Cash” to its unitholders and its General Partner within 50 days following the end of each fiscal quarter.

Definition of Available Cash.Available Cash is defined in the Parent Company’s Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:

• provide for the proper conduct of its business;

• comply with applicable law and/or debt instrument or other agreement; and

• provide funds for distributions to unitholders and its General Partner in respect of any one or more of the next four quarters.

Recent Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

Securities Authorized for Issuance Under Equity Compensation Plans

For information on the securities authorized for issuance under ETE’s equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

ITEM 6.  SELECTED FINANCIAL DATA

The selected historical financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and accompanying notes thereto included elsewhere in this report. The amounts in the table below, except per unit data, are in millions.

As discussed in Note 2 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data,” in the fourth quarter of 2017, ETP changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories were changed from last-in, first-out (“LIFO”) method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.

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	Years Ended December 31,
	2017			2016*			2015*		2014*		2013*
Statement of Operations Data:
Total revenues	$	40,523		$	31,792		$	36,096	$	54,435	$	48,335
Operating income	2,713			1,843			2,287		2,389		1,587
Income from continuing operations	2,543			462			1,023		1,014		318
Income (loss) from discontinued operations	(177		)	(462		)	38		60		33
Net Income	2,366			—			1,061		1,010		351
Basic income from continuing operations per limited partner unit	0.86			0.95			1.11		0.57		0.17
Diluted income from continuing operations per limited partner unit	0.84			0.93			1.11		0.57		0.17
Basic income (loss) from discontinued operations per limited partner unit	(0.01		)	(0.01		)	—		0.01		0.01
Diluted income (loss) from discontinued operations per limited partner unit	(0.01		)	(0.01		)	—		0.01		0.01
Cash distribution per common unit	1.17			1.14			1.08		0.80		0.67
Balance Sheet Data (at period end):
Assets held for sale	3,313			3,588			3,681		3,372		—
Total assets(1)	86,246			78,925			71,144		64,266		50,367
Liabilities associated with assets held for sale	75			48			42		47		—
Long-term debt, less current maturities	43,671			42,608			36,837		29,477		22,562
Total equity	29,980			22,431			23,553		22,301		16,341

* As adjusted for the change in accounting policy related to inventory valuation, as discussed above.

⁽¹⁾  Includes assets held for sale

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

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

Energy Transfer Equity, L.P. is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ETE.” ETE was formed in September 2002 and completed its initial public offering in February 2006.

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. 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 “Item 1A. Risk Factors” of this report.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle, Sunoco LP and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

OVERVIEW

Energy Transfer Equity, L.P. directly and indirectly owns equity interests in ETP and Sunoco LP, both publicly traded master limited partnerships engaged in diversified energy-related services.

The historical common units for ETP presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger, discussed in “Item 1. Business.”

At January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.

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The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and the Partnership’s ownership of Lake Charles LNG. The Parent Company’s primary cash requirements are for distributions to its partners, general and administrative expenses, debt service requirements and at ETE’s election, capital contributions to ETP and Sunoco LP in respect of ETE’s general partner interests in ETP and Sunoco LP. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of subsidiaries.

In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.

General

Our primary objective is to increase the level of our distributable cash flow to our unitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and liquids businesses through, among other things, pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.

Our reportable segments are as follows:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the following:

• activities of the Parent Company; and

• the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Each of the respective general partners of ETP and Sunoco LP have separate operating management and boards of directors. We control ETP and Sunoco LP through our ownership of their respective general partners.

Recent Developments

ETE Senior Notes Offering

In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.

Sunoco LP Series A Preferred Units

On March 30, 2017, the Partnership purchased 12 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units was 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate would become a floating rate of 8.00% plus three-month LIBOR of the Liquidation Preference.

In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.

ETE January 2017 Private Placement and ETP Unit Purchase

In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units.

January 2018 Sunoco LP Common Units Repurchase

In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased17,286,859Sunoco 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.

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CDM Contribution Agreement

In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP 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)19,191,351common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately$335 million, (ii)6,397,965units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately$112 millionand (iii) an amount in cash equal to$1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions.

In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii)12,466,912USAC Common Units for cash consideration equal to$250 million.

ETP Credit Facilities

On December 1, 2017 ETP entered into a five-year, $4.0 billionunsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a$1.0 billion364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).

ETP Series A and Series B Preferred Units

In November 2017, ETP issued 950,000 of its 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units at a price of $1,000 per unit.

Distributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETP Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETP Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per ETP Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Distributions on the ETP Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETP Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETP Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per ETP Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETP Senior Notes Offering

In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility and for general partnership purposes.

ETP August 2017 Units Offering

In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

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Rover Contribution Agreement

In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a49.9%interest in the holding company that owns65%of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.

PennTex Tender Offer and Limited Call Right Exercise

In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.

ETP and Sunoco Logistics Merger

In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction, 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. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.

Sunoco LP Private Offering of Senior Notes

On January 23, 2018, Sunoco LP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in aggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the closing of the asset purchase agreement with 7-Eleven to: 1) redeem in full its existing senior notes as of December 31, 2017, comprised of $800 million in aggregate principal amount of 6.250% senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023; 2) repay in full and terminate the Sunoco LP Term Loan; 3) pay all closing costs and taxes in connection with the 7-Eleven transaction; 4) redeem the outstanding Sunoco LP Series A Preferred Units as mentioned above; and 5) repurchase 17,286,859 common units owned by ETP as mentioned above.

Sunoco LP Convenience Store Sale

On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”) and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven (“SEI Fuel” and together with 7-Eleven, referred to herein collectively as “Buyers”). Under the agreement, Sunoco LP sold a portfolio of approximately 1,030 company-operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of $3.3 billion.

Sunoco LP has signed definitive agreements with a commission agent to operate the approximately 207 retail sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the previously announced transaction with 7-Eleven, Inc. Conversion of these sites to the commission agent is expected to occur in the first quarter of 2018.

Sunoco LP Real Estate Sale

On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which will be operated by a commission agent.

Permian Express Partners

In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois

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terminal.Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including$547 millionof intangible assets and$435 millionof property, plant and equipment.

In July 2017, ETP contributed an approximate15%ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a100%membership interest, sold a49%interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for$2.00 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access and ETCO. The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

Results of Operations

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 (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.

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.

The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.

As discussed in Note 1 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data,” the merger of legacy ETP and legacy Sunoco Logistics in April 2017 resulted in legacy ETP being treated as the surviving entity from an accounting perspective. Accordingly, the financial data below related to our Investment in ETP reflects the consolidated financial information of legacy ETP.

As discussed in Note 2 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data,” in the fourth quarter of 2017, ETP changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories were changed from last-in, first-out (“LIFO”) method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.

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Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016

Consolidated Results

	Years Ended December 31,
	2017			2016*			Change
Segment Adjusted EBITDA:
Investment in ETP	$	6,712		$	5,733		$	979
Investment in Sunoco LP	732			665			67
Investment in Lake Charles LNG	175			179			(4		)
Corporate and other	(31		)	(170		)	139
Adjustments and eliminations	(268		)	(272		)	4
Total	7,320			6,135			1,185
Depreciation, depletion and amortization	(2,554		)	(2,216		)	(338		)
Interest expense, net of interest capitalized	(1,922		)	(1,804		)	(118		)
Gains on acquisitions	—			83			(83		)
Impairment losses	(1,039		)	(1,040		)	1
Losses on interest rate derivatives	(37		)	(12		)	(25		)
Non-cash unit-based compensation expense	(99		)	(70		)	(29		)
Unrealized gains (losses) on commodity risk management activities	59			(136		)	195
Inventory valuation adjustments	24			97			(73		)
Losses on extinguishments of debt	(89		)	—			(89		)
Impairment of investments in unconsolidated affiliates	(313		)	(308		)	(5		)
Equity in earnings of unconsolidated affiliates	144			270			(126		)
Adjusted EBITDA related to unconsolidated affiliates	(716		)	(675		)	(41		)
Adjusted EBITDA related to discontinued operations	(223		)	(199		)	(24		)
Other, net	155			79			76
Income from continuing operations before income tax benefit	710			204			506
Income tax benefit from continuing operations	(1,833		)	(258		)	(1,575		)
Income from continuing operations	2,543			462			2,081
Income (loss) from discontinued operations, net of income taxes	(177		)	(462		)	285
Net income	$	2,366		$	—		$	2,366

* As adjusted.

See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased primarily due to additional depreciation and amortization from assets recently placed in service.

Interest Expense, Net of Interest Capitalized. Interest expense increased primarily due to the following:

• an increase of $48 million of expense recognized by Sunoco LP primarily due to increased term loan borrowings and the issuance of senior notes;

• an increase of $48 million of expense recognized by ETP primarily due to recent debt issuances by ETP and its consolidated subsidiaries; and

• an increase of $20 million of expense recognized by the Parent Company primarily due to increased borrowings.

Gains on acquisitions. The Partnership recorded gains of $83 million in connection with recent acquisitions during 2016, including $41 million related to Sunoco Logistics’ acquisition of the remaining interest in SunVit.

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Impairment Losses. In 2017, ETP recorded goodwill impairments of $262 million related to its interstate transportation and storage operations, $79 million related to its NGL and refined products operations and $452 million related to its other operations. In 2016, ETP recorded goodwill impairments of $638 million related to its interstate transportation and storage operations and $32 million related to its midstream operations. These goodwill impairments were primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve.

In 2017, Sunoco LP recognized goodwill impairment of $387 million, of which $102 million was allocated to continuing operations. In 2016, Sunoco LP recognized goodwill impairments of $641 million, of which $227 million was allocated to continuing operations. These goodwill impairments were due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.

In addition, impairment losses also include $127 million and $133 million impairments to property, plant and equipment in ETP’s interstate transportation and storage operations in 2017 and 2016, respectively, due to decreases in projected future cash flows as well as a $10 million impairment to property, plant and equipment in ETP’s midstream operations in 2016.

Losses on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives during the year ended December 31, 2017 and 2016 resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See discussion of the unrealized gains (losses) on commodity risk management activities included in the discussion of segment results below.

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP and ETP’s NGL and refined products and transportation services operations as a result of commodity price changes between periods.

Impairment of Investments in Unconsolidated Affiliates. During the year ended December 31, 2017, ETP recorded impairments to its investments in FEP of $141 million and HPC of $172 million. During the year ended December 31, 2016, ETP recorded an impairment to its investment in MEP of $308 million. Additional discussion on these impairments is included in “Estimates and Critical Accounting Policies” below.

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

Other, net. Other, net in 2017 and 2016 primarily includes amortization of regulatory assets and other income and expense amounts.

Income Tax Benefit.On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from35% to21%for taxable years beginning afterDecember 31, 2017. As a result, the Partnership recognized a deferred tax benefit of$1.81 billionin December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

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Segment Operating Results

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.

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

	Years Ended December 31,
	2017			2016
Investment in ETP	$	8,253		$	6,747
Investment in Sunoco LP	1,108			1,156
Investment in Lake Charles LNG	197			197
Adjustments and eliminations	(1		)	(1		)
Total segment margin	9,557			8,099
Less:
Operating expenses	2,644			2,307
Depreciation, depletion and amortization	2,554			2,216
Selling, general and administrative	607			693
Impairment losses	1,039			1,040
Operating income	$	2,713		$	1,843

Investment in ETP

	Years Ended December 31,
	2017			2016			Change
Revenues	$	29,054		$	21,827		$	7,227
Cost of products sold	20,801			15,080			5,721
Segment margin	8,253			6,747			1,506
Unrealized (gains) losses on commodity risk management activities	(56		)	131			(187		)
Operating expenses, excluding non-cash compensation expense	(2,103		)	(1,841		)	(262		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(392		)	(351		)	(41		)
Adjusted EBITDA related to unconsolidated affiliates	984			946			38
Other, net	26			101			(75		)
Segment Adjusted EBITDA	$	6,712		$	5,733		$	979

Segment Adjusted EBITDA. For the year ended December 31, 2017 compared to the prior year, Segment Adjusted EBITDA related to the Investment in ETP increased primarily as a result of the following:

• an increase of $13 million in ETP’s intrastate transportation and storage operations resulting from an increase of $74 million due to higher realized gains from pipeline optimization activity and an increase of $10 million in retained fuel sales. These increases were offset by a $57 million decrease in transportation fees due to renegotiated contracts and an $11 million decrease in storage margin;

• an increase of $348 million in ETP’s midstream operations primarily due to a $210 million increase in non-fee based margins (excluding changes in unrealized gains and losses) due to higher realized crude oil and NGL prices and volume increases and a $144 million increase in fee-based revenues due to minimum volume commitments in South Texas, increased volumes in

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the Permian and Northeast regions, and recent acquisitions, including PennTex; these increases in gross margin were partially offset by increases in operating expenses of $17 million due to recent acquisitions, including PennTex.

• an increase of $145 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation margin of $124 million, primarily due to higher volumes on Texas NGL pipelines and the ramp-up of volumes on the Mariner East system; an increase in fractionation and refinery services margin of $84 million, primarily due to higher NGL volumes from most major producing regions; and an increase in terminal services margin of $29 million due to a $43 million increase from higher throughput volumes on the Marcus Hook and Nederland NGL terminals offset by lower refined products terminal throughput and the sale of one of ETP’s refined product terminals in April 2017; partially offset by a decrease of $54 million in marketing margin (excluding changes in unrealized gains of $95 million) primarily due to the timing of the recognition of margin from optimization activities; an increase of $37 million in operating expenses primarily due to increased utilities costs associated with ETP’s fourth fractionator at Mont Belvieu and the Mariner project ramp up at the Marcus Hook Industrial Complex and an increase in general and administrative expenses of $8 million due to higher allocations; and

• an increase of $545 million in ETP’s crude oil transportation and services operations due to an increase of $724 million resulting primarily from placing ETP’s Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas; an increase of $90 million from existing assets due to increased volumes throughout the system; and an increase of $16 million from increased throughput fees, and tank rentals, primarily from increased activity at ETP’s Nederland, Texas crude terminal; partially offset by an increase in operating expenses as a result of placing new projects in service and costs associated with increased volumes on the system; partially offset by a decrease of $78 million in margin from ETP’s crude oil acquisition and marketing business resulting from less favorable market price spreads particularly in the first three quarters of 2017; an increase of $183 million in operating expenses primarily due to placing the Bakken Pipeline in service; and an increase of $24 million in selling, general and administrative expenses primarily due to merger fees and legal and environmental reserves; partially offset by

• a decrease of $19 million in ETP’s interstate transportation and storage operations primarily due to a decrease in reservation revenues of $45 million on the Panhandle, Trunkline, and Transwestern pipelines, a decrease of $17 million in gas parking service related revenues on the Panhandle and Trunkline pipelines primarily due to lack of customer demand resulting from weak spreads, a decrease of $19 million in revenues on the Tiger pipeline due to contract restructuring, and a decrease of $5 million on the Sea Robin pipeline due to producer maintenance and production declines. These decreases were partially offset by $55 million of incremental revenues from the placement in partial service of the Rover pipeline effective August 31, 2017, a $6 million dollar decrease in operating expenses and $4 million increase in adjusted EBITDA from unconsolidated affiliates; and

• a decrease of $53 million in ETP’s all other operations due to a decrease of $90 million related to the termination of management fees paid by ETE that ended in 2016; a decrease of $31 million from the mark-to-market of physical system gas and settled derivative; and an increase of $17 million in transaction related expenses; partially offset by an increase of $33 million in Adjusted EBITDA related to ETP’s investment in PES; a one-time fee of $15 million received from a joint venture affiliate; an increase of $20 million in crude and power trading activates, primarily from the liquidation of crude inventories; and a decrease of $11 million in expenses related to ETP’s compression business.

Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the years ended December 31, 2017 and 2016 consisted of the following:

	Years Ended December 31,
	2017		2016		Change
Citrus	$	336	$	329	$	7
FEP	74		75		(1		)
MEP	88		90		(2		)
HPC	46		61		(15		)
Sunoco LP	268		271		(3		)
Other	172		120		52
Total Adjusted EBITDA related to unconsolidated affiliates	$	984	$	946	$	38

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

Investment in Sunoco LP

	Years Ended December 31,
	2017			2016			Change
Revenues	$	11,723		$	9,986		$	1,737
Cost of products sold	10,615			8,830			1,785
Segment margin	1,108			1,156			(48		)
Unrealized (gains) losses on commodity risk management activities	(3		)	5			(8		)
Operating expenses, excluding non-cash compensation expense	(456		)	(455		)	(1		)
Selling, general and administrative, excluding non-cash compensation expense	(116		)	(142		)	26
Inventory fair value adjustments	(24		)	(98		)	74
Adjusted EBITDA from discontinued operations	223			199			24
Segment Adjusted EBITDA	$	732		$	665		$	67

The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. The segment results above are presented on the same basis as Sunoco LP’s standalone financial statements; therefore, the segment results above also include MACS, Sunoco, LLC, Susser and Sunoco Retail LLC beginning September 1, 2014. MACS, Sunoco, LLC, Susser and Sunoco Retail LLC were also consolidated by ETP until October 2014, April 2015, July 2015 and March 2016, respectively; therefore, the results from those entities are reflected in both the Investment in ETP and the Investment in Sunoco LP segments for the respective periods in 2014 and 2015. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.

Segment Adjusted EBITDA. For the year ended December 31, 2017 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP increased primarily as a result of the following:

• an increase of $18 million in gross margin (excluding a $74 million change in fair value adjustments related to inventory and unrealized gains and losses on commodity risk management activities) primarily caused by an increase in wholesale motor fuel gross profit per gallon, partially offset by a net increase in other gross profit consisting of merchandise, rental & other and retail motor fuel of $13 million;

• a decrease of $26 million in general and administrative expenses primarily due to higher costs in 2016 related to relocation, employee termination, and higher contract labor and professional fees as the Partnership transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas to Dallas during 2016; and

• an increase of $24 million related to discontinued operations; offset by

• an increase of $1 million in other operating expenses primarily attributable to Sunoco LP’s retail business which has expanded through third-party acquisitions as well as through the construction of new-to-industry sites.

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Investment in Lake Charles LNG

	Years Ended December 31,
	2017			2016			Change
Revenues	$	197		$	197		$	—
Operating expenses, excluding non-cash compensation expense	(19		)	(16		)	(3		)
Selling, general and administrative, excluding non-cash compensation expense	(3		)	(2		)	(1		)
Segment Adjusted EBITDA	$	175		$	179		$	(4	)

Lake Charles LNG derives all of its revenue from a contract with a non-affiliated gas marketer.

Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015

Consolidated Results

	Years Ended December 31,
	2016*			2015*			Change
Segment Adjusted EBITDA:
Investment in ETP	$	5,733		$	5,517		$	216
Investment in Sunoco LP	665			719			(54		)
Investment in Lake Charles LNG	179			196			(17		)
Corporate and other	(170		)	(104		)	(66		)
Adjustments and eliminations	(272		)	(590		)	318
Total	6,135			5,738			397
Depreciation, depletion and amortization	(2,216		)	(1,951		)	(265		)
Interest expense, net of interest capitalized	(1,804		)	(1,622		)	(182		)
Gain on acquisitions	83			—			83
Impairment losses	(1,040		)	(339		)	(701		)
Losses on interest rate derivatives	(12		)	(18		)	6
Non-cash compensation expense	(70		)	(91		)	21
Unrealized losses on commodity risk management activities	(136		)	(65		)	(71		)
Inventory valuation adjustments	97			(67		)	164
Losses on extinguishments of debt	—			(43		)	43
Impairment of investment in unconsolidated affiliate	(308		)	—			(308		)
Equity in earnings of unconsolidated affiliates	270			276			(6		)
Adjusted EBITDA related to unconsolidated affiliates	(675		)	(713		)	38
Adjusted EBITDA related to discontinued operations	(199		)	(228		)	29
Other, net	79			23			56
Income from continuing operations before income tax expense	204			900			(696		)
Income tax expense (benefit) from continuing operations	(258		)	(123		)	(135		)
Income from continuing operations	462			1,023			(561		)
Income (loss) from discontinued operations, net of income taxes	(462		)	38			(500		)
Net income	$	—		$	1,061		$	(1,061	)

* As adjusted.

See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased primarily due to additional depreciation and amortization from assets recently placed in service.

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Interest Expense, Net of Interest Capitalized. Interest expense increased primarily due to the following:

• an increase of $94 million of expense recognized by Sunoco LP primarily due to increased term loan borrowings, the issuance of senior notes and an increase in borrowings under the Sunoco LP revolving credit facility;

• an increase of $33 million of expense recognized by the Parent Company primarily related to the May 2015 issuance of $1 billion aggregate principal amount of its 5.5% senior notes; and

• an increase of $53 million of expense recognized by ETP (excluding interest expense related to Sunoco LP for the period prior to ETP’s deconsolidation of Sunoco LP on July 1, 2015) primarily due to recent debt issuances by ETP and its consolidated subsidiaries.

Gains on acquisitions. The Partnership recorded gains of $83 million in connection with recent acquisitions during 2016, including $41 million related to Sunoco Logistics’ acquisition of the remaining interest in SunVit.

Impairment Losses. In 2016, ETP recorded goodwill impairments of $638 million related to its interstate transportation and storage operations and $32 million related to its midstream operations. These goodwill impairments were primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. Sunoco LP recognized goodwill impairments of $641 million, of which $227 million was allocated to continuing operations, primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. In addition, impairment losses for 2016 also include a $133 million impairment to property, plant and equipment in ETP’s interstate transportation and storage operations due to a decrease in projected future cash flows as well as a $10 million impairment to property, plant and equipment in ETP’s midstream operations. In 2015, ETP recorded impairments of (i) $99 million related to Transwestern due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, (ii) $106 million related to Lone Star Refinery Services due primarily to changes in assumptions related to potential future revenues as well as the market declines in current and expected future commodity prices, (iii) $110 million of fixed asset impairments related to Lone Star NGL Refinery Services primarily due to the economic obsolescence identified as a result of low utilization and expected decrease in future cash flows, and (iv) $24 million of intangible asset impairments related to Lone Star NGL Refinery Services primarily due to the economic obsolescence identified as a result of expected decrease in future cash flows.

Losses on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives during the year ended December 31, 2016 and 2015 resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value.

Unrealized Losses on Commodity Risk Management Activities. See discussion of the unrealized gains (losses) on commodity risk management activities included in the discussion of segment results below.

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP and ETP’s NGL and refined products and transportation services operations as a result of commodity price changes between periods.

Impairment of Investment in Unconsolidated Affiliate. In 2016, the Partnership impaired its investment in MEP and recorded a non-cash impairment loss of $308 million based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates.

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

Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that is classified as held for sale.

Other, net. Other, net in 2016 and 2015 primarily includes amortization of regulatory assets and other income and expense amounts.

Income Tax Benefit. For the years ended December 31, 2016 and 2015, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries. The year ended December 31, 2015 also reflected a benefit of $24 million of net state tax benefit attributable to statutory state rate changes resulting from the Regency Merger and sale of Susser to Sunoco LP, as well as a favorable impact of $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015.

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Segment Operating Results

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

	Years Ended December 31,
	2016			2015
Investment in ETP	$	6,747		$	7,578
Investment in Sunoco LP	1,156			980
Investment in Lake Charles LNG	197			216
Adjustments and eliminations	(1		)	(1,346		)
Total segment margin	8,099			7,428
Less:
Operating expenses	2,307			2,303
Depreciation, depletion and amortization	2,216			1,951
Selling, general and administrative	693			548
Impairment losses	1,040			339
Operating income	$	1,843		$	2,287

Investment in ETP

	Years Ended December 31,
	2016			2015			Change
Revenues	$	21,827		$	34,292		$	(12,465	)
Cost of products sold	15,080			26,714			(11,634		)
Segment margin	6,747			7,578			(831		)
Unrealized losses on commodity risk management activities	131			65			66
Operating expenses, excluding non-cash compensation expense	(1,841		)	(2,621		)	780
Selling, general and administrative expenses, excluding non-cash compensation expense	(351		)	(482		)	131
Inventory valuation adjustments	—			(58		)	58
Adjusted EBITDA related to unconsolidated affiliates	946			937			9
Other, net	101			98			3
Segment Adjusted EBITDA	$	5,733		$	5,517		$	216

Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA related to the Investment in ETP increased primarily as a result of the following:

• an increase of $70 million on ETP’s intrastate transportation and storage operations driven by $34 million in natural gas sales (excluding changes in unrealized losses of $17 million) primarily due to higher realized gains from the buying and selling of gas along ETP’s system and an increase of $37 million in storage margin (excluding net changes in unrealized amounts of $28 million related to fair value inventory adjustments and unrealized gains and losses on derivatives);

• an increase of $317 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation and terminal margin of $239 million primarily due to the ramp-up of several organic growth projects as well as increased volumes from all producing regions; an increase in fractionation and refinery services margin of $118 million (excluding unrealized gains and losses) primarily due to higher NGL volumes from most major producing regions; an increase in storage margin of $36 million primarily due to increased volumes from ETP’s Mont Belvieu fractionators; partially offset by a decrease in marketing margin of $42 million (excluding net changes in unrealized gains and losses of $50 million) primarily due to lower spreads, the timing of withdrawals, and the timing of the recognition of margin from optimization activities; partially offset by an increase of $33 million in operating expenses primarily due to increased costs associated with

88

organic growth projects such as our third fractionator in Mont Belvieu,Texas, Mariner East 1, Mariner South and Allegheny Access; and

• an increase of $313 million in ETP’s crude oil transportation and services operations due to an increase of $158 million resulting primarily from placing our Permian Express II pipeline in service in the third quarter of 2015, as well as the acquisition of a crude oil gathering system in West Texas; an increase of $49 million from existing assets due to increased volumes throughout the system; an increase of $31 million from our crude terminals assets, largely related to the Nederland facility; and an increase of $74 million from our crude oil acquisition and marketing activity; offset by an increase of $5 million in selling, general and administrative expenses; partially offset by

• a decrease $38 million in ETP’s interstate transportation and storage operations caused by a $56 million decrease in revenues primarily caused by contract restructuring on the Tiger pipeline, lower reservation revenues on the Panhandle and Trunkline pipelines, lower sales of capacity in the Phoenix and San Juan areas on the Transwestern pipeline, the transfer of one of the Trunkline pipelines which was repurposed from natural gas service to crude oil service, the expiration of a transportation rate schedule on the Transwestern pipeline, and declines in production and third-party maintenance on the Sea Robin pipeline, partially offset by higher reservation revenues on the Transwestern pipeline and higher parking revenues on the Panhandle and Trunkline pipelines;

• a decrease of $104 million in ETP’s midstream operations due to decreases in gathered volumes primarily due to declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions, partially offset by increases in the Permian region and the impact of recent acquisitions, including PennTex; and

• a decrease of $308 million due to the transfer and contribution of ETP’s retail marketing assets to Sunoco LP. The consolidated results of Sunoco LP are reflected in the results for ETP’s all other above through June 2015. Effective July 1, 2015, Sunoco LP was deconsolidated, and the results for all other reflect adjusted EBITDA related to unconsolidated affiliates for ETP’s limited partner interests in Sunoco LP. The impact of the deconsolidation of Sunoco LP reduced segment margin, operating expenses and selling, general and administrative expenses; the impact to segment adjusted EBITDA is offset by the incremental adjusted EBITDA related to unconsolidated affiliates from ETP’s equity method investment in Sunoco LP subsequent to the deconsolidation; and

• a decrease of $76 million in adjusted EBITDA related to ETP’s investment in PES.

Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the years ended December 31, 2016 and 2015 consisted of the following:

	Years Ended December 31,
	2016		2015		Change
Citrus	$	329	$	315	$	14
FEP	75		75		—
MEP	90		96		(6		)
HPC	61		61		—
Sunoco, LLC	—		91		(91		)
Sunoco LP	271		137		134
Other	120		162		(42		)
Total Adjusted EBITDA related to unconsolidated affiliates	$	946	$	937	$	9

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

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Investment in Sunoco LP

	Years Ended December 31,
	2016			2015			Change
Revenues	$	9,986		$	12,430		$	(2,444	)
Cost of products sold	8,830			11,450			(2,620		)
Segment margin	1,156			980			176
Unrealized losses on commodity risk management activities	5			2			3
Operating expenses, excluding non-cash compensation expense	(455		)	(451		)	(4		)
Selling, general and administrative, excluding non-cash compensation expense	(142		)	(118		)	(24		)
Inventory fair value adjustments	(98		)	78			(176		)
Adjusted EBITDA from discontinued operations	199			228			(29		)
Segment Adjusted EBITDA	$	665		$	719		$	(54	)

The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. Sunoco LP obtained control of MACS in October 2014, Sunoco, LLC in April 2015, Susser in July 2015, and Sunoco Retail LLC in March 2016. Because these entities were under common control, Sunoco LP recast its financial statements to retrospectively consolidate each of the entities beginning September 1, 2014. The segment results above are presented on the same basis as Sunoco LP’s standalone financial statements; therefore, the segment results above also include MACS, Sunoco, LLC, Susser and Sunoco Retail LLC beginning September 1, 2014. MACS, Sunoco, LLC, Susser and Sunoco Retail LLC were also consolidated by ETP until October 2014, April 2015, July 2015 and March 2016, respectively; therefore, the results from those entities are reflected in both the Investment in ETP and the Investment in Sunoco LP segments for the respective periods in 2014 and 2015. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.

Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP decreased primarily as a result of the following:

• a change of $176 million in the fair value adjustment to inventory resulting from changes in fuels prices during the year ended December 31, 2016;

• a decrease of $29 million related to Sunoco LP’s retail operations that have been classified as discontinued operations;

• an increase of $24 million in general and administrative expenses primarily due to $18 million for the transition of employees from Houston, Texas, Corpus Christi, Texas and Philadelphia, Pennsylvania to Dallas, Texas, with the remaining increase due to higher professional fees and other administrative expenses; partially offset by

• an increase of $176 million in segment margin primarily caused by an increase in wholesale motor fuel gross profit of $212 million due to a 28.7%, or $0.55, decrease in the cost per wholesale motor fuel gallon, offset by a decrease in the gross profit on retail motor fuel of $37 million.

Investment in Lake Charles LNG

	Years Ended December 31,
	2016			2015			Change
Revenues	$	197		$	216		$	(19	)
Operating expenses, excluding non-cash compensation expense	(16		)	(17		)	1
Selling, general and administrative, excluding non-cash compensation expense	(2		)	(3		)	1
Segment Adjusted EBITDA	$	179		$	196		$	(17	)

Lake Charles LNG derives all of its revenue from a contract with a non-affiliated gas marketer.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The amount of cash that ETP and Sunoco LP distribute to their respective partners, including the Parent Company, each quarter is based on earnings from their respective business activities and the amount of available cash, as discussed below. In connection with previous transactions, we have relinquished a portion of our incentive distributions to be received from ETP and Sunoco LP, see additional discussion under “Cash Distributions.”

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company currently expects to fund its short-term needs for such items with cash flows from its direct and indirect investments in ETP, Sunoco LP and Lake Charles LNG. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.

The Parent Company expects ETP, Sunoco LP and Lake Charles LNG and their respective subsidiaries to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as it deems prudent to provide liquidity for new capital projects of its subsidiaries or for other partnership purposes.

ETP

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 the control of ETP’s management.

ETP currently expects capital expenditures in 2018 to be within the following ranges:

	Growth				Maintenance
	Low		High		Low		High
Intrastate transportation and storage	$	225	$	250	$	30	$	35
Interstate transportation and storage (1)	450		500		115		120
Midstream	750		800		120		130
NGL and refined products transportation and services	2,425		2,475		65		75
Crude oil transportation and services (1)	425		525		90		100
All other (including eliminations)	75		100		60		65
Total capital expenditures	$	4,350	$	4,650	$	480	$	525
Less: Project level non-recourse financing	—		—		—		—
Partnership level capital funding	$	4,350	$	4,650	$	480	$	525

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

The assets used in ETP’s 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, ETP does not have any significant financial commitments for maintenance capital expenditures in its businesses. From time to time ETP experiences 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, ETP includes these factors in its anticipated growth capital expenditures for each year.

ETP generally funds maintenance capital expenditures and distributions with cash flows from operating activities. ETP generally funds growth capital expenditures with proceeds of borrowings under credit facilities, long-term debt, the issuance of additional Common Units or a combination thereof.

As of December 31, 2017, in addition to $306 million of cash on hand, ETP had available capacity under the ETP Credit Facilities of $2.51 billion. Based on ETP’s current estimates, it expects to utilize capacity under the ETP Credit Facilities, along with cash

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from operations, to fund its announced growth capital expenditures and working capital needs through the end of 2018; however, ETP may issue debt or equity securities prior to that time as it deems prudent to provide liquidity for new capital projects, to maintain investment grade credit metrics or other partnership purposes.

Sunoco LP

Sunoco LP’s primary sources of liquidity consist of cash generated from operating activities, borrowings under its $1.50 billion credit facility and the issuance of additional long-term debt or partnership units as appropriate given market conditions. At December 31, 2017, Sunoco LP had available borrowing capacity of $726 million under its revolving credit facility and $28 million of cash and cash equivalents on hand.

In 2018, Sunoco LP expects to invest approximately $90 million in growth capital expenditures and approximately $40 million on maintenance capital expenditures. Sunoco LP may revise the timing of these expenditures as necessary to adapt to economic conditions.

Cash Flows

Our cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price of our subsidiaries’ 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 acquisition of assets, while changes in non-cash unit-based 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 ETP has 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 price risk management assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.

Following is a summary of operating activities by period:

Year Ended December 31, 2017

Cash provided by operating activities in 2017 was $4.43 billion and net income was $2.37 billion. The difference between net income and cash provided by operating activities in 2017 primarily consisted of net non-cash items totaling $1.78 billion and changes in operating assets and liabilities of $192 million. The non-cash activity in 2017 consisted primarily of depreciation, depletion and amortization of $2.55 billion, impairment lossesof$1.35 billion, deferred income tax benefit of$1.87 billion, inventory valuation adjustments of$24 million, losses on extinguishments of debt of $89 millionand non-cash compensation expense of$99 million.

Year Ended December 31, 2016

Cash provided by operating activities in 2016 was $3.32 billion and net income was $0 million. The difference between net income and cash provided by operating activities in 2016 primarily consisted of net non-cash items totaling $2.77 billion and changes in operating assets and liabilities of $179 million. The non-cash activity in 2016 consisted primarily of depreciation, depletion and amortization of $2.22 billion, impairment losses of $1.35 billion, deferred income tax benefit of $177 million, inventory valuation adjustments of $97 million and non-cash compensation expense of $70 million.

Year Ended December 31, 2015

Cash provided by operating activities in 2015 was $2.98 billion and net income was $1.06 billion. The difference between net income and cash provided by operating activities in 2015 primarily consisted of net non-cash items totaling $2.42 billion and changes in operating assets and liabilities of $0.87 billion. The non-cash activity in 2015 consisted primarily of depreciation, depletion and amortization of $1.95 billion, impairment losses of $339 million, deferred income tax expense of $239 million,

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inventory valuation adjustments of $67 million, losses on extinguishments of debt of $43 million and non-cash compensation expense of $91 million.

Investing Activities

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

Following is a summary of investing activities by period:

Year Ended December 31, 2017

Cash used in investing activities in 2017 of $5.61 billion was comprised primarily of capital expenditures of $8.41 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $5.47 billion for growth capital expenditures and $429 million for maintenance capital expenditures during 2017. We paid net cash for acquisitions of $303 million, including the acquisition of a noncontrolling interest.

Year Ended December 31, 2016

Cash used in investing activities in 2016 of $8.98 billion was comprised primarily of capital expenditures of $7.70 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $5.44 billion for growth capital expenditures and $368 million for maintenance capital expenditures during 2016. We paid net cash for acquisitions of $1.40 billion, including the acquisition of a noncontrolling interest.

Year Ended December 31, 2015

Cash used in investing activities in 2015 of $9.74 billion was comprised primarily of capital expenditures of $8.99 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $7.68 billion for growth capital expenditures and $485 million for maintenance capital expenditures during 2015. We paid net cash for acquisitions of $842 million, including the acquisition of a noncontrolling interest.

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 acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate.

Following is a summary of financing activities by period:

Year Ended December 31, 2017

Cash provided by financing activities was $953 million in 2017. We had a consolidated increase in our debt level of $340 million, primarily due to the issuance of Parent Company and subsidiary senior notes, as well as increases in our revolving credit facilities during 2015. Our subsidiaries also received $3.24 billion in proceeds from common unit offerings, including $2.28 billion from the issuance of ETP Common Units and $952 million from the issuance of other subsidiary common units. We paid distributions to partners of $1.01 billion, and our subsidiaries paid $2.96 billion on limited partner interests other than those held by the Parent Company.

Year Ended December 31, 2016

Cash provided by financing activities was $5.93 billion in 2016. We had a consolidated increase in our debt level of $6.71 billion, primarily due to the issuance of Parent Company and subsidiary senior notes, as well as increases in our revolving credit facilities during 2015. Our subsidiaries also received $2.56 billion in proceeds from common unit offerings, including $1.10 billion from the issuance of ETP Common Units and $1.46 billion from the issuance of other subsidiary common units. We paid distributions to partners of $1.02 billion, and our subsidiaries paid $2.77 billion on limited partner interests other than those held by the Parent Company.

Year Ended December 31, 2015

Cash provided by financing activities was $6.79 billion in 2015. We had a consolidated increase in our debt level of $6.63 billion, primarily due to the issuance of Parent Company and subsidiary senior notes, as well as increases in our revolving credit facilities during 2015. Our subsidiaries also received $3.89 billion in proceeds from common unit offerings, including $1.43 billion from

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the issuance of ETP Common Units and $2.46 billion from the issuance of other subsidiary common units. We paid distributions to partners of $1.09 billion, and our subsidiaries paid $2.34 billion on limited partner interests other than those held by the Parent Company. We also paid $1.06 billion to repurchase common units during the year ended December 31, 2015.

Discontinued Operations

Following is a summary of activities related to discontinued operations by period:

Year Ended December 31, 2017

Cash provided by discontinued operations was $93 million for the year ended December 31, 2017 resulting from cash provided by operating activities of $136 million, cash used in investing activities of $38 million and changes in cash included in current assets held for sale of $5 million.

Year Ended December 31, 2016

Cash used in discontinued operations was $385 million for the year ended December 31, 2016 resulting from cash provided by operating activities of $93 million, cash used in investing activities of $483 million and changes in cash included in current assets held for sale of $5 million.

Year Ended December 31, 2015

Cash used in discontinued operations was $283 million for the year ended December 31, 2015 resulting from cash provided by operating activities of $90 million, cash used in investing activities of $360 million and changes in cash included in current assets held for sale of $13 million.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

	December 31,
	2017			2016
Parent Company Indebtedness:
ETE Senior Notes due October 2020	$	1,187		$	1,187
ETE Senior Notes due January 2024	1,150			1,150
ETE Senior Notes due June 2027	1,000			1,000
ETE Senior Notes due March 2023	1,000			—
ETE Senior Secured Term Loan due December 2, 2019	—			2,190
ETE Senior Secured Term Loan due February 2, 2024	1,220			—
ETE Senior Secured Revolving Credit Facility due December 18, 2018	—			875
ETE Senior Secured Revolving Credit Facility due March 24, 2022	1,188			—
Subsidiary Indebtedness:
ETP Senior Notes	27,005			24,855
Panhandle Senior Notes	785			1,085
Sunoco, Inc. Senior Notes	—			400
Transwestern Senior Notes	575			657
Sunoco LP Senior Notes, Term Loan and lease-related obligations	3,556			3,561
Credit Facilities and Commercial Paper:
ETP $4.0 billion Revolving Credit Facility due December 2022	2,292			—
ETP $1.0 billion 364-Day Credit Facility due November 2018 (1)	50			—
ETLP $3.75 billion Revolving Credit Facility due November 2019	—			2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020	—			1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017	—			630
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019	765			1,000
Bakken Project $2.50 billion Credit Facility due August 2019	2,500			1,100
PennTex $275 million MLP Revolving Credit Facility due December 2019	—			168
Other long-term debt	8			31
Unamortized premiums and fair value adjustments, net	50			101
Deferred debt issuance costs	(247		)	(257		)
Total debt	44,084			43,802
Less: current maturities of long-term debt	413			1,194
Long-term debt, less current maturities	$	43,671		$	42,608

⁽¹⁾  Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.

The terms of our consolidated indebtedness and our subsidiaries are described in more detail below and in Note 6 to our consolidated financial statements.

Senior Notes and Term Loan

Energy Transfer Equity, L.P. Senior Notes Offering 

In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes.

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ETE Term Loan Facility

On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof. In connection with the Parent Company’s entry into the Senior Secured Term Loan Agreement on February 2, 2017, the Parent Company terminated its previous term loan agreements.

Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP , and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP, and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.

Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.

On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.

In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.

Sunoco LP Term Loan

Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As ofDecember 31, 2017, the balance on the term loan was $1.24 billion.

The Sunoco LP term loan was repaid in full and terminated on January 23, 2018.

ETP Senior Notes Offering

In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility and for general partnership purposes.

Credit Facilities and Commercial Paper

Parent Company Credit Facility

Indebtedness under the Parent Company Credit Facility is secured by all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, but is not guaranteed by any of the Parent Company’s subsidiaries.

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On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $1.50 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 millionsublimit. Under the Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of December 31, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $312 million.

ETP Credit Facilities

On December 1, 2017 ETP entered into a five-year, $4.0 billionunsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a$1.0 billion364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitments may be increased up to$6.0 billionunder certain conditions. ETP uses the ETP Credit Facilities to provide temporary financing for its growth projects, as well as for general partnership purposes.

Borrowings under the ETP Credit Facilities are unsecured and initially guaranteed by Sunoco Logistics Partners Operations L.P.  Borrowings under the ETP Credit Facilities will bear interest at a eurodollar rate or a base rate, at ETP’s option, plus an applicable margin.  In addition, ETP will be required to pay a quarterly commitment fee to each lender equal to the product of the applicable rate and such lender’s applicable percentage of the unused portion of the aggregate commitments under the ETP Credit Facilities.  Concurrent with the closing of the ETP Credit Facilities, ETP repaid the entire amount outstanding and terminated its previously existing $3.75 billion ETLP Credit Facility and $2.50 billion Sunoco Logistics Credit Facility.

ETP typically repays amounts outstanding under the ETP Credit Facilities with proceeds from common unit offerings or long-term notes offerings. The timing of borrowings depends on ETP’s activities and the cash available to fund those activities. The repayments of amounts outstanding under the ETP Credit Facilities depend on multiple factors, including market conditions and expectations of future working capital needs, and ultimately are a financing decision made by management. Therefore, the balance outstanding under the ETP Credit Facilities may vary significantly between periods. ETP does not believe that such fluctuations indicate a significant change in its liquidity position, because ETP expects to continue to be able to repay amounts outstanding under the ETP Credit Facilities with proceeds from common unit offerings or long-term note offerings.

As ofDecember 31, 2017, the ETP Five-Year Facility had$2.29 billion outstanding, of which$2.01 billionwas commercial paper. The amount available for future borrowings was$1.56 billionafter taking into account letters of credit of$150 million. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was2.48%.

As ofDecember 31, 2017, the ETP 364-Day Facility had$50 millionoutstanding, and the amount available for future borrowings was$950 million. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was5.00%.

Sunoco Logistics Credit Facilities

ETP maintained a$2.50 billionunsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billionand matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest

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owed under the revolving credit facility. As of December 31, 2017, the Sunoco LP credit facility had $9 million in standby letters of credit. The amount available for future borrowings on the revolver at December 31, 2017 was $726 million.

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 billioncredit 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 ofDecember 31, 2017, $2.50 billionof outstanding borrowings. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was3.00%.

Covenants Related to Our Credit Agreements

Covenants Related to the Parent Company

The Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants, and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements.

The Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows:

• Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company (as defined) to EBITDA (as defined therein) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 7.0 to 1 during a specified acquisition period following the close of a specified acquisition; and

• Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1.

Covenants Related to ETP

The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

The ETP Credit Facilities contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:

• incur indebtedness;

• grant liens;

• enter into mergers;

• dispose of assets;

• make certain investments;

• make Distributions (as defined in the ETP Credit Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit Facilities);

• engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

• engage in transactions with affiliates; and

• enter into restrictive agreements.

The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt.The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from1.125% to 2.000%and the applicable margin for base rate loans ranges from0.125%to1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from0.125%to0.300%.  The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from1.125%to1.750%and the applicable margin for base rate loans ranges from0.250%to0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from0.125%to0.225%.

The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0to1,

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which can generally be increased to5.5to1during a Specified Acquisition Period. Our Leverage Ratio was 3.96to1atDecember 31, 2017, as calculated in accordance with the credit agreements.

The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.

Covenants Related to Panhandle

Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.

In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.

Covenants Related to Bakken Credit Facility

The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:

• prohibition of certain incremental secured indebtedness;

• prohibition of certain liens / negative pledge;

• limitations on uses of loan proceeds;

• limitations on asset sales and purchases;

• limitations on permitted business activities;

• limitations on mergers and acquisitions;

• limitations on investments;

• limitations on transactions with affiliates; and

• maintenance of commercially reasonable insurance coverage.

A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than1.20to1(the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.

Covenants Related to Sunoco LP

The Sunoco LP Credit Facilities contain various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. The Sunoco LP Credit Facilities  require Sunoco LP to maintain a leverage

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ratio (as defined therein) of not more than (a) as of the last day of each fiscal quarter through December 31, 2017, 6.75 to 1.0, (b) as of March 31, 2018, 6.5 to 1.0, (c) as of June 30, 2018, 6.25 to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (in the case of the quarter ending March 31, 2019 and thereafter, subject to increases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of $50 million, as permitted under the Credit Facilities.  Indebtedness under the Credit Facilities is secured by a security interest in, among other things, all of Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Credit Facilities will be released.

Compliance with our Covenants

We are required to assess compliance quarterly and were in compliance with all requirements, limitations, and covenants relating to ETE’s and its subsidiaries’ debt agreements as of December 31, 2017.

Each of the agreements referred to above are incorporated herein by reference to our, ETP’s, Sunoco Logistics’ and Sunoco LP’s reports previously filed with the SEC under the Exchange Act. See “Item 1. Business – SEC Reporting.”

Off-Balance Sheet Arrangements

Contingent Residual Support Agreement – AmeriGas

In connection with the closing of the contribution of its propane operations in January 2012, ETP previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.

Guarantee of Sunoco LP Notes

Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i)$800 millionprincipal amount of6.375%senior notes due 2023 issued by Sunoco LP, (ii)$800 millionprincipal amount of6.25%senior notes due 2021 issued by Sunoco LP and (iii)$2.035 billionaggregate 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 billionaggregate principal amount of4.875%, senior notes due 2023;

• $800 millionaggregate principal amount of5.50%senior notes due 2026; and

• $400 millionaggregate principal amount of5.875%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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Contractual Obligations

The following table summarizes our long-term debt and other contractual obligations as of December 31, 2017:

	Payments Due by Period
Contractual Obligations	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Long-term debt	$	44,281	$	1,705	$	9,179	$	8,745	$	24,652
Interest on long-term debt(1)	24,908		2,197		3,887		3,081		15,743
Payments on derivatives	223		84		139		—		—
Purchase commitments(2)	3,605		3,443		99		35		28
Transportation, natural gas storage and fractionation contracts	25		19		6		—		—
Operating lease obligations	1,069		113		196		154		606
Other(3)	185		32		56		45		52
Total(4)	$	74,296	$	7,593	$	13,562	$	12,060	$	41,081

⁽¹⁾  Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2017. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2017. To the extent interest rates change, our contractual obligation for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion.

⁽²⁾  We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for refined product and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the December 31, 2017 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.

⁽³⁾  Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, asset retirement obligations, unrecognized tax benefits, contingency accruals and deferred revenue, which were included in “Other non-current liabilities” in our consolidated balance sheets were excluded from the table above as the amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain.

⁽⁴⁾  Excludes net non-current deferred tax liabilities of $3.32 billion due to uncertainty of the timing of future cash flows for such liabilities.

Cash Distributions

Cash Distributions Paid by the Parent Company

Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner that is necessary or appropriate to provide for future cash requirements.

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Distributions declared and paid during the periods presented are as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 6, 2015	February 19, 2015	$	0.2250
March 31, 2015	May 8, 2015	May 19, 2015	0.2450
June 30, 2015	August 6, 2015	August 19, 2015	0.2650
September 30, 2015	November 5, 2015	November 19, 2015	0.2850
December 31, 2015	February 4, 2016	February 19, 2016	0.2850
March 31, 2016 (1)	May 6, 2016	May 19, 2016	0.2850
June 30, 2016 (1)	August 8, 2016	August 19, 2016	0.2850
September 30, 2016 (1)	November 7, 2016	November 18, 2016	0.2850
December 31, 2016 (1)	February 7, 2017	February 21, 2017	0.2850
March 31, 2017	May 10, 2017	May 19, 2017	0.2850
June 30, 2017	August 7, 2017	August 21, 2017	0.2850
September 30, 2017	November 7, 2017	November 20, 2017	0.2950
December 31, 2017	February 8, 2018	February 20, 2018	0.3050

⁽¹⁾  Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See Note 8 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

Our distributions declared and paid with respect to our Convertible Unit during the year ended December 31, 2017 were as follows:

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2016	May 6, 2016	May 19, 2016	$	0.1100
June 30, 2016	August 8, 2016	August 19, 2016	0.1100
September 30, 2016	November 7, 2016	November 18, 2016	0.1100
December 31, 2016	February 7, 2017	February 21, 2017	0.1100
March 31, 2017	May 10, 2017	May 19, 2017	0.1100
June 30, 2017	August 7, 2017	August 21, 2017	0.1100
September 30, 2017	November 7, 2017	November 20, 2017	0.1100
December 31, 2017	February 8, 2018	February 20, 2018	0.1100

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The total amounts of distributions declared and paid during the periods presented (all from Available Cash from the Parent Company’s operating surplus and are shown in the period to which they relate) are as follows:

	Years Ended December 31,
	2017		2016		2015
Limited Partners	$	1,022	$	971	$	1,139
General Partner interest	3		3		2
Class D units	—		—		3
Total Parent Company distributions	$	1,025	$	974	$	1,144

Cash Distributions Received by the Parent Company

The Parent Company’s cash available for distributions is primarily generated from its direct and indirect interests in ETP and Sunoco LP. Lake Charles LNG’s wholly-owned subsidiaries also contribute to the Parent Company’s cash available for distributions. At December 31, 2017, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, approximately 2.3 million Sunoco LP common units and 12 million Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries.

Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.

As the holder of Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.

	Percentage of Total Distributions to IDRs	ETP
		Quarterly Distribution Rate Target Amounts
Minimum Quarterly Distribution	—%	$0.0750
First Target Distribution	—%	up to $0.0833
Second Target Distribution	13%	above $0.0833 up to $0.0958
Third Target Distribution	35%	above $0.0958 up to $0.2638
Thereafter	48%	above $0.2638

	Percentage of Total Distributions to IDRs	Sunoco LP
		Quarterly Distribution Rate Target Amounts
Minimum quarterly distribution	—%	$0.4375
First target distribution	—%	$0.4375 to $0.503125
Second target distribution	15%	$0.503125 to $0.546875
Third target distribution	25%	$0.546875 to $0.656250
Fourth target distribution	50%	Above $0.656250

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The total amount of distributions to the Parent Company from its limited partner interests, general partner interest and incentive distributions (shown in the period to which they relate) for the periods ended as noted below is as follows:

	Years Ended December 31,
	2017			2016			2015
Distributions from ETP:
Limited Partners	$	61		$	28		$	54
Class H Units	—			357			263
General Partner interest	16			32			31
IDRs	1,638			1,363			1,261
IDR relinquishments net of Class I Unit distributions	(656		)	(409		)	(111		)
Total distributions from ETP	1,059			1,371			1,498
Distributions from Sunoco LP (1)
Limited Partner interests	7			7			—
IDRs	85			81			25
Series A Preferred	23			—			—
Total distributions received from subsidiaries	$	1,174		$	1,459		$	1,523

⁽¹⁾  Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP. Effective January 1, 2016, ETE acquired 2,263,158 common units of Sunoco LP.

In connection with previous transactions, ETE has agreed to relinquish certain amounts of incentive distributions, including the following amounts of incentive distributions in future periods. These amounts include incentive distribution relinquishments related to both legacy ETP and legacy Sunoco Logistics, both of which are applicable to the combined post-merger ETP:

	Total Year
2018	$	153
2019	128
Each year beyond 2019	33

Cash Distributions Paid by Subsidiaries

Certain of our subsidiaries are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.

Cash Distributions Paid by ETP

Under ETP’s limited partnership agreement, within 45 days after the end of each quarter, ETP 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 ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP’s business. ETP 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.

If cash distributions exceed$0.0833per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”

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The following table shows the target distribution levels and distribution “splits” between the general and limited partners and the holders of ETP’s incentive distribution rights (”IDRs”):

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	IDRs	Partners (1)
Minimum Quarterly Distribution	$0.0750	—%	100%
First Target Distribution	up to $0.0833	—%	100%
Second Target Distribution	above $0.0833 up to $0.0958	13%	87%
Third Target Distribution	above $0.0958 up to $0.2638	35%	65%
Thereafter	above $0.2638	48%	52%

⁽¹⁾Includes general partner and limited partner interests, based on the proportionate ownership of each.

Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:

Quarter Ended	ETP		Sunoco Logistics
December 31, 2014	$	0.6633	$	0.4000
March 31, 2015	0.6767		0.4190
June 30, 2015	0.6900		0.4380
September 30, 2015	0.7033		0.4580
December 31, 2015	0.7033		0.4790
March 31, 2016	0.7033		0.4890
June 30, 2016	0.7033		0.5000
September 30, 2016	0.7033		0.5100
December 31, 2016	0.7033		0.5200

Distributions on common units declared and paid by Post-Merger ETP were as follows:

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 16, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 15, 2017	0.5500
September 30, 2017	November 7, 2017	November 14, 2017	0.5650
December 31, 2017	February 8, 2018	February 14, 2018	0.5650

Distributions declared and paid by ETP to the ETP Series A and Series B preferred unitholders 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

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The total amounts of distributions declared and paid during the periods presented (all from Available Cash from ETP’s operating surplus and are shown in the period to which they relate) are as follows:

	Years Ended December 31,
	ETP			Energy Transfer Partners, L.P.						Sunoco Logistics
	2017			2016			2015			2016			2015
Common Units held by public	$	2,435		$	2,168		$	1,970		$	485		$	344
Common Units held by ETP	—			—			—			135			120
Common Units held by ETE	61			28			54			—			—
Class H Units held by ETE	—			357			263			—			—
General Partner interest	16			32			31			15			12
Incentive distributions	1,638			1,363			1,261			397			281
IDR relinquishments (1)	(656		)	(409		)	(111		)	(15		)	—
ETP Series A Preferred Units	15			—			—			—			—
ETP Series B Preferred Units	9			—			—			—			—
Total distributions declared to partners	$	3,518		$	3,539		$	3,468		$	1,017		$	757

⁽¹⁾  Net of Class I unit distributions

Cash Distributions Paid by Sunoco LP

Sunoco LP is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by its general partner.

Distributions declared and paid by Sunoco LP during the periods presented were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 17, 2015	February 27, 2015	$	0.6000
March 31, 2015	May 19, 2015	May 29, 2015	0.6450
June 30, 2015	August 18, 2015	August 28, 2015	0.6934
September 30, 2015	November 17, 2015	November 27, 2015	0.7454
December 31, 2015	February 5, 2016	February 16, 2016	0.8013
March 31, 2016	May 6, 2016	May 16, 2016	0.8173
June 30, 2016	August 5, 2016	August 15, 2016	0.8255
September 30, 2016	November 7, 2016	November 15, 2016	0.8255
December 31, 2016	February 13, 2017	February 21, 2017	0.8255
March 31, 2017	May 9, 2017	May 16, 2017	0.8255
June 30, 2017	August 7, 2017	August 15, 2017	0.8255
September 30, 2017	November 7, 2017	November 14, 2017	0.8255
December 31, 2017	February 06, 2018	February 14, 2018	0.8255

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The total amounts of Sunoco LP distributions declared and paid during the periods presented were as follows (all from Available Cash from Sunoco LP’s operating surplus and are shown in the period with respect to which they relate):

	Years Ended December 31,
	2017		2016		2015
Limited Partners:
Common units held by public	$	178	$	166	$	90
Common and subordinated units held by ETP(1)	143		143		89
Common and subordinated units held by ETE	7		8		—
General Partner interest and Incentive distributions(2)	85		81		30
Series A Preferred	23		—		—
Total distributions declared	$	436	$	398	$	209

⁽¹⁾  Includes Sunoco LP units issued to ETP in connection with Sunoco LP’s acquisition of Susser from ETP in July 2015.

⁽²⁾  The Sunoco LP IDRs were held by ETP until July 2015, at which time the IDRs were exchanged with ETE. The total incentive distributions from Sunoco LP for the year ended December 31, 2015 include $5 million to ETP and 25 million to ETE related to the respective periods during which each held the IDRs.

Recent Accounting Pronouncements

ASU 2014-09

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. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.

For future periods, ETP expects that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of its midstream agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.

We have determined that the timing and/or amount of revenue that we recognize on certain contracts associated with Sunoco LP’s operations will be impacted by the adoption of the new standard. We currently estimate the cumulative catch-up effect to Sunoco LP’s retained earnings as of January 1, 2018 to be approximately $54 million. These adjustments are primarily related to the change in recognition of dealer incentives and rebates.

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. The Partnership expects to adopt ASU 2016-02 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 2016-16

On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.

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ASU 2017-04

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

ASU 2017-12

In August 2017, the FASB issued ASU 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.

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. Our critical accounting policies are discussed below. For further details on our accounting policies, see Note 2 to our consolidated financial statements.

Use of Estimates.  The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for ETP’s midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the year ended December 31, 2017 represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Revenue Recognition.  Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing, are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.

The results of ETP’s intrastate transportation and storage and interstate transportation operations are determined primarily by the amount of capacity ETP’s customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, ETP customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Excess fuel retained after consumption is typically valued at market prices.

ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from the midstream marketing operations, and from producers at the wellhead.

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In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and segment margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.

ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we 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, and (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

ETP has a risk management policy that provides for oversight over ETP’s marketing activities. These activities are monitored independently by ETP’s risk management function and must take place within predefined limits and authorizations. As a result of ETP’s use of derivative financial instruments that may not qualify for hedge accounting, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attempts to manage this volatility through the use of daily position and profit and loss reports provided to senior management and predefined limits and authorizations set forth in ETP’s risk management policy.

ETP injects and holds natural gas in our Bammel storage facility to take advantage of contango markets, when the price of natural gas is higher in the future than the current spot price. ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks in a margin by purchasing gas in the spot market or off peak season and entering a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot prices 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. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot prices and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as ETP enters the winter months, the spread converges so that ETP recognizes in earnings the original locked in spread, either through mark-to-market or the physical withdrawal of natural gas.

ETP’s NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.

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In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.

Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

Regulatory Assets and Liabilities.  Certain of our subsidiaries are subject to regulation by certain state and federal authorities and have accounting policies that conform to FASB Accounting Standards Codification (“ASC”) Topic 980, Regulated Operations, which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be assessed and potentially eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

Accounting for Derivative Instruments and Hedging Activities.  ETP utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit their exposure to margin fluctuations in natural gas, NGL and refined products. These contracts consist primarily of commodity futures and swaps. In addition, prior to ETP’s contribution of its retail propane activities to AmeriGas, ETP used derivatives to limit its exposure to propane market prices.

If ETP designates a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

If ETP designates a hedging relationship as a fair value hedge, they record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.

ETP utilizes published settlement prices for exchange-traded contracts, quotes provided by brokers, and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk,” for further discussion regarding our derivative activities.

Fair Value of Financial Instruments.  We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP Convertible Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our

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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.

Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in Unconsolidated Affiliates.  Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.

In order to test for recoverability when performing a quantitative impairment test, the Partnership makes estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, the Partnership makes certain estimates and assumptions, including, among other things, changes in general economic conditions in the Partnership’s operating regions, the availability and prices of natural gas, the ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, dependence on certain significant customers and producers of natural gas, and competition from other companies, including major energy producers. If future results are not consistent with the Partnership’s estimates, future impairment losses that could be material may be recorded to our results of operations.

The Partnership determined the fair value of its reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable; however, variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

One key assumption for the measurement of an impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in additional impairments in future periods; however, management does not believe that any of the goodwill balances in its reporting units as of December 31, 2017 is at significant risk of impairment. Therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments. 

Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the $4.8 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2017, approximately $1.0 billion is recorded in ETP’s reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.

During the year ended December 31, 2017, ETP recorded following impairments:

• A $223 million impairment was recorded related to the goodwill associated with CDM. In January 2018, ETP announced the contribution of CDM to USAC. Based on ETP’s anticipated proceeds in the contribution transaction, the implied fair value

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of the CDM reporting unit was less than its carrying value. As ETP believes that the contribution consideration also represented an appropriate estimate of fair value as of the 2017 annual impairment test date, ETP recorded an impairment for the difference between the carrying value and the fair value of the reporting unit. Subsequent to the impairment, a total of $253 million of goodwill remains in the CDM reporting unit, which amount is subject to further impairment based on changes in the contribution transaction prior to closing or any other factors affecting the fair value of the CDM reporting unit. Assuming the contribution transaction closes, the remaining CDM goodwill balance will be derecognized; if the transaction does not close, then the CDM goodwill balance will remain on the ETP’s consolidated balance sheet and will continue to be tested for impairment in the future.

• A $262 million impairment was recorded related to the goodwill associated with ETP’s interstate transportation and storage reporting units, and a $229 million impairment was recorded related to the goodwill associated with the general partner of Panhandle. These impairments were due to a reduction in management’s forecasted future cash flows from the related reporting units, which reduction reflected the impacts discussed in “Results of Operations” above, along with the impacts of re-contracting assumptions related to future periods.

• A $79 million impairment was recorded related to the goodwill associated ETP’s refined products transportation and services reporting unit. Subsequent to the Sunoco Logistics Merger, ETP restructured the internal reporting of legacy Sunoco Logistics’ business to be consistent with the internal reporting of legacy ETP. Subsequent to this reallocation the carrying value of certain refined products reporting units was less than the estimated fair value due to a reduction in management’s forecasted future cash flows from the related reporting units, and the goodwill associated with those reporting units was fully impaired. No goodwill remained in the respective reporting units subsequent to the impairment.

• A $127 million impairment of property, plant and equipment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets.

• A $141 million impairment of ETP’s equity method investment in FEP. ETP concluded that the carrying value of its investment in FEP was other than temporarily impaired based on an anticipated decrease in production in the Fayetteville basin and a customer re-contracting with a competitor during 2017.

• A $172 million impairment of ETP’s equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven be the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.

During the year ended December 31, 2016, ETP recorded following goodwill impairments:

• A $638 million goodwill impairment and a $133 million impairment to property, plant and equipment were recorded in its interstate transportation and storage operations primarily due to decreases in projected future revenues and cash flows driven by changes in the markets that these assets serve.

• A $32 million goodwill impairment was recorded in its midstream operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices.

• A $308 million impairment of ETP’s equity method investment in MEP. ETP concluded that the carrying value of its investment in MEP was other than temporarily impaired based on commercial discussions with current and potential shippers on MEP during 2016, which negatively affected the outlook for long-term transportation contract rates.

During the year ended December 31, 2015, ETP recorded following goodwill impairments:

• A $99 million goodwill impairment related to Transwestern primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.

• A $106 million goodwill impairment, a $24 million impairment of intangible assets, and a $110 million impairment to property, plant and equipment related to Lone Star Refinery Services primarily due to changes in assumptions related to potential future revenues and market declines in current and expected future commodity prices, as well as economic obsolescence identified as a result of low utilization.

Except for the 2017 impairment of the goodwill associated with CDM, as discussed above, the goodwill impairments recorded by ETP during the years ended December 31, 2017, 2016 and 2015 represented all of the goodwill within the respective reporting units.

For Sunoco LP, the impairment of $641 million during the year ended December 31, 2016 represented a portion of the goodwill within Sunoco LP’s retail reporting unit.

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During 2017, Sunoco LP announced the sale of a majority of the assets in its retail and Stripes reporting units. These reporting units include the retail operations in the continental United States but excludes the retail convenience store operations in Hawaii that comprise the Aloha reporting unit. Upon the classification of assets and related liabilities as held for sale, Sunoco LP’s management applied the measurement guidance in ASC 360, Property, Plant and Equipment, to calculate the fair value less cost to sell of the disposal group. In accordance with ASC 360-10-35-39, Sunoco LP’s management first tested the goodwill included within the disposal group for impairment prior to measuring the disposal group’s fair value less the cost to sell. In the determination of the classification of assets held for sale and the related liabilities, Sunoco LP’s management allocated a portion of the goodwill balance previously included in the Sunoco LP retail and Stripes reporting units to assets held for sale based on the relative fair values of the business to be disposed of and the portion of the respective reporting unit that will be retained in accordance with ASC 350-20-40-3. The amount of goodwill allocated to assets held for sale was approximately $796 million and $1.1 billion as of December 31, 2017 and 2016, respectively. The remainder of the goodwill was allocated to the retained portion of the retail and Stripes reporting units, which is comprised of Sunoco LP’s ethanol plant, credit card processing services, franchise royalties and retail stores Sunoco LP continues to operate in the continental United States. This amount, inclusive of the portion of the Aloha reporting unit that represents retail activities, was approximately $678 million and $780 million as of December 31, 2017 and 2016, respectively.

Sunoco LP recognized goodwill impairments of $387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.

For goodwill included in the Aloha and Wholesale reporting units, which goodwill balances total $112 million and $732 million, respectively, and which were not classified as held for sale, no impairments were deemed necessary during 2017.

Additionally, Sunoco LP performed impairment tests on their indefinite-lived intangible assets during the fourth quarter of 2017 and recognized $13 million and $4 million impairment charge on their contractual rights and liquor licenses primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded.

Property, Plant and Equipment.  Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, ETP capitalizes certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the consolidated statement of operations. Depreciation of property, plant and equipment is provided using the straight-line method based on their estimated useful lives ranging from 1 to 99 years. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. We do not anticipate future changes in the estimated useful lives of our property, plant and equipment.

Asset Retirement Obligations.We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.

Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as ofDecember 31, 2017and2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

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Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

Long-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million of legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.

Pensions and Other Postretirement Benefit Plans. We are required to measure plan assets and benefit obligations as of its fiscal year-end balance sheet date. We recognize the changes in the funded status of our defined benefit postretirement plans through AOCI or are reflected as a regulatory asset or regulatory liability for regulated subsidiaries.

The calculation of the net periodic benefit cost and benefit obligation requires the use of a number of assumptions. Changes in these assumptions can have a significant effect on the amounts reported in the financial statements. The Partnership believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets.

The discount rate is established by using a hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due. Net periodic benefit cost and benefit obligation increases and equity correspondingly decreases as the discount rate is reduced.

The expected rate of return on plan assets is based on long-term expectations given current investment objectives and historical results. Net periodic benefit cost increases as the expected rate of return on plan assets is correspondingly reduced.

Legal Matters.We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised as required as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints.

For more information on our litigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.

Environmental Remediation Activities. The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.

Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and reasonably estimable. ETP has 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, ETP accrues losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. ETP’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range be accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded.

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In addition to the probable and estimable losses which have been recorded, management believes it is reasonably possible (i.e., less than probable but greater than remote) that additional environmental remediation losses will be incurred. At December 31, 2017, the aggregate of the estimated maximum additional reasonably possible losses, which relate to numerous individual sites, totaled approximately $5 million. This estimate of reasonably possible losses comprises estimates for remediation activities at current logistics and retail assets and, in many cases, reflects the upper end of the loss ranges which are described above. Such estimates include potentially higher contractor costs for expected remediation activities, the potential need to use more costly or comprehensive remediation methods and longer operating and monitoring periods, among other things.

Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position.

Deferred Income Taxes. ETE recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal tax alternative minimum tax credit carryforwards totaling $683 million have been included in ETE’s consolidated balance sheet as of December 31, 2017. All of the deferred income tax assets attributable to state and federal NOL benefits expire before 2037 as more fully described below. The state NOL carryforward benefits of $274 million ($217 million net of federal benefit) begin to expire in 2018 with a substantial portion expiring between 2031 and 2037. The federal NOLs of $1,921 million ($403 million in benefits) will expire in 2033 and 2036. Federal tax alternative minimum tax credit carryforwards of $62 million remained at December 31, 2017. We have determined that a valuation allowance totaling $236 million ($186 million net of federal income tax effects) is required for the state NOLs at December 31, 2017 primarily due to significant restrictions on their use in the Commonwealth of Pennsylvania. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made.

Forward-Looking Statements

This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations 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, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

• the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;

• the actual amount of cash distributions by our subsidiaries to us;

• the volumes transported on our subsidiaries’ pipelines and gathering systems;

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• the level of throughput in our subsidiaries’ processing and treating facilities;

• the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;

• the prices and market demand for, and the relationship between, natural gas and NGLs;

• energy prices generally;

• the prices of natural gas and NGLs compared to the price of alternative and competing fuels;

• the general level of petroleum product demand and the availability and price of NGL supplies;

• the level of domestic oil, natural gas and NGL production;

• the availability of imported oil, natural gas and NGLs;

• actions taken by foreign oil and gas producing nations;

• the political and economic stability of petroleum producing nations;

• the effect of weather conditions on demand for oil, natural gas and NGLs;

• availability of local, intrastate and interstate transportation systems;

• the continued ability to find and contract for new sources of natural gas supply;

• availability and marketing of competitive fuels;

• the impact of energy conservation efforts;

• energy efficiencies and technological trends;

• governmental regulation and taxation;

• changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;

• hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;

• competition from other midstream companies and interstate pipeline companies;

• loss of key personnel;

• loss of key natural gas producers or the providers of fractionation services;

• reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities;

• the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments;

• the nonpayment or nonperformance by our subsidiaries’ customers;

• regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries’ internal growth projects, such as our subsidiaries’ construction of additional pipeline systems;

• risks associated with the construction of new pipelines and treating and processing facilities or additions to our subsidiaries’ existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;

• the availability and cost of capital and our subsidiaries’ ability to access certain capital sources;

• a deterioration of the credit and capital markets;

• risks associated with the assets and operations of entities in which our subsidiaries own less than a controlling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;

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• the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;

• changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and

• the costs and effects of legal and administrative proceedings.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Item 1A. Risk Factors” in this annual report. Any forward-looking statement made by us in this Annual Report on Form 10-K is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.

Inflation

Interest rates on existing and future credit facilities and future debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in the capital markets, we expect to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances.

Inflation in the United States has been relatively low in recent years and has not had a material effect on our results of operations. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by commodity price changes. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along a portion of increased costs to our customers in the form of higher fees.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

(Tabular dollar amounts are in millions)

Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risk and interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks.

Commodity Price Risk

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

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

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

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

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

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

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The tables below summarize commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of December 31, 2017 and 2016 for ETP and Sunoco LP, including derivatives related to their respective subsidiaries. Dollar amounts are presented in millions.

	December 31, 2017							December 31, 2016
	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	1,078		$	—		$	—	(683	)	$	—		$	—
Basis Swaps IFERC/NYMEX(1)	48,510		2			1		2,243		(1		)	—
Options – Puts	13,000		—			—		—		—			—
Power (Megawatt):
Forwards	435,960		1			1		391,880		(1		)	1
Futures	(25,760	)	—			—		109,564		—			—
Options — Puts	(153,600	)	—			1		(50,400	)	—			—
Options — Calls	137,600		—			—		186,400		1			—
Crude (MBbls) — Futures	—		1			—		(617	)	(4		)	6
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	4,650		(13		)	4		10,750		2			—
Swing Swaps IFERC	87,253		(2		)	1		(5,663	)	(1		)	1
Fixed Swaps/Futures	(4,390	)	(1		)	2		(52,653	)	(27		)	19
Forward Physical Contracts	(145,105	)	6			41		(22,492	)	1			—
Natural Gas Liquid (MBbls) — Forwards/Swaps	6,744		1			25		(5,787	)	(40		)	35
Refined Products (MBbls) — Futures	(3,901	)	(27		)	4		(3,144	)	(21		)	18
Corn (Bushels) – Futures	1,870,000		—			—		1,580,000		—			1
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(39,770	)	(2		)	—		(36,370	)	2			1
Fixed Swaps/Futures	(39,770	)	14			11		(36,370	)	(26		)	14

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

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 below 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 portfolios 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.

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Interest Rate Risk

As of December 31, 2017, we and our subsidiaries had $9.86 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $98 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, none of which are designated as hedges for accounting purposes:

			Notional Amount Outstanding
Entity	Term	Type(1)	December 31, 2017		December 31, 2016
ETP	July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
ETP	July 2018(2)	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
ETP	July 2019(2)	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
ETP	July 2020(2)	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
ETP	December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
ETP	March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300

⁽¹⁾  Floating rates are based on 3-month LIBOR.

⁽²⁾  Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a change in the fair value of the interest rate derivatives and earnings (recognized in gains (losses) on interest rate derivatives) of approximately $236 million as of December 31, 2017. For ETP’s $1.50 billion of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flow of $15 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.

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.

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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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements starting on page F-1 of this report are incorporated by reference.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING

AND FINANCIAL DISCLOSURE

None.

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the President and Group Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including the President and Group Chief Financial Officer of our General Partner, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2017.

Management’s Report on Internal Control over Financial Reporting

The management of Energy Transfer Equity, L.P. and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the President and Group Chief Financial Officer of our General Partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”).

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2017.

Grant Thornton LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2017, as stated in their report, which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of LE GP, LLC and

Unitholders of Energy Transfer Equity, L.P.

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Energy Transfer Equity, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2017, and our report dated February 23, 2018 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Dallas, Texas

February 23, 2018

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Changes in Internal Controls over Financial Reporting

There has been no change in our internal controls over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B.  OTHER INFORMATION

None.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Board of Directors

Our general partner, LE GP, LLC, manages and directs all of our activities. The officers and directors of ETE are officers and directors of LE GP, LLC. The members of our general partner elect our general partner’s Board of Directors. The board of directors of our general partner has the authority to appoint our executive officers, subject to provisions in the limited liability company agreement of our general partner. Pursuant to other authority, the board of directors of our general partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of our chief executive officer, to appoint a replacement.

As of December 31, 2017, our Board of Directors was comprised of seven persons, three of whom qualify as “independent” under the NYSE’s corporate governance standards. We have determined that Messrs. Brannon, Turner and Williams are all “independent” under the NYSE’s corporate governance standards.

As a limited partnership, we are not required by the rules of the NYSE to seek unitholder approval for the election of any of our directors. We believe that the members of our general partner have appointed as directors individuals with experience, skills and qualifications relevant to the business of the Parent Company, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees, but we believe that the members of our general partner have endeavored to assemble a group of individuals with the qualities and attributes required to provide effective oversight of the Parent Company.

Risk Oversight

Our Board of Directors generally administers its risk oversight function through the board as a whole. Our President, who reports to the Board of Directors, has day-to-day risk management responsibilities. Our President attends the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Parent Company’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Parent Company’s internal auditor, who reports directly to the Audit Committee, and reviews the Parent Company’s contingencies with management and our independent auditors.

Corporate Governance

The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com and will be provided in print form to any Unitholder requesting such information.

Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein.

Annual Certification

In 2017, our President provided to the NYSE the annual CEO certification regarding our compliance with the NYSE’s corporate governance listing standards.

Conflicts Committee

Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the general partner is fair and reasonable to the Parent Company and our Unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to the Parent Company to determine if the transaction presents a conflict of interest and whether the transaction is fair and reasonable to the Parent Company. Pursuant to the terms of our partnership agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Parent Company, approved by all partners of the Parent Company and not a breach by the general partner or its Board of Directors of any duties

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they may owe the Parent Company or the Unitholders. These duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).

Audit Committee

The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board determined that based on relevant experience, Audit Committee member Rick Turner qualified as an audit committee financial expert during 2017. A description of the qualifications of Mr. Turner may be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.”

The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and makes recommendations to the Board of Directors relating to our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Audit Committee has received written disclosures and the letter from Grant Thornton required by applicable requirements of the Audit Committee concerning independence and has discussed with Grant Thornton that firm’s independence. The Audit Committee recommended to the Board that the audited financial statements of ETE be included in ETE’s Annual Report on Form 10-K for the year ended December 31, 2017.

The Board of Directors adopts the charter for the Audit Committee. Richard D. Brannon, K. Rick Turner and William P. Williams serve as elected members of the Audit Committee.

Compensation and Nominating/Corporate Governance Committees

Although we are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are a limited partnership, the Board of Directors of LE GP, LLC has previously established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our employees and officers under the equity compensation plans, including the performance standards or other restrictions pertaining to the vesting of any such awards. Pursuant to the Charter of the Compensation Committee, a director serving as a member of the Compensation Committee may not be an officer of or employed by our general partner, the Parent Company, ETP or its subsidiaries, or Sunoco LP or its subsidiaries.

Matters relating to the nomination of directors or corporate governance matters were addressed to and determined by the full Board of Directors for the period ETE did not have a compensation committee.

The responsibilities of the ETE Compensation Committee include, among other duties, the following:

• annually review and approve goals and objectives relevant to compensation of our President and CFO, if applicable;

• annually evaluate the President and CFO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the President and CFO’s compensation levels, if applicable, based on this evaluation;

• make determinations with respect to the grant of equity-based awards to executive officers under ETE’s equity incentive plans;

• periodically evaluate the terms and administration of ETE’s long-term incentive plans to assure that they are structured and administered in a manner consistent with ETE’s goals and objectives;

• periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;

• periodically evaluate the compensation of the directors;

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• retain and terminate any compensation consultant to be used to assist in the evaluation of director, President and CFO or executive officer compensation; and

• perform other duties as deemed appropriate by the Board of Directors.

Code of Business Conduct and Ethics

The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are applicable to the principal executive officer, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our general partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may not be posted.

Meetings of Non-management Directors and Communications with Directors

Our non-management directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings.

We have established a procedure by which Unitholders or interested parties may communicate directly with the Board of Directors, any committee of the Board, any of the independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired person, committee or group to the attention of Sonia Aubé at Energy Transfer Equity, L.P., 8111 Westchester Drive, Suite 600, Dallas, Texas, 75225. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.

Directors and Executive Officers of Our General Partner

The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner as of February 23, 2018. Executive officers and directors are elected for indefinite terms.

Name	Age	Position with Our General Partner
John W. McReynolds	67	Director and President
Kelcy L. Warren	62	Director and Chairman of the Board
Thomas E. Long	61	Group Chief Financial Officer
Marshall S. (Mackie) McCrea, III	58	Director and Group Chief Operating Officer and Chief Commercial Officer
Thomas P. Mason	61	Executive Vice President and General Counsel
Brad Whitehurst	43	Executive Vice President and Head of Tax
Richard D. Brannon	59	Director
Matthew S. Ramsey	62	Director
K. Rick Turner	59	Director
William P. Williams	80	Director

Messrs. Warren, and McCrea also serve as directors of ETP’s general partner. Messrs. Ramsey and Turner serve as directors of the general partner of Sunoco LP.

Set forth below is biographical information regarding the foregoing officers and directors of our general partner:

John W. McReynolds.  Mr. McReynolds has served as our President since March 2005, and as a Director since August 2005. He served as our Chief Financial Officer from August 2005 to June 2013, and previously served as a Director of ETP from August 2001 through May 2010. Mr. McReynolds has been in the energy industry for his entire career. Prior to becoming President and CFO of ETE, Mr. McReynolds was in private law practice for over 20 years,  specializing exclusively in energy-related finance, securities, corporations and partnerships, mergers and acquisitions, syndications, and a wide variety of energy-related litigation. His practice dealt with all forms of fossil fuels, and the transportation and handling thereof, together with the financing and structuring of all forms of business entities related thereto. The members of our general partner selected Mr. McReynolds to serve in the indicated roles with the Energy Transfer partnerships because of this extensive background and experience, as well as his many contacts and relationships in the industry.

Kelcy L. Warren.  Mr. Warren was appointed Co-Chairman of the Board of Directors of our general partner, LE GP, LLC, effective upon the closing of our IPO. On August 15, 2007, Mr. Warren became the sole Chairman of the Board of our general partner and

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the Chief Executive Officer and Chairman of the Board of the general partner of ETP. Prior to that, Mr. Warren had served as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETP since the combination of the midstream and intrastate transportation storage operations of ETC OLP and the retail propane operations of Heritage in January 2004. Mr. Warren also serves as Chief Executive Officer of the general partner of ETC OLP. Mr. Warren also served as the Chief Executive Officer of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Prior to the combination of the operations of ETP and Heritage Propane, Mr. Warren served as President of the general partner of ET Company I, Ltd. the entity that operated ETP’s midstream assets before it acquired Aquila, Inc.’s midstream assets, having served in that capacity since 1996. From 1996 to 2000, he also served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer and a Director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 30 years of business experience in the energy industry. The members of our general partner selected Mr. Warren to serve as a director and as Chairman because he is ETP’s Chief Executive Officer and has more than 30 years in the natural gas industry. Mr. Warren also has relationships with chief executives and other senior management at natural gas transportation companies throughout the United States, and brings a unique and valuable perspective to the Board of Directors.

Thomas E. Long.  Mr. Long is the Group Chief Financial Officer of ETE since February 2016. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long has served as a director of Sunoco LP since May 2016. Mr. Long previously served as Chief Financial Officer of ETP and as Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. From May 2008 to November 2010, Mr. Long served as Vice President and Chief Financial Officer of Matrix Service Company. Prior to joining Matrix, he served as Vice President and Chief Financial Officer of DCP Midstream Partners, LP, a publicly traded natural gas and natural gas liquids midstream business company located in Denver, CO. In that position, he was responsible for all financial aspects of the company since its formation in December 2005. From 1998 to 2005, Mr. Long served in several executive positions with subsidiaries of Duke Energy Corp., one of the nation’s largest electric power companies.

Marshall S. (Mackie) McCrea, III.  Mr. McCrea is the Group Chief Operating Officer and Chief Commercial Officer for the Energy Transfer family and has served in that capacity since November 2015. Mr. McCrea was appointed as a director of the general partner of ETP in December 2009. Prior to that, he served as President and Chief Operating Officer of ETP’s general partner from June 2008 to November 2015 and President – Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President – Commercial Development since January 2004. In March 2005, Mr. McCrea was named President of La Grange Acquisition LP, ETP’s primary operating subsidiary, after serving as Senior Vice President-Business Development and Producer Services since 1997. Mr. McCrea also currently serves on the Board of Directors of the general partner of ETE. Mr. McCrea also served as the Chairman of the Board of Directors of the general partner of Sunoco Logistics from October 2012 to April 2017. The members of our general partner selected Mr. McCrea to serve as a director because he brings extensive project development and operational experience to the Board. He has held various positions in the natural gas business over the past 25 years and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.

Thomas P. Mason.Mr. Mason became Executive Vice President and General Counsel of the general partner of ETE in December 2015. Mr. Mason also served as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETP’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining ETP, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years. Mr. Mason also served on the Board of Directors of the general partner of Sunoco Logistics, from October 2012 to April 2017.

Brad Whitehurst. Mr. Whitehurst has served as the Executive Vice President and Head of Tax of our general partner since August 2014. Prior to joining ETE, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised ETE and its subsidiaries in his role as outside counsel since 2006.

Richard D. Brannon. Mr. Brannon was appointed to the Board of Directors of our general partner in March 2016. Previously, he served on the Sunoco LP Board of Directors from September 2014 to March 2016. Mr. Brannon has also served on the Board of Directors of WildHorse Resource Development Corp. (NYSE: WRD), since its IPO in December 2016 he is CEO of CH4 Energy II, III, IV, V and VI, all independent companies focused on horizontal development of oil and gas. Previously, he was President of CH4 Energy Corp. from 2001 to 2006, when the company was sold to Bill Barrett Corp. From 1984 to 2005, Dick was President of Brannon Oil & Gas, Inc. and Brannon & Murray Drilling Co. Previously, he was a drilling and completion engineer for Texas Oil & Gas Corp. He has previously served on the boards of Cornerstone Natural Gas Corp., which was purchased by El Paso Corp. in 1996, and OEC Compression Corp, acquired by Hanover Compressor Company in 2001. Mr. Brannon also formerly served on the Board of Directors and as a member of the audit committee and compensation committee of Regency, Energy Partners LP and Sunoco LP. The members of our general partner selected Mr. Brannon to serve as director because of his extensive energy industry experience and his service on other public company boards and committees.

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Matthew S. Ramsey. Mr. Ramsey was appointed as a director of ETE’s general partner on July 17, 2012 and as a director of ETP’s general partner on November 9, 2015. Mr. Ramsey currently serves as President and Chief Operating Officer of ETP’s general partner since November 2015. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey is also a director of Sunoco LP, serving as chairman of Sunoco LP’s board since April 2015. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership generating and drilling 3-D seismic prospects on the Gulf Coast of Texas. Mr. Ramsey is currently a director of RSP Permian, Inc. (NYSE: RSPP), where he serves as chairman of the compensation committee and as a member of the audit committee. Mr. Ramsey formerly served as President of DDD Energy, Inc. until its sale in 2002. From 1996 to 2000, Mr. Ramsey served as President and Chief Executive Officer of OEC Compression Corporation, Inc., a publicly traded oil field service company, providing gas compression services to a variety of energy clients. Previously, Mr. Ramsey served as Vice President of Nuevo Energy Company, an independent energy company. Additionally, he was employed by Torch Energy Advisors, Inc., a company providing management and operations services to energy companies including Nuevo Energy, last serving as Executive Vice President. Mr. Ramsey joined Torch Energy as Vice President of Land and was named Senior Vice President of Land in 1992. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey is a graduate of Harvard Business School Advanced Management Program. Mr. Ramsey is licensed to practice law in the State of Texas. He is qualified to practice in the Western District of Texas and the United States Court of Appeals for the Fifth Circuit. Mr. Ramsey formerly served as a director of Southern Union Company. The member of our general partner recognize Mr. Ramsey’s vast experience in the oil and gas space and believe that he provides valuable industry insight as a member of our Board of Directors.

K. Rick Turner.  Mr. Turner has served as a director of our general partner since October 2002. Mr. Turner currently serves as chair of the Compensation Committee and a member of the Audit Committee. Mr. Turner is also a director of Sunoco LP, serving as chair of Sunoco LP’s compensation and audit committees. Mr. Turner is presently a managing director of Altos Energy Partners, LLC. Mr. Turner previously was a private equity executive with several groups after retiring from the Stephens’ family entities, which he had worked for since 1983. He first became a private equity principal in 1990 after serving as the Assistant to the Chairman, Jackson T. Stephens. His areas of focus have been oil and gas exploration, natural gas gathering, processing industries, and power technology. Prior to joining Stephens, he was employed by Peat, Marwick, Mitchell and Company. Mr. Turner currently serves as a director of AmeriGas Partners, L.P. Mr. Turner earned his B.S.B.A. from the University of Arkansas and is a non-practicing Certified Public Accountant. The members of our general partner selected Mr. Turner based on his industry knowledge, his background in corporate finance and accounting, and his experience as a director and audit committee member on the boards of several other companies.

William P. Williams. Mr. Williams was appointed as a director in March 2012 and currently serves as a member of the Audit Committee. Mr. Williams began his career in the oil and gas industry in 1967 with Texas Power and Light Company as Manager of Pipeline Construction for Bi-Stone Fuel Company, a predecessor of Texas Utilities Fuel Company. In 1980, he was employed by Endevco as Vice President of Pipeline and Plant Construction, Engineering, and Operations. Prior to Endevco, he worked for Cornerstone Natural Gas. Mr. Williams later joined Energy Transfer Partners, L.P. as Vice President of Engineering and Operations, ending his career as Vice President of Measurement in May 2011. The members of our general partner selected Mr. Williams due to his experience in the pipeline industry and his familiarity with our business.

Compensation of the General Partner

Our general partner does not receive any management fee or other compensation in connection with its management of the Parent Company.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2017.

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ITEM 11.  EXECUTIVE COMPENSATION

Overview

As a limited partnership, we are managed by our General Partner. Our General Partner is majority owned by Mr. Kelcy Warren.

We own 100% of ETP GP and its general partner, ETP LLC. We refer to ETP GP and ETP LLC together as the “ETP GP Entities.” ETP GP is the general partner of ETP. All of ETP’s employees receive employee benefits from the operating companies of ETP.

We acquired 100% of Sunoco GP LLC, the general partner of Sunoco LP, from ETP in July 2015. All of Sunoco LP’s employees receive employee benefits from either Sunoco GP LLC or the operating companies of Sunoco LP.

Compensation Discussion and Analysis

Named Executive Officers

ETE does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of ETE’s management functions. As a result, the executive officers of our General Partner are essentially ETE’s executive officers, and their compensation is administered by our General Partner. This Compensation Discussion and Analysis is, therefore, focused on the total compensation of the executive officers of our General Partner as set forth below. In addition, to provide comprehensive disclosure of our executive compensation, we are also providing information as to the executive compensation of certain executive officers of our subsidiaries, even though none of these persons is an executive officer of the Parent Company. Accordingly, the persons we refer to in this discussion as our “named executive officers” are the following:

ETE Executive Officers

• John W. McReynolds, President;

• Thomas E. Long, Chief Financial Officer and Group Chief Financial Officer of ETE’s general partner;

• Marshall S. (Mackie) McCrea, III, Group Chief Operating Officer and Chief Commercial Officer;

• Thomas P. Mason, Executive Vice President and General Counsel; and

• Bradford D. Whitehurst, Executive Vice President and Head of Tax.

Our Philosophy for Compensation of Executives

Our General Partner. In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for the named executive officers that provides for a slightly below the median market annual base compensation rate (i.e. approximately the 40^th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short and long-term performance that are both targeted to pay-out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by the payment of annual discretionary cash bonuses and grants of restricted unit awards. Our General Partner believes the performance of our operating subsidiaries and the contribution of our management toward the achievement of the financial targets and other goals of those subsidiaries should be considered in determining annual discretionary cash bonuses.

ETP GP Entities. The ETP GP Entities also believe that a significant portion of each executives’ compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be very competitive in the marketplace for executive talents and abilities. ETP GP seeks a total compensation program for the named executive officers that provides for a slightly below the median market annual base compensation rate (i.e. approximately the 40^th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short and long-term performance that are both targeted to pay-out at approximately the top-quartile of market. ETP GP believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of ETP’s financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of its named executive officers to the success of ETP and the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit or phantom unit awards under ETE’s equity incentive plan, ETP’s equity incentive plan(s) or the equity incentive programs of Sunoco LP, as applicable based on the allocation of the named executive officers’ award, which awards are intended to provide a longer term incentive and retention value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution ETP and/or the other affiliated partnerships pay to their respective unitholders.

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The Partnership grants restricted unit/phantom unit awards that vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service. The ETP GP Entities believe that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance ETP GP places on aligning the interests of its named executive officers with those of unitholders.

While ETE, through the ETP GP Entities, is responsible for the direct payment of the compensation of our named executive officers, ETE does not participate or have any input in any decisions as to the compensation levels or policies of our General Partner or the ETP GP Entities. As discussed below, our compensation committee, the eligible members of board of directors of our General Partner at times when we have not had a compensation committee or the ETP Compensation Committee and/or the compensation committee of the general partner of Sunoco Logistics and Sunoco LP, as applicable, all in consultation with the General Partner, are responsible for the compensation policies and compensation level of the named executive officers of our General Partner. In this discussion, we refer to either or both of the ETE Compensation Committee or such members of our board of directors collectively as the “ETE Compensation Committee.”

ETP also does not participate or have any input in any decisions as to the compensation policies of the ETP GP Entities or the compensation levels of the executive officers of the ETP GP Entities. The compensation committee of the board of directors of the ETP GP Entities (the “ETP Compensation Committee”) is responsible for the approval of the compensation policies and the compensation levels of the executive officers of the ETP GP Entities.

Sunoco LP also does not participate or have any input in any decisions as to the compensation policies of Sunoco GP LLC or the compensation levels of the executive officers of its general partner. The SUN Compensation Committee is responsible for the approval of the compensation policies and the compensation levels of the executive officers of Sunoco GP LLC.

For a more detailed description of the compensation to ETE’s and ETP GP’s named executive officers, please see “– Compensation Tables” below.

Distributions to Our General Partner

Our General Partner is partially-owned by certain of our current and prior named executive officers. We pay quarterly distributions to our General Partner in accordance with our partnership agreement with respect to its ownership of its general partner interest as specified in our partnership agreement. The amount of each quarterly distribution that we must pay to our General Partner is based solely on the provisions of our partnership agreement, which agreement specifies the amount of cash we distribute to our General Partner based on the amount of cash that we distribute to our limited partners each quarter. Accordingly, the cash distributions we make to our General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Distributions to our General Partner are described in detail in Note 8 to our consolidated financial statements. Our named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per unit distributions equal the per unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named executive officers or the services they perform as employees.

For a more detailed description of the compensation of our named executive officers, please see “Compensation Tables” below.

Compensation Philosophy

Our compensation programs are structured to achieve the following:

• reward executives with an industry-competitive total compensation package of base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;

• attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size and in similar lines of business;

• motivate executive officers and key employees to achieve strong financial and operational performance;

• emphasize performance-based or “at-risk” compensation; and

• reward individual performance.

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Components of Executive Compensation

For the year ended December 31, 2017, the compensation paid to our named executive officers consisted of the following components:

• annual base salary;

• non-equity incentive plan compensation consisting solely of discretionary cash bonuses;

• time-vested restricted/phantom unit awards under the equity incentive plan(s);

• payment of distribution equivalent rights (“DERs”) on unvested time-based restricted unit award under our equity incentive plan;

• vesting of previously issued time-based restricted unit/phantom restricted unit awards issued pursuant to our equity incentive plans or the equity incentive plans(s) of affiliates; and

• 401(k) plan employer contributions.

Methodology

The ETE Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for our executive officers, including the named executive officers. The ETE Compensation Committee also considers individual performance, levels of responsibility, skills and experience.

Periodically, the ETE or ETP Compensation Committee engages a third-party consultant to provide market information for compensation levels at peer companies in order to assist in the determination of compensation levels for our executive officers, including the named executive officers. Most recently, Longnecker & Associates (“Longnecker”) evaluated the market competitiveness of total compensation levels of a number of officers of ETE and ETP to provide market information with respect to compensation of those executives during the year ended December 31, 2017. In particular, the review by Longnecker was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including our named executive officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy.

In conducting its review, Longnecker specifically considered the larger size of the combined ETE and ETP entities from an energy industry perspective. During 2017, Longnecker assisted in the development of the final “peer group” of leading companies in the energy industry that most closely reflect the profile of ETP and ETE in terms of revenues, assets and market value as well as competition for talent at the senior management level and similarly situated general industry companies with similar revenues, assets and market value. In setting such peer group, the size of ETE and ETP on a combined basis was considered. Unlike in prior evaluations conducted by Longnecker, a determination was made to focus the analysis specifically on the energy industry based on a determination that an energy industry peer group provided a more than sufficient amount of comparative data to consider and evaluate total compensation. This decision allowed Longnecker to report on specific industry related data comparing the levels of annual base salary, annual short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive officers of these other companies. The identified companies were:

Energy Peer Group:
• Conoco Phillips	• Anadarko Petroleum Corporation
• Enterprise Products Partners, L.P.	• Marathon Petroleum Corporation
• Plains All American Pipeline, L.P.	• Kinder Morgan, Inc.
• Halliburton Company	• The Williams Companies, Inc.
• Valero Energy Corporation	• Phillips 66

The compensation analysis provided by Longnecker in 2017 covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives of these companies. In preparing the review materials, Longnecker utilized generally accepted compensation principles as determined by WorldatWork and gathered data from the public peer companies and published salary surveys.

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Following Longnecker’s 2017 review, the ETE Compensation Committee reviewed the information provided, including Longnecker’s specific conclusions and recommended considerations for all compensation going forward. The ETE Compensation Committee considered and reviewed the results of the study performed by Longnecker to determine if the results indicated that the compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives and considered Longnecker’s conclusions and recommendations. While Longnecker found that ETE is achieving its stated objectives with respect to the “at-risk” approach, they also found that certain adjustments should be implemented to allow ETE to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term) as described below.

Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers, and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the named executive officers are reviewed on an annual basis. As discussed above, the base salaries of our named executive officers are targeted to yield an annual base salary slightly below the median level of market (i.e. approximately the 40^th percentile of market) and are determined by the ETE Compensation Committee after taking into account the recommendations of Mr. Warren.

During the 2017 merit review process, the ETE Compensation Committee considered the recommendations of Mr. Warren, the results of the Longnecker study and the merit increase pool set for all employees of ETP GP and ETP. The ETE Compensation Committee approved an increase to the base salary of Mr. McReynolds of 2.5% to $598,026 from its prior level of $583,440; a 2.5% base salary increase of Mr. McCrea to $1,045,000 from its prior level of $1,020,000; and a 2.5% base salary increase to Mr. Mason to $592,276 from its prior level of $577,830. In the case of Mr. Long, the ETE Compensation Committee approved an increase to Mr. Long’s base salary to $530,000 from its prior level of $459,000, which represents an approximately 15.5% increase and was based largely on the recommendation of Mr. Warren and the results of the Longnecker study. In the case of Mr. Whitehurst, the ETE Compensation Committee approved an increase to Mr. Whitehurst’s base salary to $525,000 from its prior level of $508,725, which represents an approximately 3.2% increase and was based largely on the recommendation of Mr. Warren and the results of the Longnecker study.

The 2.5% increase to Messrs. McReynolds, McCrea and Mason reflected a base salary increase consistent with the 2.5% annual merit increase pool set for all employees of ETE and its affiliates for 2017 approved by the respective compensation committees.

Annual Bonus.  In addition to base salary, the ETE Compensation Committee makes determinations whether to make discretionary annual cash bonus awards to executives, including our named executive officers, following the end of the year under the Energy Transfer Partners, L.L.C. Annual Bonus Plan (the “Bonus Plan”).

These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of financial performance objectives during the year for which the bonuses are awarded in light of the contribution of each individual to our profitability and success during such year. The ETE Compensation Committee also considers the recommendation of our Chairman in determining the specific annual cash bonus amounts for each of the named executive officers. The ETE Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses.

TheETP Compensation Committee’s evaluation of performance and determination of an overall available bonus pool is based on therespective internal earnings target generally based on targeted EBITDA (the “Earnings Target”) budget and the performance of each department compared to the applicable departmental budget (with suchperformance measured based on the specific dollar amount of general and administrative expenses set for each department). The two performance criteria are weighted 75% on internal Earnings Target budget criteria and 25% on internal department financialbudget criteria. Internal Earnings Target is the primary performance factor in determining annual bonuses, while internal department financial budget criteria is considered to ensure that the Partnership is effectively managing general and administrative costs in a prudent manner.

For 2017, the ETE Compensation Committee approved short-term annual cash bonus pool targets for Messrs. McReynolds, Long, Mason and Whitehurst of 130% of their annual base earnings and a bonus pool target of 160% for Mr. McCrea. The 130% target for Mr. Whitehurst represents an increase from his previous target of 125% and represents a desire on the part of the Chairman to align the senior officers that report to him, other than Mr. McCrea, with a consistent bonus target. The targets of the other named executive officers were consistent with the prior year’s targets.

In February 2018, the ETP Compensation Committee certified 2017 performance results under the Bonus Plan, which resulted in a bonus payout of 100% of target, which reflected achievement of 101.6% of the internal Earnings Target and 100% of the budget criteria. Based on the approved results, the ETE Compensation Committee approved a cash bonus relating to the 2017 calendar year to Messrs. McReynolds, Long, McCrea, Mason and Whitehurst in the amounts of $764,306, $625,100, $1,644,554, $756,958, and $667,852, respectively.

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In approving the 2017 bonuses of the named executive officers, the ETE Compensation Committee took into account the achievement by the respective partnerships of all of the targeted performance objectives for 2017 and the individual performances of each of the named executive officers, as well as the study results of Longnecker. The cash bonuses awarded to each of the executive officers for 2017 performance were consistent with their applicable bonus pool targets.

Equity Awards.  In 2017, ETE adopted the Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan (the “ETE Plan”). The ETE Plan authorizes the ETE Compensation Committee, in its discretion, to grant awards of restricted units, phantom units, unit options, unit appreciation rights and other awards related to ETE common units upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the ETE Plan. For 2015 and 2016, no long-term incentive awards were issued under the ETE Plan.

For 2017, the annual long-term incentive targets set by the ETE Compensation Committee for the named executive officers were 500% of annual base salary for Mr. Long, 900% of annual base salary for Mr. McCrea, 500% of annual base salary for Mr. Mason and 400% of base salary for Mr. Whitehurst, which were consistent with the prior year’s targets.

In December 2017, the ETE Compensation Committee in consultation with ETE’s Chairman determined to issue long-term incentive awards under the ETE Plan to the ETE named executive officers, other than Mr. McReynolds, who does not currently receive long-term incentive awards. This determination was made in consideration of limiting the number of units issued under the ETP unit plans for 2017. In December of 2017, the ETE Compensation Committee approved grants of phantom unit awards to Messrs. Long, McCrea, Mason and Whitehurst of 121,074 units, 537,379 units, 135,300 units and 95,945 units, respectively.

The phantom unit awards provide for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, generally subject to continued employment through each specified vesting date. The phantom unit awards entitle the recipients of the phantom unit awards to receive, with respect to each ETE unit subject to such award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by ETE to its unitholders. In approving the grant of such phantom unit awards, the ETE Compensation Committee considered several factors, including the long-term objective of retaining such individuals as key drivers of ETE’s and ETP’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2017 awards would accelerate in the event of the death or disability of the named executive officer or in the event of a change in control of ETE as that term is defined under the ETE Plan.

Upon vesting of the phantom units awarded under the ETE Plan, the ETE Compensation Committee reserves the right to determine if, upon vesting, such phantom units shall be settled in (i) common units of ETE (subject to the approval of the ETE Plan prior to the first vesting date by a majority of ETE’s unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ETE Plan) of the ETE common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property (including, without limitation, delivery of common units of ETP purchased by ETE in the open market) in an amount equal to the Fair Market Value of ETE common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the ETE Compensation Committee in its discretion.

From time to time, the compensation committees of ETP and/or Sunoco LP may make grants under the respective long-term incentive plans to employees and/or directors containing such terms as the respective compensation committee shall determine. The applicable compensation committee determines the conditions upon which the restricted units or restricted phantom units granted may become vested or forfeited, and whether or not any such restricted units or restricted phantom units will have distribution equivalent rights (“DERs”) entitling the grantee to distributions receive an amount in cash equal to cash distributions made by the respective partnership with respect to a like number of partnership common units during the restricted period. For 2017, there were no awards made to the named executive officers under an ETP long-term incentive plan.

In December of 2017, consistent with ETE’s compensation methodology, all of the restricted units and restricted phantom units granted under the long-term incentive plans of ETE, ETP and Sunoco LP, including to the named executive officers, provided for vesting of 60% at the end of the third year and vesting of the remaining 40% at the end of the fifth year, subject to continued employment of the named executive officers through each specified vesting date. The restricted units and restricted phantom unit awards entitle the grantee of the unit awards to receive, with respect to each partnership common unit subject to such restricted unit or restricted phantom unit award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution to the partnership unitholders. In approving the grant of such unit awards, the applicable compensation committee took into account a number of performance factors as well as the long-term objective of retaining such individuals as key drivers of the partnership’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2017 awards would accelerate in the event of the death or disability of the named executive officer or in the event of a change in control of the respective partnership as that term is defined under the applicable long-term incentive plan.

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As described below in the section titled Affiliate/Subsidiary Equity Awards, for 2017, in discussions between the General Partner, the ETE Compensation Committees and the compensation committees of the general partners of ETP and Sunoco, it was determined that for 2017 the value of Messrs. Long, Mason and Whitehurst’s awards would be comprised of restricted/phantom unit awards under the ETE Plan and the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”) in consideration of their roles and responsibilities for all of the partnerships under ETE’s umbrella and, for Messrs. Long and Mason, as members of the Boards of Directors of the general partner of Sunoco. Messrs. Long, Mason and Whitehurst’s total 2017 long-term awards were allocated 80% to the ETE Plan and 20% to the 2012 Incentive Plan. Mr. McCrea’s 2017 long-term incentive award was allocated entirely to the ETE Plan. It is expected that future long-term incentive awards to the named executive officers of ETE will recognize an aggregation of restricted/phantom restricted units under long-term incentive plans of ETE, ETP and/or Sunoco LP, as applicable.

The ETP and SUN Compensation Committees have in the past and may in the future, but are not required to, accelerate the vesting of unvested restricted unit awards in the event of the termination or retirement of an executive officer. None of the compensation committees accelerated the vesting of restricted unit awards to any ETE named executive officers in 2017.

As discussed below under “Potential Payments Upon a Termination or Change of Control,” certain equity awards automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the 2014 awards to Messrs. McCrea and Whitehurst included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause”. For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates by, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates.

We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we undergo a change in control transaction. In addition, we believe permitting acceleration of vesting upon a change in control and the acceleration of vesting awards upon a termination without “cause” in the case of the 2014 awards to Messrs. McCrea and Whitehurst creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and encourage these officers to remain focused on their job responsibilities.

Affiliate and Subsidiary Equity Awards. In addition to their roles as officers of our General Partner during 2017, Messrs. Long, McCrea, Mason and Whitehurst in their roles have certain responsibilities for all of the partnerships under ETE’s umbrella, including with respect to Mr. McCrea as member of the Boards of Directors of the general partners of ETP and with respect to Mr. Long, as Chief Financial Officer of ETP and a member of the Board of Directors of the general partner of Sunoco LP.

The SUN Compensation Committee in December 2017 approved grants of units awards to Messrs. Long, Mason and Whitehurst of 17,097, 19,106 and 13,548 units, respectively under the 2012 Incentive Plan related to Sunoco LP common units. The terms and conditions of the restricted unit/phantom awards to Messrs. Long, Mason and Whitehurst under the 2012 Incentive Plan, as applicable, were the same and provided for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. All of the awards would be accelerated in the event of their death, disability or upon a change in control.

Unit Ownership Guidelines. In December 2013, the Board of Directors of our General Partner adopted the Executive Unit Ownership Guidelines (the “Guidelines”), which set forth minimum ownership guidelines applicable to certain executives of ETE and ETP with respect to ETE, ETP and Sunoco LP common units representing limited partnership interests, as applicable. The applicable Guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility. Under these Guidelines, Mr. McReynolds as ETE’s President and Mr. McCrea as Group Chief Operations Officer and Chief Commercial Officer are expected to own common units having a minimum value of five times their base salaries and Messrs. Long, Mason and Whitehurst are expected to own common units having a minimum value of four times their base salaries. In addition to the named executive officers, the Guidelines also apply to other executives, all of whom are expected to own either directly or indirectly in accordance with the terms of the Guidelines, common units having minimum values ranging from two to four times their respective base salaries.

The ETE Compensation Committee believes that the ownership of ETE, ETP and/or Sunoco LP common units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to ETE’s total unitholder return,

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aligning the interests of such executives with those of ETE’s Unitholders, and promoting ETE’s interest in good corporate governance.

Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines; however, certain covered executives, based on their tenure as an executive, are required to achieve compliance within two years of the December 2013 effective date of the Guidelines. Thus, compliance with the Guidelines was required for Messrs. McReynolds, McCrea and Mason beginning in December 2015, and they were compliant. Compliance for Mr. Long will be required in December 2018, and compliance for Mr. Whitehurst will be required in December 2019.

Covered executives may satisfy the Guidelines through direct ownership of ETE, ETP and/or Sunoco LP common units or indirect ownership by certain immediate family members. Direct or indirect ownership of ETE, ETP and/or Sunoco LP common units shall count on a one-to-one ratio for purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements.

Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less common units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the required ownership level is achieved, ownership of the required common units must be maintained for as long as the covered executive is subject to the Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of the common units in a manner consistent with applicable laws, rules and regulations, including regulations of the SEC and our internal policies, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership level.

The Board of Directors of ETP’s general partner approved and adopted policies substantially identical to the Guidelines described above.

Qualified Retirement Plan Benefits.  The Energy Transfer Partners GP, L.P. 401(k) Plan (the “ETP 401(k) Plan”) is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement.

The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service.

Health and Welfare Benefits.  All full-time employees, including our named executive officers may participate in ETP GP’s health and welfare benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance.

Termination Benefits.  Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or that provide for any payments in the event of a change in control of our General Partner. In addition, ETE Plan, Second Amended and Restated Energy Transfers Partners, L.P. 2008 Long-Term Incentive Plan (the “2008 Incentive Plan”), the Energy Transfer Partners, L.P. Amended and Restated 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”), and the Energy Transfer Partners, L.L.C. Long Term Incentive Plan, as amended and restated (the “ETP Plan”) provide the ETP Compensation Committee with the discretion, unless otherwise specified in the applicable award agreement, to provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change of control, as defined in the plan; (ii) death or (iii) disability, as defined in the applicable plan. In the case of the December 2014 and 2015 long-term incentive awards to the named executive officers under ETP’s 2008 Incentive Plan, the ETP Plan or the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”), the awards would immediately and fully vest all unvested restricted unit awards in the event of a change of control, as defined in the applicable plan. Please refer to “Compensation Tables - Potential Payments Upon a Termination or Change of Control” for additional information.

In addition, ETP GP has also adopted the ETP GP Severance Plan and Summary Plan Description effective as of June 12, 2013, (the “Severance Plan”), which provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Severance Plan). In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two weeks or one year of annual base salary (with a minimum of four weeks of annual base salary) and up to three months of continued group health insurance coverage. The Severance Plan also provides that we may determine to pay benefits in addition to those provided under the Severance Plan based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried

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employees on a nondiscriminatory basis; therefore, amounts that would be payable to our named executive officers upon a Qualified Termination have been excluded from “Compensation Tables – Potential Payments Upon a Termination or Change of Control” below.

ETP Non-Qualified Deferred Compensation Plan (the “ETP NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the ETP NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the ETP NQDC Plan, ETP may make annual discretionary matching contributions to participants’ accounts; however, ETP has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the ETP NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds.

Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the ETP NQDC Plan) of ETP, all ETP NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the ETP NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement. None of our named executive officers currently participate in this plan.

Risk Assessment Related to our Compensation Structure.  We believe that the compensation plans and programs for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of a portion of our operations. Our subsidiaries generally determine whether, and to what extent, their respective named executive officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named executive officers to the Partnership’s success. We and our subsidiaries use restricted units and phantom units rather than unit options for equity awards because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that the interests of employees align with those of our unitholders and our subsidiaries’ unitholders for our long-term performance.

Tax and Accounting Implications of Equity-Based Compensation Arrangements

Deductibility of Executive Compensation

We are a limited partnership and not a corporation for United States federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for United States federal income tax purposes.

Accounting for Unit-Based Compensation

For unit-based compensation arrangements we record compensation expense over the vesting period of the awards, as discussed further in Note 9 to our consolidated financial statements.

Compensation Committee Interlocks and Insider Participation

Mr. Turner and Mr. Richard D. Brannon are the only members of the Compensation Committee. During 2017, no member of the Compensation Committee was an officer or employee of us or any of our subsidiaries or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, neither Mr. Turner nor Mr. Richard D. Brannon is a former employee of ours or any of our subsidiaries.

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Report of Compensation Committee

The board of directors of our General Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the management of ETE. Based on this review and discussion, we have recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

The Compensation Committee of the

Board of Directors of LE GP, LLC,

general partner of Energy Transfer Equity, L.P.

K. Rick Turner

Richard D. Brannon

The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this annual report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.

Compensation Tables

Summary Compensation Table

Name and Principal Position	Year	Salary ($)		Bonus (1) ($)		Equity Awards (2) ($)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)		All Other Compensation (3) ($)		Total ($)
ETE Officers:
John W. McReynolds	2017	$	587,928	$	764,306	$	—	$	—	$	—	$	—	$	15,179	$	1,367,413
President	2016	577,280		712,922		—		—		—		—		10,768		1,300,970
	2015	560,154		700,893		—		—		—		—		11,103		1,272,150
Thomas E. Long	2017	480,846		625,100		2,519,954		—		—		—		18,320		3,644,220
Group Chief Financial Officer	2016	454,154		560,865		2,007,697		—		—		—		14,679		3,037,395
	2015	399,207		480,296		1,447,063		—		—		—		14,282		2,340,848
Marshall S. (Mackie) McCrea, III	2017	1,027,846		1,644,554		9,033,341		—		—		—		16,834		11,722,575
Group Chief Operating Officer and Chief Commercial Officer	2016	1,009,231		1,533,990		8,059,413		—		—		—		14,818		10,617,452
	2015	840,385		1,294,192		6,646,354		—		—		—		14,282		8,795,213
Thomas P. Mason	2017	582,275		756,958		2,816,048								18,618		4,173,899
Executive Vice President and General Counsel	2016	571,729		706,067		2,524,064								14,818		3,816,678
	2015	557,615		6,300,000		2,253,927		—		—		—		14,282		9,125,824
Brad Whitehurst	2017	513,733		667,852		1,996,921								14,275		3,192,781
Executive Vice President and Head of Tax	2016	503,354		597,717		1,777,758								14,816		2,893,645
	2015	485,962		584,673		1,587,514		—		—		—		37,947		2,696,096

⁽¹⁾  The discretionary cash bonus amounts earned named executive officers for 2017 reflect cash bonuses approved by the ETE and ETP Compensation Committees in February 2018 that are expected to be paid on or before March 15, 2018.

⁽²⁾  Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards.

⁽³⁾  The amounts reflected for 2017 in this column include (i) matching contributions to the ETP 401(k) Plan made on behalf of the named executive officers of $9,024 for Mr. McReynolds and $13,500 for each Messrs. Long, McCrea, Mason and Whitehurst, respectively, and (ii) the dollar value of life insurance premiums paid for the benefit of the named executive officers. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Unit Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent

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rights were originally granted. For 2017, distribution payments in connection with distribution equivalent rights totaled $423,809 for Mr. Long, $1,928,181 for Mr. McCrea, $680,261 for Mr. Mason and $526,388 for Mr. Whitehurst.

Grants of Plan-Based Awards Table

Name	Grant Date	All Other Unit Awards: Number of Units (#)	All Other Option Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Option Awards ($ / Unit)		Grant Date Fair Value of Unit Awards (1)
ETE Unit Awards:
Thomas E. Long	12/20/2017	121,074	—	$	—	$	2,035,254
Marshal S. (Mackie) McCrea, III	12/20/2017	537,379	—	—		9,033,341
Thomas P. Mason	12/20/2017	135,300	—	—		2,274,393
Bradford D. Whitehurst	12/20/2017	95,945	—	—		1,612,835
Sunoco LP Unit Awards:
Thomas E. Long	12/21/2017	17,097	—	—		484,700
Thomas P. Mason	12/21/2017	19,106	—	—		541,655
Bradford D. Whitehurst	12/21/2017	13,548	—	—		384,086

⁽¹⁾  We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our consolidated financial statements.

Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table

A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, nonqualified deferred compensation earnings (and losses), and 401(k) plan contributions can be found in the Compensation Discussion and Analysis that precedes these tables.

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Outstanding Equity Awards at 2017 Fiscal Year-End Table

Name	Grant Date (2)	Unit Awards (1)
		Number of Units That Have Not Vested (#)	Market or Payout Value of Units That Have Not Vested ($) (3)
ETE Unit Awards:
Thomas E. Long	12/20/2017	121,074	2,089,737
Marshal S. (Mackie) McCrea, III	12/20/2017	537,379	9,275,162
Thomas P. Mason	12/20/2017	135,300	2,335,278
Bradford D. Whitehurst	12/20/2017	95,945	1,656,011
ETP Unit Awards:
Thomas E. Long	12/29/2016	59,053	1,058,229
	12/9/2015	27,788	497,952
	12/4/2015	11,208	200,847
	12/16/2014	8,192	146,792
	12/5/2013	6,516	116,767
Marshal S. (Mackie) McCrea, III	12/29/2016	336,386	6,028,028
	12/9/2015	185,261	3,319,868
	12/4/2015	93,390	1,673,549
	12/16/2014	37,590	673,613
	12/5/2014	16,454	294,863
	12/30/2013	41,625	745,920
	12/3/2013	21,840	391,373
Thomas P. Mason	12/29/2016	79,384	1,422,552
	12/9/2015	43,733	783,686
	12/4/2015	22,046	395,064
	12/16/2014	12,963	232,297
	12/5/2014	6,047	108,362
	12/30/2013	24,554	440,004
Bradford D. Whitehurst	12/29/2016	55,913	1,001,952
	12/9/2015	30,803	551,981
	12/4/2015	15,528	278,262
	12/16/2014	11,138	199,584
	12/5/2014	5,224	93,614
	8/1/2014	26,995	483,751
	12/30/2013	16,922	303,239
Sunoco LP Unit Awards:
Thomas E. Long	12/21/2017	17,097	485,555
	12/29/2016	22,210	630,764
	12/16/2015	14,125	401,150
Thomas P. Mason	12/21/2017	19,106	542,610
	12/29/2016	23,300	661,720
	12/16/2015	18,523	526,053
Bradford D. Whitehurst	12/21/2017	13,548	384,763
	12/29/2016	16,410	466,044
	12/16/2015	13,046	370,506

⁽¹⁾  In connection with the April 28, 2017 merger between ETP and Sunoco Logistics, each outstanding unvested ETP restricted unit converted into 1.5 units of Sunoco Logistics, maintaining the same terms as the original ETP award. In connection with the merger, Sunoco Logistics changed its name to Energy Transfer Partners, L.P. Certain of these outstanding awards represent ETP awards that converted into Sunoco Logistics awards in connection with the merger.

⁽²⁾  ETE phantom unit awards outstanding vest at a rate of 60% in December 2020 and 40% in December 2022 for awards granted in December 2017. Such awards may be settledat the election of the ETE Compensation Committee in (i) common units of

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ETE (subject to the approval of the ETE Plan prior to the first vesting date by a majority of ETE’s unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ETE Plan) of the ETE common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property (including, without limitation, delivery of common units of ETP purchased by ETE in the open market) in an amount equal to the Fair Market Value of ETE common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the ETE Compensation Committee in its discretion.

ETP and Sunoco LP common unit awards outstanding vest as follows:

• at a rate of 60% in December 2019 and 40% in December 2021 for awards granted in December 2016;

• at a rate of 60% in December 2018 and 40% in December 2020 for awards granted in December 2015;

• 100% in December 2019 for the remaining outstanding portion of awards granted in December 2014; and

• 100% in December 2018 for the remaining outstanding portion of all other awards.

⁽³⁾  Market value was computed as the number of unvested awards as of December 31, 2017 multiplied by the closing price of respective common units of ETE, ETP and Sunoco LP.

Option Exercises and Units Vested Table

	Unit Awards
Name	Number of Units Acquired on Vesting (#)	Value Realized on Vesting ($) (1)
ETP Unit Awards:
Thomas E. Long	18,471	301,576
Marshall S. (Mackie) McCrea, III	107,732	1,758,957
Thomas P. Mason	46,513	759,418
Bradford D. Whitehurst	24,540	400,665

⁽¹⁾  Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of common units for ETP upon the vesting date.

We have not issued option awards.

Nonqualified Deferred Compensation

A description of the key provisions of the Partnership’s non-qualified deferred compensation plan can be found in the compensation discussion and analysis above. None of the named executive officers participated in the plan in 2017.

Potential Payments Upon a Termination or Change of Control

Equity Awards. As discussed in our Compensation Discussion and Analysis above, any unvested equity awards granted pursuant the ETE Plan will automatically become vested upon a change of control, which is generally defined as the occurrence of one or more of the following events: (i) any person or group becomes the beneficial owner of 50% or more of the voting power or voting securities of ETE or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be the general partner of ETE; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the assets of ETE in one or more transactions to anyone other than an affiliate of ETE.

In addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the restricted unit awards under the equity incentive plans of ETE and its affiliated partnerships, generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. All awards granted in 2015, 2016 and 2017 under the ETE Plan, the 2008 Incentive Plan, the 2011 Incentive Plan, the ETP Plan and the 2012 Incentive Plan would be accelerated in the event of a change in control of the Partnership.

The 2014 awards to Messrs. McCrea and Whitehurst, whether awarded under the 2008 Incentive Plan, the 2011 Incentive Plan or the Sunoco Logistic Plan included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause.” For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea

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as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates.

In addition, the ETE Compensation Committee, the ETP Compensation Committees and the compensation committee of the general partner of Sunoco LP, have approved a retirement provision, which provides that employees, including the named executive officers with at least ten years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The Sunoco Logistics Compensation Committee beginning with awards made in December 2014 have included a provision in the award agreement which provides that employees, including the named executive officers with at least ten years of service with the general partner, who leave the general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409(A).

With respect to Mr. Mason, in February 2016, the ETE Compensation Committee approved a one-time special incentive retention bonus in the amount of $6,300,000 (the “Special Bonus”).  The Special Bonus was approved by the ETE Compensation Committee based on a recommendation of ETE senior management in recognition of, among other things, (i) Mr. Mason’s appointment as the Executive Vice President and General Counsel of the General Partner; (ii) his 2015 calendar year performance; and (iii) his contributions to ETE and its family of partnerships on several key initiatives, including (a) the drop-down transactions by and between ETP and Sunoco LP, (b) the proposed merger transaction between the ETE and The Williams Companies, Inc., (c) the liquefied natural gas (LNG) export project of ETE, and (d) the simplification of the overall Energy Transfer family structure.  The approval of the Special Bonus by the ETE Compensation Committee was conditioned upon entry by Mr. Mason into a Retention Agreement with ETE (the “Retention Agreement”) which provides (i) if, prior to the third (3^rd) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment with ETE or one of its affiliates terminates (other than as a result of (x) a termination without cause by ETE or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability as determined by ETE), he will be obligated to remit and repay one-hundred percent (100%) of the Special Bonus to ETE; (ii) if, after the third (3^rd) anniversary but prior to the fourth (4^th) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment with ETE or one of its affiliates terminates (other than as a result of (x) a termination without cause by ETE or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability as determined by ETE), he will be obligated to remit and repay seventy-five percent (75%) of the Special Bonus to ETE; and (iii) if, after the fourth (4^th) anniversary but prior to the fifth (5^th) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment with ETE or one of its affiliates terminates (other than as a result of (x) a termination without cause by ETE or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability as determined by ETE), he will be obligated to remit and repay fifty percent (50%) of the Special Bonus to ETE.  Mr. Mason and ETE entered into the Retention Agreement on February 24, 2016.

Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the ETP NQDC Plan (other than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the ETP NQDC Plan), distributions from the respective plan would be made in accordance with the normal distribution provisions of the respective plan. A change of control is generally defined in the ETP NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5).

CEO Pay Ratio

In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Mr. McReynolds, our President and the annual total compensation of our employees. We are using Mr. McReynolds for purposes of the CEO pay ratio as ETE does not have an elected Chief Executive Officer and Mr. McReynolds serves as ETE’s principal executive officer. Mr. Kelcy Warren serves as ETE’s Chairman and the Chairman and Chief Executive Officer of ETP. Additionally, for purposes of this disclosure we used the same data used for the ETP CEO pay ratio as the employee base supporting ETP is substantially the same employee base supporting ETE.

For the 2017 calendar year:

The annual total compensation of Mr. McReynolds, as reported in the Summary Compensation Tables of this Item 11was $1,367,413; and

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The median total compensation of the employees supporting ETP (other than Mr. Warren) was $115,226.

Based on this information, for 2017 the ration of the annual total compensation of Mr. McReynolds to the median of the annual total compensation of the 8,494 employees supporting ETP, which is substantially the same employee base supporting ETE, as of December 31, 2017 was approximately 12 to 1.

To identify the median of the annual total compensation of the employees supporting ETE and ETP, the following steps were taken:

1. It was determined that, as of December 31, 2017, the applicable employee populations consisted of 8,494 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2017 that are required to be included in our employee population for the CEO pay ratio evaluation.

2. To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2017.

3. We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee.”

4. Once we identified our median employee, we combined all elements of the employee’s compensation for 2017 resulting in an annual compensation of $115,226. The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $10,800) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $5,846 per employee, includes $3,633 per employee on average matching contribution and $2,213 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).

5. With respect to Mr. McReynolds, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table under this Item 11.

Director Compensation

Directors of our General Partner, who are employees of the ETP GP or any of their subsidiaries, are not eligible for director compensation. In 2017, the compensation arrangements for outside directors included a $50,000 annual retainer for services on the board. If a director served on the ETE Audit Committee, such director would receive an annual retainer ($10,000 or $15,000 in the case of the chairman) and meeting attendance fees ($1,200). If a director served on the ETE Compensation Committee, such director would receive an annual cash retainer ($5,000 or $7,500 in the case of the chairman) and meeting attendance fees ($1,200).

The outside directors of our General Partner are also entitled to an annual award under the ETE Plan equal to an aggregate of $100,000 divided by the closing price of ETE common units on the date of grant. These ETE common units will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of the ETE common units and is recognized over the vesting period. Distributions are paid during the vesting period.

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The compensation paid to the non-employee directors of our General Partner in 2017 is reflected in the following table:

Name	Fees Paid in Cash(1) ($)		Unit Awards(2) ($)		All Other Compensation ($)		Total ($)
Richard D. Brannon
As ETE director	$	83,965	$	99,991	$	—	$	183,956
K. Rick Turner
As ETE director	80,700		99,991		—		180,691
As Sunoco LP Director	82,100		100,008		—		182,108
William P. Williams
As ETE director	74,600		99,991		—		174,591
As Sunoco LP Director					—		—

⁽¹⁾  Fees paid in cash are based on amounts paid during the period.

⁽²⁾  Unit award amounts reflect the aggregate grant date fair value of awards granted based on the market price of ETE common units, ETP common units or Sunoco LP Common Units, accordingly, as of the grant date.

As of December 31, 2017, Mr. Brannon had 7,716 unvested ETE restricted units outstanding, Mr. Turner had 20,423 unvested ETE restricted units outstanding and Mr. Williams had 15,739 ETE restricted units outstanding.

For 2018, the Board of our General Partner has approved modifications to the compensation of non-employee directors of our General Partner. The directors will receive an annual retainer fee of $100,000 in cash up from $50,000 in 2017. In addition, the Chairman of the Audit Committee will receive an annual fee of $25,000 up from $15,000 in 2017 and the members of the Audit Committee will receive an annual fee of $15,000 up from $10,000. The Chairman of our Compensation Committee will receive an annual fee of $15,000 up from 7,500 in 2017 and the members of our Compensation Committee will receive an annual fee of $7,500 up from $5,000 in 2017. The fees for membership on the Conflicts Committee will continue to be determined on a per instance basis for each Conflicts Committee assignment.

Additionally for 2018, the value of equity awards issued to the non-employee directors will remain equal to an aggregate of $100,000 to be divided by the closing price of our Common Units on the date of grant. Equity awards will also continue to vest 60% after the third year and the remaining 40% after the fifth year after the grant date.

The proposed compensation changes for the non-employee directors for 2018 were developed in consultation with Mr. Warren after considering the results of a review of directors’ compensation by Longnecker during 2017.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Equity Compensation Plan Information

At the time of our initial public offering, we adopted the Energy Transfer Equity, L.P. Long-Term Incentive Plan for the employees, directors and consultants of our General Partner and its affiliates who perform services for us. The long-term incentive plan provides for the following five types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The long-term incentive plan limits the number of units that may be delivered pursuant to awards to three million units. Units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The plan is administered by the compensation committee of the board of directors of our General Partner.

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The following table sets forth in tabular format, a summary of our equity plan information as of December 31, 2017:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	—	$	—	—
Equity compensation plans not approved by security holders:
Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan	1,198,239	—		10,752,488
Total	1,198,239	$	—	10,752,488

Energy Transfer Equity, L.P. Units

The following table sets forth certain information as of February 16, 2018, regarding the beneficial ownership of our voting securities by (i) certain beneficial owners of more than 5% of our Common Units, (ii) each director and named executive officer of our General Partner and (iii) all current directors and executive officers of our General Partner as a group. The General Partner knows of no other person not disclosed herein who beneficially owns more than 5% of our Common Units.

Name and Address of Beneficial Owner (1)	Beneficially Owned (2)	Percent of Class
Kelcy L. Warren (3)	187,739,220	17.4	%
Ray C. Davis (4)	70,058,606	6.5	%
John W. McReynolds (5)	25,085,888	2.3	%
Thomas E. Long	—	*
Marshall S. (Mackie) McCrea, III	1,177,570	*
Thomas P. Mason	583,000	*
Brad Whitehurst (6)	9,145	*
Richard D. Brannon	38,400	*
Matthew S. Ramsey	52,317	*
K. Rick Turner (7)	452,072	*
William P. Williams (8)	5,392,728	*
All Directors and Executive Officers as a group (11 persons)	290,588,946	26.9	%

* Less than 1%

⁽¹⁾  The address for Mr. Davis is 5950 Sherry Lane, Dallas, Texas 75225. The address for all other listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.

⁽²⁾  Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days. The nature of beneficial ownership for all listed persons is direct with sole investment and disposition power unless otherwise noted. The beneficial ownership of each listed person is based on 1,079,145,561 Common Units outstanding in the aggregate as of February 16, 2018. The number of Common Units shown does not include Common Units that may result from the conversion of ETE Series A Convertible Preferred Units, since such conversion is not expected to occur within sixty days of the date of this annual report.

⁽³⁾  Includes 79,102,200 Common Units held by Kelcy Warren Partners, L.P. and 8,244,900 Common Units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 73,853,812 Common Units held by Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 5,012 Common Units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and

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dispositive power with Ray Davis. Also includes 601,076 Common Units held by LE GP, LLC. Mr. Warren may be deemed to own Common Units held by LE GP, LLC due to his ownership of 81.2% of its member interests. The voting and disposition of these Common Units is directly controlled by the board of directors of LE GP, LLC. Mr. Warren disclaims beneficial ownership of Common Units owned by LE GP, LLC other than to the extent of his interest in such entity. Also includes 84,000 Common Units held by Mr. Warren’s spouse.

⁽⁴⁾  Includes 41,692 Common Units held by Avatar Holdings LLC, 1,092,436 Common Units held by Avatar BW, Ltd., 22,742,680 Common Units held by Avatar ETC Stock Holdings LLC, 2,868,948 Common Units held by Avatar Investments LP, 97,668 Common Units held by Avatar Stock Holdings, LP and 817,216 Common Units held by RCD Stock Holdings, LLC, all of which entities are owned or controlled by Mr. Davis. Also includes 12,892,020 Common Units held by a remainder trust for Mr. Davis’ spouse and 7,689,900 Common Units held by two trusts for the benefit of Mr. Davis’ grandchildren, for which Mr. Davis serves as trustee. Mr. Davis shares voting and dispositive power with his wife with respect to Common Units held directly. Also includes 264,806 Common Units attributable to ET Company Ltd. Mr. Davis is a former executive officer of ETP and former director of our General Partner.

⁽⁵⁾  Includes 14,490,408 Common Units held by McReynolds Energy Partners L.P. and 10,086,280 Common Units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of Common Units owned by such limited partnerships other than to the extent of his interest in such entities.

⁽⁶⁾  Includes 4,430 Common Units held in a family trust. Mr. Whitehurst disclaims beneficial ownership of the Common Units held by such trust, except to the extent of his interest in such trust.

⁽⁷⁾  Includes (i) 89,084 Common Units held in a partnership controlled by the Stephens Group, Mr. Turner’s former employer; (ii) 8,000 Common Units held by the Turner Family Partnership; and (iii) 157,790 Common Units held by the Turner Liquidating Trust. The voting and disposition of the Common Units held by the Stephens Group partnership is controlled by the board of directors of the Stephens Group. With respect to the Common Units held by the Turner Family Partnership, Mr. Turner exercises voting and dispositive power as the general partner of the partnership; however, he disclaims beneficial ownership of these Common Units, except to the extent of his interest in the partnership. With respect to the Common Units held by the Turner Liquidating Trust, Mr. Turner exercises one-third of the shared voting and dispositive power with the administrator of the liquidating trust and Mr. Turner’s ex-wife, who beneficially owns an additional 157,790 Common Units. Mr. Turner disclaims beneficial ownership of the Common Units owned by his ex-wife.

⁽⁸⁾  Includes 2,338,484 Common Units held by the William P and Jane C Family Partnership Ltd. and 3,032,028 Common Units held by the Bar W Barking Cat LTD Partnership. Mr. Williams disclaims beneficial ownership of Common Units owned by such entities, except to the extent of his interest in such entities.

In connection with the Parent Company Credit Agreement, ETE and certain of its subsidiaries entered into a Pledge and Security Agreement (the “Security Agreement”) with Credit Suisse AG, Cayman Islands Branch, as collateral agent (the “Collateral Agent”). The Security Agreement secures all of ETE’s obligations under the Parent Company Credit Agreement and grants to the Collateral Agent a continuing first priority lien on, and security interest in, all of ETE’s and the other grantors’ tangible and intangible assets.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

At December 31, 2017, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, approximately 2.3 million Sunoco LP common units and 12 million Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and cash flows from the operations of Lake Charles LNG.

ETP and Sunoco LP are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.

In connection with ETE’s 2014 acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 8 to our consolidated financial statements.

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Mr. McCrea, a current director of LE GP, LLC, our General Partner, is also a director and executive officer of ETP GP. In addition, Mr. Warren, the Chairman of our Board of Directors, is also a director and executive officer of ETP GP.

For a discussion of director independence, see Item 10. “Directors, Executive Officers and Corporate Governance.”

As a policy matter, our Conflicts Committee generally reviews any proposed related party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of directors makes the determinations as to whether there exists a related party transaction in the normal course of reviewing transactions for approval as the Partnership’s board of directors is advised by its management of the parties involved in each material transaction as to which the board of directors’ approval is sought by the Partnership’s management. In addition, the Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in the proposed transaction. While there are no written policies or procedures for the board of directors to follow in making these determinations, the Partnership’s board makes those determinations in light of its contractually-limited fiduciary duties to the Unitholders. The partnership agreement of ETE provides that any matter approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to ETE, approved by all the partners of ETE and not a breach by the General Partner or its Board of Directors of any duties they may owe ETE or the Unitholders (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.

ETP previously had an operating lease agreement with the former owners of ETG, including Mr. Warren and Mr. Davis. ETP paid these former owners $5 million in annual operating lease payments during the term of the lease and made a one-time payment of $8.8 million in August 2017 and we retained the equipment when the lease expired at that time. With respect to the related party transaction with ETG, the Conflicts Committee of ETP met numerous times prior to the consummation of the transaction to discuss the terms of the transaction. The committee made the determination that the sale of ETG to ETP was fair and reasonable to ETP and that the terms of the operating lease between ETP and the former owners of ETG are fair and reasonable to ETP.

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

The following sets forth fees billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered (dollars in millions):

	Years Ended December 31,
	2017		2016
Audit fees (1)	$	11.5	$	9.9
Audit-related fees (2)	—		0.6
Tax fees (3)	—		0.1
Total	$	11.5	$	10.6

⁽¹⁾  Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal controls over financial reporting.

⁽²⁾  Includes fees in 2016 for financial statement audits and interim reviews of subsidiary entities in connection with contribution and sale transactions. Includes fees in 2016 in connection with the service organization control report on Panhandle’s centralized data center.

⁽³⁾  Includes fees related to state and local tax consultation.

Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.

The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2017 and 2016 were pre-approved by the Audit Committee in accordance with this policy.

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The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):

• the auditors’ internal quality-control procedures;

• any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;

• the independence of the external auditors;

• the aggregate fees billed by our external auditors for each of the previous two years; and

• the rotation of the lead partner.

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PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this Report:		Page
	(1) Financial Statements – see Index to Financial Statements	F - 1
	(2) Financial Statement Schedules – None
	(3) Exhibits – see Index to Exhibits	149
(b) Exhibits - see Index to Exhibits		149
(c) Financial statements of affiliates whose securities are pledged as collateral - See Index to Financial Statements on page S-1.		S - 1

The Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP constitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP are required under Rule 3-16 to be included in this Annual Report on Form 10-K and have been included herein.

The Parent Company’s interest in ETP GP also constitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of ETP GP would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. ETP GP does not have substantive operations of its own; rather, ETP GP only owns the general partner interest in ETP.

As further discussed in Note 6 to the consolidated financial statements, as referenced in (a) above, the financial statements of ETP GP would substantially duplicate information that is available in the financial statements of ETP. Therefore, the financial statements of ETP GP have been excluded from this Annual Report on Form 10-K.

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ITEM 16. FORM 10-K SUMMARY

None.

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INDEX TO EXHIBITS

The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.

Exhibit Number	Description
2.1	Redemption and Transfer Agreement, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. dated November 19, 2013 (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-32740, filed November 21, 2013)
2.2	Exchange and Repurchase Agreement, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC, dated December 23, 2014 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed December 23, 2014)
2.3	Agreement and Plan of Merger, dated as of September 28, 2015, among Energy Transfer Corp LP, ETE Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC, ETE GP, LLC and The Williams Companies, Inc. (incorporated by reference to Exhibit 2.1 of Form 8-K/A, File No. 1-32740, filed October 2, 2015)
2.4	Agreement and Plan of Merger, dated as of January 25, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners, GP, L.P., Regency Energy Partners LP, Regency GP LP and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-11727, filed January 26, 2015)
2.5	Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Rendezvous I LLC, Rendezvous II LLC, Regency Energy Partners LP, Regency GP LP, ETE GP Acquirer LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K, File No. 1-11727, filed February 19, 2015)
2.6	Agreement and Plan of Merger, dated as of November 20, 2016, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Sunoco Logistics Partners L.P., Sunoco Partners LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporate by reference to Exhibit 2.1 of Form 8-K File No. 1-11727, filed November 21, 2016
2.7	Amendment No. 1 to Agreement and Plan of Merger, dated as of December 16, 2016, by and among Sunoco Logistics Partners L.P., Sunoco Partners LLC, SXL Acquisition Sub LLC, SXL Acquisition Sub LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETP Acquisition Sub, LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K File No. 1-11727, filed December 21, 2016
2.8	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 Registrant’s Form 8-K filed January 16, 2018).
2.9	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 Registrant’s Form 8-K filed January 16, 2018).
3.1	Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 of Form S-1, File No. 333-128097, filed September 2, 2005)
3.2	Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed February 14, 2006)
3.3	Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. dated November 1, 2006 (incorporated by reference to Exhibit 3.3.1 of Form 10-K, File No. 1-32740, filed November 29, 2006)
3.4	Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007 (incorporated by reference to Exhibit 3.3.2 of Form 8-K, File No. 1-32740, filed November 13, 2007)
3.5	Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed June 2, 2010)
3.6	Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed December 27, 2013)
3.7	Amendment No. 5 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated as of March 8, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed March 9, 2016)

149

Exhibit Number	Description
4.1	Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-32740, filed September 20, 2010)
4.2	First Supplemental Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.15 of Form 8-K, File No. 1-32740, filed September 20, 2010)
4.3	Second Supplemental Indenture, dated December 20, 2011 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form S-3, File No. 1-32740, filed November 14, 2013)
4.4	Second Supplemental Indenture, dated February 16, 2012 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-32740, filed February 17, 2012)
4.5	Fourth Supplemental Indenture, dated December 2, 2013 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed December 2, 2013)
4.6	Fifth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed May 28, 2014)
4.7	Sixth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 1-32740, filed May 28, 2014)
4.8	Seventh Supplemental Indenture, dated May 22, 2015 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed May 22, 2015)
4.9	Eighth Supplemental Indenture dated October 18, 2017 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed October 18th, 2017)
10.1+	Energy Transfer Equity, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.25 of Form S-1, File No. 333-128097, filed December 20, 2005)
10.2+	Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.26 of Form S-1, File No. 333-128097, filed December 20, 2005)
10.3	Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P. and Energy Transfer Investments, L.P. (incorporated by reference to Exhibit 10.38 of Form 10-K, File No. 1-32740, filed November 29, 2006)
10.4	Registration Rights Agreement, dated November 27, 2006, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed November 30, 2006)
10.5+	LE GP, LLC Outside Director Compensation Policy (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed December 26, 2006)
10.6	Registration Rights Agreement, dated March 2, 2007, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed March 5, 2007)
10.7	Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Ray C. Davis, Natural Gas Partners VI, L.P. and Enterprise GP Holdings, L.P. (incorporated by reference to Exhibit 10.45 of Form 8-K, File No. 1-32740, filed May 7, 2007)
10.8	Letter Agreement, dated as of April 29, 2012, by and among Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed May 1, 2012)
10.9	Shared Services Agreement dated as of August 26, 2005, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.30 of Form S-1/A (333-128097) filed December 20, 2005).
10.10	Second Amendment, dated April 30, 2013, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.(incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-32740, filed May 1, 2013)
10.11	Third Amendment, dated February 19, 2014, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010 and April 30, 2013 by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 19, 2014)
10.12	Exchange and Redemption Agreement by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC, dated August 7, 2013 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed August 8, 2013)

150

Exhibit Number	Description
10.13	Credit Agreement, dated as of March 24, 2017 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed March 30, 2017)
10.14	Second Amended and Restated Pledge and Security Agreement, dated December 2, 2013 among Energy Transfer Equity, L.P., the other grantors named therein and U.S. Bank National Association, as collateral agent (incorporated by reference to Exhibit 10.3 of Form 8-K, File No. 1-32740, filed December 2, 2013)
10.15+	Retention Agreement, by and among Energy Transfer Equity, L.P. and Thomas P. Mason, dated February 24, 2016.
10.16	Senior Secured Term Loan Agreement, dated February 2, 2017 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 3, 2017.)
10.1*+	Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan
12.1*	Computation of Ratio of Earnings to Fixed Charges
18.1*	Preferability Letter from Grant Thornton LLP
21.1*	List of Subsidiaries
23.1*	Consent of Grant Thornton LLP related to Energy Transfer Equity, L.P.
23.2*	Consent of Grant Thornton LLP related to Energy Transfer Partners, L.P.
31.1*	Certification of President (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Certification of President (Principal 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 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	Statement of Policies Relating to Potential Conflicts among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and Regency Energy Partners LP dated as of April 26, 2011 (incorporated by reference to Exhibit 99.1 of Form 10-Q, file No. 1-32740, filed August 8, 2011)
101*	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016; (ii) our Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015; (iii) our Consolidated Statements of Comprehensive Income for years ended December 31, 2017, 2016 and 2013; (iv) our Consolidated Statement of Equity for the years ended December 31, 2017, 2016 and 2015; and (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015

*	Filed herewith.
**	Furnished herewith.
+	Denotes a management contract or compensatory plan or arrangement.

151

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 EQUITY, L.P.
		By:	LE GP, LLC,
			its general partner
Date:	February 23, 2018	By:	/s/    Thomas E. Long
			Thomas E. Long
			Group Chief Financial Officer (duly authorized to sign on behalf of the registrant)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated:

Signature	Title	Date
/s/    John W. McReynolds	Director and President	February 23, 2018
John W. McReynolds	(Principal Executive Officer)
/s/    Thomas E. Long	Group Chief Financial Officer (Principal Financial and Accounting Officer)	February 23, 2018
Thomas E. Long
/s/    Kelcy L. Warren	Director and Chairman of the Board	February 23, 2018
Kelcy L. Warren
/s/    Richard D. Brannon	Director	February 23, 2018
Richard D. Brannon
/s/    Marshall S. McCrea, III	Director	February 23, 2018
Marshall S. McCrea, III
/s/    Matthew S. Ramsey	Director	February 23, 2018
Matthew S. Ramsey
/s/    K. Rick Turner	Director	February 23, 2018
K. Rick Turner
/s/    William P. Williams	Director	February 23, 2018
William P. Williams

152

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Equity, L.P. and Subsidiaries

	Page
Report of Independent Registered Public Accounting Firm	F - 2
Consolidated Balance Sheets	F - 3
Consolidated Statements of Operations	F - 5
Consolidated Statements of Comprehensive Income	F - 6
Consolidated Statements of Equity	F - 7
Consolidated Statements of Cash Flows	F - 9
Notes to Consolidated Financial Statements	F - 11

F - 1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of LE GP, LLC and

Unitholders of Energy Transfer Equity, L.P.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Energy Transfer Equity, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 2018 expressed an unqualified opinion thereon.

Change in accounting principle

As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2004.

Dallas, Texas

February 23, 2018

F - 2

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	December 31,
	2017			2016*
ASSETS
Current assets:
Cash and cash equivalents	$	336		$	467
Accounts receivable, net	4,504			3,557
Accounts receivable from related companies	53			47
Inventories	2,022			2,055
Income taxes receivable	136			128
Derivative assets	24			21
Other current assets	295			447
Current assets held for sale	3,313			177
Total current assets	10,683			6,899
Property, plant and equipment	71,177			61,562
Accumulated depreciation and depletion	(10,089		)	(7,984		)
	61,088			53,578
Advances to and investments in unconsolidated affiliates	2,705			3,040
Other non-current assets, net	886			815
Intangible assets, net	6,116			5,512
Goodwill	4,768			5,670
Non-current assets held for sale	—			3,411
Total assets	$	86,246		$	78,925

* As adjusted. See Note 2.

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

F - 3

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	December 31,
	2017			2016*
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	4,685		$	3,502
Accounts payable to related companies	31			42
Derivative liabilities	111			172
Accrued and other current liabilities	2,582			2,367
Current maturities of long-term debt	413			1,194
Current liabilities held for sale	75			—
Total current liabilities	7,897			7,277
Long-term debt, less current maturities	43,671			42,608
Long-term notes payable - related company	—			250
Deferred income taxes	3,315			5,112
Non-current derivative liabilities	145			76
Other non-current liabilities	1,217			1,075
Liabilities associated with assets held for sale	—			48
Commitments and contingencies
Preferred units of subsidiary (Note 7)	—			33
Redeemable noncontrolling interests	21			15
Equity:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)	(1,643		)	(1,871		)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)	450			180
Accumulated other comprehensive loss	—			—
Total partners’ deficit	(1,196		)	(1,694		)
Noncontrolling interest	31,176			24,125
Total equity	29,980			22,431
Total liabilities and equity	$	86,246		$	78,925

* As adjusted. See Note 2.

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

F - 4

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

	Years Ended December 31,
	2017			2016*			2015*
REVENUES:
Natural gas sales	$	4,172		$	3,619		$	3,671
NGL sales	6,972			4,841			3,935
Crude sales	10,184			6,766			8,378
Gathering, transportation and other fees	4,435			4,172			4,200
Refined product sales	11,975			10,097			11,321
Other	2,785			2,297			4,591
Total revenues	40,523			31,792			36,096
COSTS AND EXPENSES:
Cost of products sold	30,966			23,693			28,668
Operating expenses	2,644			2,307			2,303
Depreciation, depletion and amortization	2,554			2,216			1,951
Selling, general and administrative	607			693			548
Impairment losses	1,039			1,040			339
Total costs and expenses	37,810			29,949			33,809
OPERATING INCOME	2,713			1,843			2,287
OTHER INCOME (EXPENSE):
Interest expense, net	(1,922		)	(1,804		)	(1,622		)
Equity in earnings from unconsolidated affiliates	144			270			276
Impairment of investments in unconsolidated affiliates	(313		)	(308		)	—
Gains on acquisitions	—			83			—
Losses on extinguishments of debt	(89		)	—			(43		)
Losses on interest rate derivatives	(37		)	(12		)	(18		)
Other, net	214			132			20
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX BENEFIT	710			204			900
Income tax benefit from continuing operations	(1,833		)	(258		)	(123		)
INCOME FROM CONTINUING OPERATIONS	2,543			462			1,023
Income (loss) from discontinued operations, net of income taxes	(177		)	(462		)	38
NET INCOME	2,366			—			1,061
Less: Net income (loss) attributable to noncontrolling interest	1,412			(995		)	(128		)
NET INCOME ATTRIBUTABLE TO PARTNERS	954			995			1,189
General Partner’s interest in net income	2			3			3
Convertible Unitholders’ interest in net income	37			9			—
Class D Unitholder’s interest in net income	—			—			3
Limited Partners’ interest in net income	$	915		$	983		$	1,183
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.86		$	0.95		$	1.11
Diluted	$	0.84		$	0.93		$	1.11
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.85		$	0.94		$	1.11
Diluted	$	0.83		$	0.92		$	1.11

* As adjusted. See Note 2.

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

F - 5

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

	Years Ended December 31,
	2017			2016*			2015*
Net income	$	2,366		$	—		$	1,061
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	6			2			(3		)
Actuarial gain (loss) relating to pension and other postretirement benefits	(12		)	(1		)	65
Foreign currency translation adjustment	—			(1		)	(1		)
Change in other comprehensive income (loss) from unconsolidated affiliates	1			4			(1		)
	(5		)	4			60
Comprehensive income	2,361			4			1,121
Less: Comprehensive income (loss) attributable to noncontrolling interest	1,407			(991		)	(68		)
Comprehensive income attributable to partners	$	954		$	995		$	1,189

* As adjusted. See Note 2.

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

F - 6

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in millions)

	General Partner			Common Unitholders			Class D Units			Series A Convertible Preferred Units			Accumulated Other Comprehensive Income (Loss)			Non- controlling Interest			Total
Balance, December 31, 2014*	(1		)	648			22			—			(5		)	21,637			22,301
Distributions to partners	(3		)	(1,084		)	(3		)	—			—			—			(1,090		)
Distributions to noncontrolling interest	—			—			—			—			—			(2,335		)	(2,335		)
Subsidiary units issued	(1		)	(524		)	(1		)	—			—			4,415			3,889
Conversion of Class D Units to ETE Common Units	—			7			(7		)	—			—			—			—
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			—			8			—			—			62			70
Capital contributions received from noncontrolling interest	—			—			—			—			—			875			875
Units repurchased under buyback program	—			(1,064		)	—			—			—			—			(1,064		)
Acquisition and disposition of noncontrolling interest	—			—			—			—			—			(65		)	(65		)
Other comprehensive income, net of tax	—			—			—			—			5			55			60
Other, net	—			(118		)	—			—			—			(31		)	(149		)
Net income (loss)	3			1,183			3			—			—			(128		)	1,061
Balance, December 31, 2015*	(2		)	(952		)	22			—			—			24,485			23,553
Distributions to partners	(3		)	(1,019		)	—			—			—			—			(1,022		)
Distributions to noncontrolling interest	—			—			—			—			—			(2,795		)	(2,795		)
Distributions reinvested	—			(173		)	—			173			—			—			—
Subsidiary units issued for cash	—			—			—			—			—			2,559			2,559
Subsidiary units issued for acquisition	—			—			—			—			—			307			307
Issuance of common units	—			39						(2		)	—			—			37
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			—			(22		)	—			—			74			52
Capital contributions received from noncontrolling interest	—			—			—			—			—			236			236
Acquisition and disposition of noncontrolling interest	—			(779		)	—			—			—			—			(779		)
PennTex Acquisition	—			—			—			—			—			236			236
Other comprehensive income, net of tax	—			—			—			—			—			4			4
Other, net	(1		)	30			—			—			—			14			43
Net income (loss)	3			983			—			9			—			(995		)	—
Balance, December 31, 2016*	$	(3	)	$	(1,871	)	$	—		$	180		$	—		$	24,125		$	22,431
Distributions to partners	(2		)	(1,008		)	—			—			—			—			(1,010		)
Distributions to noncontrolling interest	—			—			—			—			—			(2,999		)	(2,999		)
Distributions reinvested	—			(234		)	—			234			—			—			—
Units issuance	—			568			—			—			—			—			568
Subsidiary units issued for cash	—			(55		)	—			(1		)	—			3,291			3,235
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings	—			—			—			—			—			86			86
Capital contributions received from noncontrolling interest	—			—			—			—			—			2,202			2,202
Other, net	—			—			—			—			—			(92		)	(92		)

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

F - 7

PennTex unit acquisition	—			(2		)	—		—		—		(278		)	(280		)
Sale of Bakken Pipeline interest	—			42			—		—		—		1,958			2,000
Sale of Rover Pipeline interest	—			2			—		—		—		1,476			1,478
Other comprehensive loss, net of tax	—			—			—		—		—		(5		)	(5		)
Net income	2			915			—		37		—		1,412			2,366
Balance, December 31, 2017	$	(3	)	$	(1,643	)	$	—	$	450	$	—	$	31,176		$	29,980

* As adjusted. See Note 2.

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

F - 8

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

	Years Ended December 31,
	2017			2016*			2015*
OPERATING ACTIVITIES:
Net income	$	2,366		$	—		$	1,061
Reconciliation of net income to net cash provided by operating activities:
Loss (income) from discontinued operations	177			462			(38		)
Depreciation, depletion and amortization	2,554			2,216			1,951
Deferred income taxes	(1,871		)	(177		)	239
Amortization included in interest expense	24			3			(21		)
Unit-based compensation expense	99			70			91
Impairment losses	1,039			1,040			339
Gains on acquisitions	—			(83		)	—
Losses on extinguishments of debt	89			—			43
Impairment of investments in unconsolidated affiliates	313			308			—
Losses on disposal of assets	—			—			(6		)
Equity in earnings of unconsolidated affiliates	(144		)	(270		)	(276		)
Distributions from unconsolidated affiliates	297			268			409
Inventory valuation adjustments	(24		)	(97		)	67
Other non-cash	(298		)	(239		)	(8		)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	(192		)	(179		)	(872		)
Net cash provided by operating activities	4,429			3,322			2,979
INVESTING ACTIVITIES:
Proceeds from sale of Bakken Pipeline interest	2,000			—			—
Proceeds from sale of Rover Pipeline interest	1,478			—			—
Cash paid for acquisition of PennTex noncontrolling interest	(280		)	—			—
Proceeds from sale of noncontrolling interest	—			—			64
Cash paid for acquisitions, net of cash received	(303		)	(1,398		)	(777		)
Cash paid for acquisition of a noncontrolling interest	—			—			(129		)
Capital expenditures, excluding allowance for equity funds used during construction	(8,444		)	(7,771		)	(9,073		)
Contributions in aid of construction costs	31			71			80
Contributions to unconsolidated affiliates	(268		)	(68		)	(45		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	135			135			128
Proceeds from the sale of other assets	48			35			14
Change in restricted cash	—			14			19
Other	(3		)	—			(16		)
Net cash used in investing activities	(5,606		)	(8,982		)	(9,735		)
FINANCING ACTIVITIES:
Proceeds from borrowings	31,608			25,785			26,455
Repayments of long-term debt	(31,268		)	(19,076		)	(19,828		)
Cash received from affiliate notes	—			5,317			—
Cash paid on affiliate notes	(255		)	(5,051		)	—
Units issued for cash	568			—			—
Subsidiary units issued for cash	3,235			2,559			3,889
Distributions to partners	(1,010		)	(1,022		)	(1,090		)
Distributions to noncontrolling interests	(2,961		)	(2,766		)	(2,335		)
Redemption of ETP Convertible Preferred Units	(53		)	—			—
Debt issuance costs	(131		)	(52		)	(75		)
Capital contributions from noncontrolling interest	1,214			236			841
Units repurchased under buyback program	—			—			(1,064		)
Other, net	6			(3		)	(8		)
Net cash provided by financing activities	953			5,927			6,785
DISCONTINUED OPERATIONS
Operating activities	136			93			90
Investing activities	(38		)	(483		)	(360		)

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

F - 9

Changes in cash included in current assets held for sale	(5		)	5			(13		)
Net increase (decrease) in cash and cash equivalents of discontinued operations	93			(385		)	(283		)
Decrease in cash and cash equivalents	(131		)	(118		)	(254		)
Cash and cash equivalents, beginning of period	467			585			839
Cash and cash equivalents, end of period	$	336		$	467		$	585

* As adjusted. See Note 2.

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

F - 10

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1. OPERATIONS AND ORGANIZATION:

Financial Statement Presentation

The consolidated financial statements of Energy Transfer Equity, L.P. (the “Partnership,” “we” or “ETE”) presented herein for the years ended December 31, 2017, 2016, and 2015, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle, Sunoco LP and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

The consolidated financial statements of ETE presented herein include the results of operations of:

• the Parent Company;

• our controlled subsidiaries, ETP and Sunoco LP;

• consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDR interests in ETP and Sunoco LP; and

• our wholly-owned subsidiary, Lake Charles LNG.

Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

At January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.

As discussed in Note 8, in July 2015, the Partnership completed a two-for-one split of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effects of the unit split for all periods presented.

In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled.

In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. For purposes of maintaining clarity, the following references are used herein:

• References to “ETLP” refer to the entity named Energy Transfer, LP subsequent to the close of the merger;

F - 11

• References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and

• References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.

The historical common units for ETP 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 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. Additionally, for prior periods herein, certain balances have been reclassified to assets and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity.

Business Operations

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our financial statements reflect the following reportable business segments:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the following:

• activities of the Parent Company; and

• the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

ETP is a publicly traded partnership whose operations comprise the following:

• the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales;

• intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia;

• interstate pipelines that are owned and operated, either directly or through equity method investments, that transport natural gas to various markets in the United States; and

• controlling interest in 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.

Sunoco LP is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites.

Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.

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2. ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Change in Accounting Policy

During the fourth quarter of 2017, ETP 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 product and NGL associated with the legacy Sunoco Logistics business. ETP’s management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

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

	Year Ended December 31, 2016									Year Ended December 31, 2015
	As Originally Reported*			Effect of Change			As Adjusted			As Originally Reported*			Effect of Change			As Adjusted
Consolidated Statement of Operations and Comprehensive Income:
Cost of products sold	$	23,652		$	41		$	23,693		$	28,636		$	32		$	28,668
Operating income	1,884			(41		)	1,843			2,319			(32		)	2,287
Income from continuing operations before income tax benefit	245			(41		)	204			932			(32		)	900
Net income	41			(41		)	—			1,093			(32		)	1,061
Net income (loss) attributable to noncontrolling interest	(954		)	(41		)	(995		)	(96		)	(32		)	(128		)
Comprehensive income	45			(41		)	4			1,153			(32		)	1,121
Consolidated Statements of Cash Flows:
Net income	41			(41		)	—			1,093			(32		)	1,061
Inventory valuation adjustments	(267		)	170			(97		)	229			(162		)	67
Net change in operating assets and liabilities (change in inventories)	(50		)	(129		)	(179		)	(1,066		)	194			(872		)
Consolidated Balance Sheets (at period end):
Inventories	2,141			(86		)	2,055			1,498			(45		)	1,453
Noncontrolling interest	24,211			(86		)	24,125			24,530			(45		)	24,485

* Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 3.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill

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impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Recent Accounting Pronouncements

ASU 2014-09

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. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.

For future periods, ETP expects that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of its midstream agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.

We have determined that the timing and/or amount of revenue that we recognize on certain contracts associated with Sunoco LP’s operations will be impacted by the adoption of the new standard. We currently estimate the cumulative catch-up effect to Sunoco LP’s retained earnings as of January 1, 2018 to be approximately $54 million. These adjustments are primarily related to the change in recognition of dealer incentives and rebates.

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. The Partnership expects to adopt ASU 2016-02 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 2016-16

On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.

ASU 2017-04

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

ASU 2017-12

In August 2017, the FASB issued ASU 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

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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.

Revenue Recognition

Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.

Investment in ETP

Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.

The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.

ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead.

In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which ETP operate, competitive factors in the energy industry, and other issues.

Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and segment margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.

ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

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NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.

In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.

ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

Investment in Sunoco LP

Revenues from Sunoco LP’s two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Sunoco LP may sell motor fuel to wholesale customers on a commission agent basis, in which Sunoco LP retains title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. Sunoco LP derives other income from rental income, propane and lubricating oils and other ancillary product and service offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals and other ancillary product and service offerings. Sunoco LP records revenue on a net commission basis when the product is sold and/or services are rendered. Rental income from operating leases is recognized on a straight line basis over the term of the lease.

Investment in Lake Charles LNG

Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal.

Regulatory Accounting – Regulatory Assets and Liabilities

ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of ETP’s regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, ETP ceases to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the NGA and NGPA, it does not currently apply regulatory accounting policies in accounting for its operations.  Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

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Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which 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, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:

	Years Ended December 31,
	2017			2016			2015
Accounts receivable	$	(948	)	$	(1,126	)	$	856
Accounts receivable from related companies	24			42			(5		)
Inventories	58			(480		)	(212		)
Other current assets	38			165			(225		)
Other non-current assets, net	84			(148		)	247
Accounts payable	712			1,170			(1,070		)
Accounts payable to related companies	(178		)	(64		)	400
Accrued and other current liabilities	(97		)	89			(697		)
Other non-current liabilities	106			106			(241		)
Derivative assets and liabilities, net	9			67			75
Net change in operating assets and liabilities, net of effects of acquisitions	$	(192	)	$	(179	)	$	(872	)

Non-cash investing and financing activities and supplemental cash flow information were as follows:

	Years Ended December 31,
	2017			2016			2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,060		$	848		$	910
Net gains (losses) from subsidiary common unit transactions	(56		)	16			(526		)
NON-CASH FINANCING ACTIVITIES:
Issuance of Common Units in connection with the PennTex Acquisition	$	—		$	307		$	—
Contribution of assets from noncontrolling interest	988			—			34
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	1,914		$	1,922		$	1,800
Cash paid for (refund of) income taxes	50			(229		)	72

Accounts Receivable

Our subsidiaries assess the credit risk of their customers and take steps to mitigate risk as necessary. Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and identification of specific customers with payment issues.

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Inventories

As discussed under “Change in Accounting Policy” in Note 2, ETP changed its accounting policy for certain inventory in the fourth quarter of 2017.

Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Inventories consisted of the following:

	December 31,
	2017		2016
Natural gas, NGLs, and refined products	$	1,120	$	1,141
Crude oil	551		651
Spare parts and other	351		263
Total inventories	$	2,022	$	2,055

ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

Other Current Assets

Other current assets consisted of the following:

	December 31,
	2017		2016
Deposits paid to vendors	$	64	$	74
Prepaid expenses and other	231		373
Total other current assets	$	295	$	447

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.

Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.

In 2017, ETP recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, ETP recorded a $133 million fixed asset impairment related to its interstate transportation and storage operations primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in its midstream operations. In 2015, ETP recorded a $110 million fixed asset impairment related to its NGL and refined products transportation and services operations primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for its reporting units during the periods presented.

Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our

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revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:

	December 31,
	2017			2016
Land and improvements	$	2,222		$	1,189
Buildings and improvements (1 to 45 years)	2,786			2,247
Pipelines and equipment (5 to 83 years)	44,673			36,570
Natural gas and NGL storage facilities (5 to 46 years)	1,681			1,451
Bulk storage, equipment and facilities (2 to 83 years)	3,883			3,701
Vehicles (1 to 25 years)	126			217
Right of way (20 to 83 years)	3,432			3,349
Natural resources	434			434
Other (1 to 40 years)	1,029			2,285
Construction work-in-process	10,911			10,119
	71,177			61,562
Less – Accumulated depreciation and depletion	(10,089		)	(7,984		)
Property, plant and equipment, net	$	61,088		$	53,578

We recognized the following amounts for the periods presented:

	Years Ended December 31,
	2017		2016		2015
Depreciation and depletion expense	$	2,204	$	1,952	$	1,661
Capitalized interest	286		201		164

Advances to and Investments in Affiliates

Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.

Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:

	December 31,
	2017		2016
Regulatory assets	85		86
Deferred charges	210		217
Restricted funds	192		190
Other	399		322
Total other non-current assets, net	$	886	$	815

Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.

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Intangible Assets

Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.

Components and useful lives of intangible assets were as follows:

	December 31, 2017					December 31, 2016
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	6,979	$	(1,277	)	$	6,050	$	(971	)
Trade names (20 years)	66		(25		)	66		(22		)
Patents (10 years)	48		(26		)	48		(21		)
Other (5 to 20 years)	28		(14		)	25		(10		)
Total amortizable intangible assets	7,121		(1,342		)	6,189		(1,024		)
Non-amortizable intangible assets:
Trademarks	295		—			288		—
Other	42		—			59		—
Total intangible assets	$	7,458	$	(1,342	)	$	6,536	$	(1,024	)

Aggregate amortization expense of intangibles assets was as follows:

	Years Ended December 31,
	2017		2016		2015
Reported in depreciation, depletion and amortization	$	344	$	264	$	290

Estimated aggregate amortization expense of intangible assets for the next five years was as follows:

Years Ending December 31:
2018	$	341
2019	338
2020	336
2021	319
2022	287

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

Sunoco LP performed impairment tests on their indefinite-lived intangible assets during the fourth quarter of 2017 and recognized $13 million and $4 million impairment charge on their contractual rights and liquor licenses, included in Other in the table above, primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded.

In 2015, ETP recorded $24 million of intangible asset impairments related to its NGL and retail products transportation and services operations primarily due to an expected decrease in future cash flows.

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Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

Changes in the carrying amount of goodwill were as follows:

	Investment in ETP			Investment in Sunoco LP			Investment in Lake Charles LNG		Corporate, Other and Eliminations			Total
Balance, December 31, 2015	$	5,428		$	1,694		$	184	$	(1,250	)	$	6,056
Goodwill acquired	428			81			—		—			509
Sunoco LP Exchange	(1,289		)	—			—		1,289			—
Goodwill impairment	(670		)	(227		)	—		—			(897		)
Other	—			2			—		—			2
Balance, December 31, 2016	3,897			1,550			184		39			5,670
Goodwill acquired	12			—			—		—			12
Goodwill impairment	(793		)	(102		)	—		—			(895		)
Other	(1		)	(18		)	—		—			(19		)
Balance, December 31, 2017	$	3,115		$	1,430		$	184	$	39		$	4,768

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.

During the fourth quarter of 2017, ETP recognized goodwill impairments of $262 million in its interstate transportation and storage operations, $79 million in its NGL and refined products transportation and services operations and $452 million in its all other operations primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. Sunoco LP recognized goodwill impairments of $387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.

During the fourth quarter of 2016, ETP recognized goodwill impairments of $638 million in its interstate transportation and storage operations and $32 million in its midstream operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. Sunoco LP recognized goodwill impairments of $641 million, of which $227 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.

During the fourth quarter of 2015, ETP recognized goodwill impairments of $99 million in its interstate transportation and storage operations and $106 million in its NGL and refined products transportation and services operations primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.

The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

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Asset Retirement Obligations

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.

Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as ofDecember 31, 2017and2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

As of December 31, 2017 and 2016, other non-current liabilities in ETP’s consolidated balance sheets included AROs of $165 million and $170 million, respectively.

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

Long-lived assets related to AROs aggregated to $2 million and $14 million, and were reflected as property, plant and equipment on our consolidated balance sheets as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.

All amounts recorded in our consolidated balance sheets as of December 31, 2017 and 2016 are attributable to the obligations of ETP.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	December 31,
	2017		2016
Interest payable	$	552	$	545
Customer advances and deposits	59		72
Accrued capital expenditures	1,006		769
Accrued wages and benefits	280		254
Taxes payable other than income taxes	108		201
Income taxes payable	180		—
Exchanges payable	154		208
Other	243		318
Total accrued and other current liabilities	$	2,582	$	2,367

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Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests

The noncontrolling interest holders in one of ETP’s consolidated subsidiaries have the option to sell their interests to ETP.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheet.

Environmental Remediation

We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

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 December 31, 2017 was $45.62 billion and $44.08 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations was $45.05 billion and $43.80 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, interest rate derivatives and embedded derivatives in the ETP Convertible Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2017 and 2016, no transfers were made between any levels within the fair value hierarchy.

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2017 and 2016 based on inputs used to derive their fair values:

				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			—
Refined Products – Futures	1			1			—
Crude – Futures	2			2			—
Total commodity derivatives	321			277			44
Other non-current assets	21			14			7
Total assets	$	342		$	291		$	51
Liabilities:
Interest rate derivatives	$	(219	)	$	—		$	(219	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(24		)	(24		)	—
Swing Swaps IFERC	(15		)	(1		)	(14		)
Fixed Swaps/Futures	(57		)	(57		)	—
Forward Physical Swaps	(2		)	—			(2		)
Power — Forwards	(22		)	—			(22		)
Natural Gas Liquids — Forwards/Swaps	(192		)	(192		)
Refined Products – Futures	(28		)	(28		)	—
Crude — Futures	(1		)	(1		)	—
Total commodity derivatives	(341		)	(303		)	(38		)
Total liabilities	$	(560	)	$	(303	)	$	(257	)

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				Fair Value Measurements at
				December 31, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	14		$	14		$	—		$	—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	96			96			—			—
Forward Physical Contracts	1			—			1			—
Power:
Forwards	4			—			4			—
Futures	1			1			—			—
Options — Calls	1			1			—			—
Natural Gas Liquids — Forwards/Swaps	233			233			—			—
Refined Products – Futures	2			2			—			—
Crude – Futures	9			9			—			—
Total commodity derivatives	363			356			7			—
Other non-current assets	13			8			5			—
Total assets	$	376		$	364		$	12		$	—
Liabilities:
Interest rate derivatives	$	(193	)	$	—		$	(193	)	$	—
Embedded derivatives in the ETP Convertible Preferred Units	(1		)	—			—			(1		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(11		)	(11		)	—			—
Swing Swaps IFERC	(3		)	—			(3		)	—
Fixed Swaps/Futures	(149		)	(149		)	—			—
Power:
Forwards	(5		)				(5		)	—
Futures	(1		)	(1		)	—			—
Natural Gas Liquids — Forwards/Swaps	(273		)	(273		)	—			—
Refined Products – Futures	(23		)	(23		)	—			—
Crude — Futures	(13		)	(13		)	—			—
Total commodity derivatives	(478		)	(470		)	(8		)	—
Total liabilities	$	(672	)	$	(470	)	$	(201	)	$	(1	)

Contributions in Aid of Construction Cost

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.

Shipping and Handling Costs

Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

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Costs and Expenses

Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by Sunoco LP’s retail locations where Sunoco LP holds the inventory were $234 million, $243 million and $231 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiaries’ issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.

Income Taxes

ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).

As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, and 2015, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

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At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.

Unit-Based Compensation

For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.

Pensions and Other Postretirement Benefit Plans

ETP recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.  Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.

Allocation of Income

For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

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3. ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

2018 Transactions

CDM Contribution Agreement

In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP 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)19,191,351common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately$335 million, (ii)6,397,965units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately$112 millionand (iii) an amount in cash equal to$1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions.

In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii)12,466,912USAC Common Units for cash consideration equal to$250 million.

Sunoco LP Convenience Store and Real Estate Sale

On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”) and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven (“SEI Fuel” and together with 7-Eleven, referred to herein collectively as “Buyers”). Under the agreement, Sunoco LP sold a portfolio of approximately 1,030 company-operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of $3.3 billion.

Sunoco LP has signed definitive agreements with a commission agent to operate the approximately 207 retail sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the previously announced transaction with 7-Eleven, Inc. Conversion of these sites to the commission agent is expected to occur in the first quarter of 2018.

On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which will be operated by a commission agent.

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The assets under the asset purchase agreement and the real estate assets subject to the portfolio optimization plan comprise the retail divestment presented as discontinued operations (“Retail Divestment”).

The Partnership has concluded that it meets the accounting requirements for reporting results of operations and cash flows of Sunoco LP’s continental United States retail convenience stores as discontinued operations and the related assets and liabilities as held for sale.

The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet:

	December 31, 2017		December 31, 2016
Carrying amount of assets included as part of discontinued operations:
Accounts receivable, net	$	21	$	16
Inventories	149		150
Other current assets	16		11
Property and equipment, net	1,851		1,860
Goodwill	796		1,068
Intangible assets, net	477		480
Other noncurrent assets	3		3
Total assets classified as held for sale in the Consolidated Balance Sheet	$	3,313	$	3,588
Carrying amount of liabilities included as part of discontinued operations:
Other current and noncurrent liabilities	$	75	$	48
Total liabilities classified as held for sale in the Consolidated Balance Sheet	$	75	$	48

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The results of operations associated with discontinued operations are presented in the following table:

	Years Ended December 31,
	2017			2016			2015
REVENUES	$	6,964		$	5,712		$	6,030
COSTS AND EXPENSES
Cost of products sold	5,806			4,649			5,026
Operating expenses	763			744			705
Depreciation, depletion and amortization	34			143			128
Selling, general and administrative	168			114			91
Impairment losses	285			447			—
Total costs and expenses	7,056			6,097			5,950
OPERATING INCOME	(92		)	(385		)	80
Interest expense, net	36			28			21
Other, net	1			8			(2		)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE	(129		)	(421		)	61
Income tax expense	48			41			23
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(177	)	$	(462	)	$	38
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE	$	(6	)	$	(12	)	$	1

In connection with the classification of those assets as held-for-sale, the related goodwill was tested for impairment based on the assumed proceeds from the sale of those assets, resulting in goodwill impairment charges of $285 million recognized in 2017.

2017 Transactions

Rover Contribution Agreement

In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a49.9%interest in the holding company that owns65%of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.

ETP and Sunoco Logistics Merger

As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the Sunoco Logistics Merger.

Permian Express Partners

In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.

In July 2017, the Partnership contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in the Partnership’s ownership interest in PEP to approximately 88%. The Partnership maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance

F - 30

sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a100%membership interest, sold a49%interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for$2.00 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access and ETCO. The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

2016 Transactions

WMB Merger

On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in ETE’s filings in the Delaware lawsuit referenced above. WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court.

PennTex Acquisition

On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately$627 millionin ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, ETP purchased PennTex’s remaining outstanding common units in June 2017.

Summary of Assets Acquired and Liabilities Assumed

We accounted for the PennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.

The total purchase price was allocated as follows:

	At November 1, 2016
Total current assets	$	34
Property, plant and equipment	393
Goodwill(1)	177
Intangible assets	446
	1,050
Total current liabilities	6
Long-term debt, less current maturities	164
Other non-current liabilities	17
Noncontrolling interest	236
	423
Total consideration	627
Cash received	21
Total consideration, net of cash received	$	606

⁽¹⁾  None of the goodwill is expected to be deductible for tax purposes.

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

F - 31

Sunoco Logistics’ Vitol Acquisition

In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for$760 millionplus working capital. The acquisition provides Sunoco Logistics with an approximately2 millionbarrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a50%interest in SunVit Pipeline LLC (“SunVit”), which increased Sunoco Logistics’ overall ownership of SunVit to100%. The$769 millionpurchase price, net of cash received, consisted primarily of net working capital of$13 millionlargely attributable to inventory and receivables; property, plant and equipment of$286 millionprimarily related to pipeline and terminalling assets; intangible assets of$313 millionattributable to customer relationships; and goodwill of$251 million.

Bakken Financing

In August 2016, ETP and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billioncredit facility provided substantially all of the remaining capital necessary to complete the projects. As ofDecember 31, 2017, $2.50 billionwas outstanding under this credit facility.

Bayou Bridge

In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a30%interest in the entity and Sunoco Logistics is the operator of the system.

Sunoco Retail to Sunoco LP

In March 2016, ETP contributed to Sunoco LP its remaining68.42%interest in Sunoco, LLC and100%interest in the legacy Sunoco, Inc. retail business for$2.23 billion. Sunoco LP paid$2.20 billionin cash, including a working capital adjustment and issued5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016.

Sunoco LP Acquisitions

In August 2016, Sunoco LP acquired the fuels business from Emerge Energy Services LP for $171 million, including tax deductible goodwill of $53 million and intangible assets of $56 million. Additionally, during 2016, Sunoco LP made other acquisitions primarily consisting of convenience stores, totaling $114 million plus the value of inventory on hand at closing and increasing goodwill by $61 million.

In October 2016, Sunoco LP completed the acquisition of a convenience store, wholesale motor fuel distribution, and commercial fuels distribution business for approximately $55 million plus inventory on hand at closing, subject to closing adjustments.

2015 Transactions

Sunoco LP

In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons of motor fuel per year to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million in Sunoco LP common units to Retail Holdings, based on the five-day volume-weighted average price of Sunoco LP’s common units as of March 20, 2015.

In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries.

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Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015.

Bakken Pipeline

In March 2015, ETE transferred 46.2 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017.

In October 2015, Sunoco Logistics completed the acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access and ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction.

Regency Merger

On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency surviving as a wholly-owned subsidiary of ETP (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 common units of ETP. ETP issued 258.3 million ETP common units to Regency unitholders, including 23.3 million units issued to ETP subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding new ETP Series A Convertible Preferred Units on a one-for-one basis.

In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.

ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.

4. ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

Citrus

ETP owns CrossCountry, which owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.

FEP

ETP has a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. ETP evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. ETP recorded an impairment of its investment in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor.

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MEP

ETP owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. ETP evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016.

HPC

ETP owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. ETP evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. During the year ended December 31, 2017, ETP recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.

The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2017 and 2016, were as follows:

	December 31,
	2017		2016
Citrus	$	1,754	$	1,729
FEP	121		101
MEP	242		318
HPC	28		382
Others	560		510
Total	$	2,705	$	3,040

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The following table presents equity in earnings (losses) of unconsolidated affiliates:

	December 31,
Equity in earnings (losses) of unconsolidated affiliates:	2017			2016		2015
Citrus	$	144		$	102	$	97
FEP	53			51		55
MEP	38			40		45
HPC(1)	(168		)	31		32
Others	77			46		47
Total	$	144		$	270	$	276

⁽¹⁾  For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented:

	December 31,
	2017		2016
Current assets	$	206	$	214
Property, plant and equipment, net	8,336		8,726
Other assets	43		181
Total assets	$	8,585	$	9,121
Current liabilities	$	861	$	816
Non-current liabilities	4,492		4,940
Equity	3,232		3,365
Total liabilities and equity	$	8,585	$	9,121

	Years Ended December 31,
	2017		2016		2015
Revenue	$	1,358	$	1,164	$	1,385
Operating income	407		714		800
Net income	145		384		470

In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant to our consolidated financial statements.

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5. NET INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of the ETE Series A Convertible Preferred Units, as discussed in Note 8. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP or Sunoco LP that would have resulted assuming the incremental units related to ETP’s or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.

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

	Years Ended December 31,
	2017			2016			2015
Income from continuing operations	$	2,543		$	462		$	1,023
Less: Income (loss) from continuing operations attributable to noncontrolling interest	1,583			(545		)	(165		)
Income from continuing operations, net of noncontrolling interest	960			1,007			1,188
Less: General Partner’s interest in income from continuing operations	2			3			3
Less: Convertible Unitholders’ interest in net income from continuing operations	38			8			—
Less: Class D Unitholder’s interest in income from continuing operations	—			—			3
Income from continuing operations available to Limited Partners	$	920		$	996		$	1,182
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,078.2			1,045.5			1,062.8
Basic income from continuing operations per Limited Partner unit	$	0.86		$	0.95		$	1.11
Basic income (loss) from discontinued operations per Limited Partner unit	$	(0.01	)	$	(0.01	)	$	—
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	920		$	996		$	1,182
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units	38			8			3
Diluted income from continuing operations available to Limited Partners	958			1,004			1,185
Weighted average limited partner units	1,078.2			1,045.5			1,062.8
Dilutive effect of unconverted unit awards and Convertible Units	72.6			33.1			1.6
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	1,150.8			1,078.6			1,064.4
Diluted income from continuing operations per Limited Partner unit	$	0.84		$	0.93		$	1.11
Diluted income (loss) from discontinued operations per Limited Partner unit	$	(0.01	)	$	(0.01	)	$	—

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6. DEBT OBLIGATIONS:

Our debt obligations consist of the following:

	December 31,
	2017			2016
Parent Company Indebtedness:
7.50% Senior Notes due October 15, 2020	$	1,187		$	1,187
5.875% Senior Notes due January 15, 2024	1,150			1,150
5.50% Senior Notes due June 1, 2027	1,000			1,000
4.25% Senior Notes due March 15, 2023	1,000			—
ETE Senior Secured Term Loan due December 2, 2019	—			2,190
ETE Senior Secured Term Loan due February 2, 2024	1,220			—
ETE Senior Secured Revolving Credit Facility due December 18, 2018	—			875
ETE Senior Secured Revolving Credit Facility due March 24, 2022	1,188			—
Unamortized premiums, discounts and fair value adjustments, net	(11		)	(15		)
Deferred debt issuance costs	(34		)	(30		)
	6,700			6,357
Subsidiary Indebtedness:
ETP Debt
6.125% Senior Notes due February 15, 2017	—			400
2.50% Senior Notes due June 15, 2018 (1)	650			650
6.70% Senior Notes due July 1, 2018 (1)	600			600
9.70% Senior Notes due March 15, 2019	400			400
9.00% Senior Notes due April 15, 2019	450			450
5.50% Senior Notes due February 15, 2020	250			250
5.75% Senior Notes due September 1, 2020	400			400
4.15% Senior Notes due October 1, 2020	1,050			1,050
4.40% Senior Notes due April 1, 2021	600			600
6.50% Senior Notes due July 15, 2021	—			500
4.65% Senior Notes due June 1, 2021	800			800
5.20% Senior Notes due February 1, 2022	1,000			1,000
4.65% Senior Notes due February 15, 2022	300			300
5.875% Senior Notes due March 1, 2022	900			900
5.00% Senior Notes due October 1, 2022	700			700
3.45% Senior Notes due January 15, 2023	350			350
3.60% Senior Notes due February 1, 2023	800			800
5.50% Senior Notes due April 15, 2023	—			700
4.50% Senior Notes due November 1, 2023	600			600
4.90% Senior Notes due February 1, 2024	350			350
7.60% Senior Notes due February 1, 2024	277			277
4.25% Senior Notes due April 1, 2024	500			500
9.00% Debentures due November 1, 2024	65			65
4.05% Senior Notes due March 15, 2025	1,000			1,000
5.95% Senior Notes due December 1, 2025	400			400
4.75% Senior Notes due January 15, 2026	1,000			1,000
3.90% Senior Notes due July 15, 2026	550			550
4.20% Senior Notes due April 15, 2027	600			—
4.00% Senior Notes due October 1, 2027	750			—
8.25% Senior Notes due November 15, 2029	267			267
4.90% Senior Notes due March 15, 2035	500			500
6.625% Senior Notes due October 15, 2036	400			400
7.50% Senior Notes due July 1, 2038	550			550
6.85% Senior Notes due February 15, 2040	250			250
6.05% Senior Notes due June 1, 2041	700			700
6.50% Senior Notes due February 1, 2042	1,000			1,000
6.10% Senior Notes due February 15, 2042	300			300

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4.95% Senior Notes due January 15, 2043	350		350
5.15% Senior Notes due February 1, 2043	450		450
5.95% Senior Notes due October 1, 2043	450		450
5.30% Senior Notes due April 1, 2044	700		700
5.15% Senior Notes due March 15, 2045	1,000		1,000
5.35% Senior Notes due May 15, 2045	800		800
6.125% Senior Notes due December 15, 2045	1,000		1,000
5.30% Senior Notes due April 15, 2047	900		—
5.40% Senior Notes due October 1, 2047	1,500		—
Floating Rate Junior Subordinated Notes due November 1, 2066	546		546
ETP $4.0 billion Revolving Credit Facility due December 2022	2,292		—
ETP $1.0 billion 364-Day Credit Facility due November 2018 (2)	50		—
ETLP $3.75 billion Revolving Credit Facility due November 2019	—		2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020	—		1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017	—		630
Unamortized premiums, discounts and fair value adjustments, net	33		66
Deferred debt issuance costs	(170	)	(166	)
	29,210		29,454
Transwestern Debt
5.64% Senior Notes due May 24, 2017	—		82
5.36% Senior Notes due December 9, 2020	175		175
5.89% Senior Notes due May 24, 2022	150		150
5.66% Senior Notes due December 9, 2024	175		175
6.16% Senior Notes due May 24, 2037	75		75
Deferred debt issuance costs	(1	)	(1	)
	574		656
Panhandle Debt
6.20% Senior Notes due November 1, 2017	—		300
7.00% Senior Notes due June 15, 2018	400		400
8.125% Senior Notes due June 1, 2019	150		150
7.60% Senior Notes due February 1, 2024	82		82
7.00% Senior Notes due July 15, 2029	66		66
8.25% Senior Notes due November 14, 2029	33		33
Floating Rate Junior Subordinated Notes due November 1, 2066	54		54
Unamortized premiums, discounts and fair value adjustments, net	28		50
	813		1,135
Sunoco, Inc. Debt
5.75% Senior Notes due January 15, 2017	—		400
Bakken Project Debt
Bakken Project $2.50 billion Credit Facility due August 2019	2,500		1,100
Deferred debt issuance costs	(8	)	(13	)
	2,492		1,087
PennTex Debt
PennTex $275 million Revolving Credit Facility due December 2019	—		168
Sunoco LP Debt
5.50% Senior Notes due August 1, 2020	600		600
6.375% Senior Notes due April 1, 2023	800		800
6.25% Senior Notes due April 15, 2021	800		800
Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019	765		1,000
Sunoco LP Term Loan due October 1, 2019	1,243		1,243
Lease-related obligations	113		118
Deferred debt issuance costs	(34	)	(47	)
	4,287		4,514

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Other	8		31
Total debt	44,084		43,802
Less: current maturities of long-term debt	413		1,194
Long-term debt, less current maturities	$	43,671	$	42,608

⁽¹⁾  As of December 31, 2017 ETP’s management had the intent and ability to refinance the$650 million2.50%senior notes due June 15, 2018 and the$600 million6.70%senior notes due July 1, 2018, and therefore neither was classified as current.

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

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $197 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net:

2018	$	1,705
2019	5,512
2020	3,667
2021	2,205
2022	6,540
Thereafter	24,652
Total	$	44,281

Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.

Notes and Debentures

ETE Senior Notes Offering

In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes.

The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The balance is payable upon maturity. Interest on the senior notes is paid semi-annually.

ETE Senior Notes

The ETE Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ETE Senior Notes are secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ETE Term Loan Facility, by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries.

The covenants related to the ETE Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Parent Company’s assets.

As discussed above, the Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP are required under Rule 3-16 to be included in the Partnership’s Annual Report on Form 10-K and have been included herein.

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The Parent Company’s interests in ETP GP also constitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of ETP GP would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. ETP GP does not have substantive operations of its own; rather, ETP GP only owns 100% of the general partner interest in ETP. ETP GP does not own limited partner interests in ETP; therefore, the limited partner interests in ETP, which had a carrying value of $28.02 billion and $18.41 billion as of December 31, 2017 and 2016, respectively, would be reflected as noncontrolling interests on ETP GP’s balance sheets. Likewise, ETP’s income (loss) attributable to limited partners (including common unitholders, Class H unitholders, Class I unitholders and ETP Preferred Units) of $1.08 billion, $(660) million and $325 million for the years ended December 31, 2017, 2016 and 2015, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations.

ETP’s general partner interest is reflected separately in ETP’s financial statements. As a result, the financial statements of ETP GP would substantially duplicate information that is available in the financial statements of ETP. Therefore, the financial statements of ETP GP have been excluded from the Partnership’s Annual Report on Form 10-K.

ETP Senior Notes

The ETP senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually.

The ETP senior notes are unsecured obligations of ETP and as a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

Transwestern Senior Notes

The Transwestern senior notes are redeemable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is payable semi-annually.

Panhandle Junior Subordinated Notes

The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 4.39% at December 31, 2017.

Sunoco LP Private Offering of Senior Notes

On January 23, 2018, Sunoco LP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in aggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the closing of the asset purchase agreement with 7-Eleven to: 1) redeem in full its existing senior notes as of December 31, 2017, comprised of $800 million in aggregate principal amount of 6.250%senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023; 2) repay in full and terminate the Sunoco LP Term Loan; 3) pay all closing costs and taxes in connection with the 7-Eleven transaction; 4) redeem the outstanding Sunoco LP Series A Preferred Units as mentioned above; and 5) repurchase 17,286,859 common units owned by ETP as mentioned above.

Sunoco LP Senior Notes

In April 2016, Sunoco LP issued $800 million aggregate principal amount of 6.25% Senior Notes due 2021. The net proceeds of $789 million were used to repay a portion of the borrowings under its term loan facility.

The 6.25% Senior Notes due 2021 were redeemed on January 23, 2018. See Sunoco LP Private Offering of Senior Notes above.

Term Loans, Credit Facilities and Commercial Paper

ETE Term Loan Facility

On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term

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subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof. In connection with the Parent Company’s entry into the Senior Secured Term Loan Agreement on February 2, 2017, the Parent Company terminated its previous term loan agreements.

Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP , and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP, and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.

Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.

On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.

In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.

ETE Revolving Credit Facility

The Parent Company had a revolver credit agreement which had a scheduled maturity date of December 2, 2018, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The agreement was terminated in connection with entry into the Revolver Credit Agreement, discussed below.

On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $1.50 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 millionsublimit. Under the Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of December 31, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $312 million.

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ETP Credit Facilities

On December 1, 2017 ETP entered into a five-year, $4.0 billionunsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a$1.0 billion364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitments may be increased up to$6.0 billionunder certain conditions. ETP uses the ETP Credit Facilities to provide temporary financing for its growth projects, as well as for general partnership purposes.

As ofDecember 31, 2017, the ETP Five-Year Facility had$2.29 billion outstanding, of which$2.01 billionwas commercial paper. The amount available for future borrowings was$1.56 billionafter taking into account letters of credit of$150 million. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was2.48%.

As ofDecember 31, 2017, the ETP 364-Day Facility had$50 millionoutstanding, and the amount available for future borrowings was$950 million. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was5.00%.

ETLP Credit Facility

The ETLP Credit Facility allowed for borrowings of up to$3.75 billionand was used to provide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.

Sunoco Logistics Credit Facilities

ETP maintained a$2.50 billionunsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.

In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of$1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017.

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 billioncredit 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 ofDecember 31, 2017, the Bakken Credit Facility had $2.50 billionof outstanding borrowings. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was3.00%.

PennTex Revolving Credit Facility

PennTex previously maintained a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

Sunoco LP Term Loan

Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As ofDecember 31, 2017, the balance on the term loan was $1.24 billion.

The Sunoco LP term loan was repaid in full and terminated on January 23, 2018. See Sunoco LP Private Offering of Senior Notes above.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billionand matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay

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incremental interest owed under the revolving credit facility. As of December 31, 2017, the Sunoco LP credit facility had $9 million in standby letters of credit. The amount available for future borrowings on the revolver at December 31, 2017 was $726 million.

On October 16, 2017, Sunoco LP entered into the Fifth Amendment to the Credit Agreement with the lenders party thereto and Bank of America, N.A., in its capacity as a letter of credit issuer, as swing line lender, and as administrative agent. The Fifth Amendment amended the agreement to (i) permit the dispositions contemplated by the Retail Divestment, (ii) extend the interest coverage ratio covenant of 2.25x through maturity, (iii) modify the definition of consolidated EBITDA to include the pro forma effect of the divestitures and the new fuel supply contracts, and (iv) modify the leverage ratio covenant.

Covenants Related to Our Credit Agreements

Covenants Related to the Parent Company

The Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements.

The Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows:

• Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company to Consolidated EBITDA (as defined therein) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 7 to 1 during a specified acquisition period following the close of a specified acquisition; and

• Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1.

Covenants Related to ETP

The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

The ETP Credit Facilities contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:

• incur indebtedness;

• grant liens;

• enter into mergers;

• dispose of assets;

• make certain investments;

• make Distributions (as defined in the ETP Credit Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit Facilities);

• engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

• engage in transactions with affiliates; and

• enter into restrictive agreements.

The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt.The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from1.125% to 2.000%and the applicable margin for base rate loans ranges from0.125%to1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from0.125%to0.300%.  The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from1.125%to1.750%and the applicable margin for base rate loans ranges from0.250%to0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from0.125%to0.225%.

The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements,

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of 5.0to1, which can generally be increased to5.5to1during a Specified Acquisition Period. Our Leverage Ratio was 3.96to1atDecember 31, 2017, as calculated in accordance with the credit agreements.

The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.

Covenants Related to Panhandle

Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.

In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.

Covenants Related to Bakken Credit Facility

The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:

• prohibition of certain incremental secured indebtedness;

• prohibition of certain liens / negative pledge;

• limitations on uses of loan proceeds;

• limitations on asset sales and purchases;

• limitations on permitted business activities;

• limitations on mergers and acquisitions;

• limitations on investments;

• limitations on transactions with affiliates; and

• maintenance of commercially reasonable insurance coverage.

A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than1.20to1(the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.

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Covenants Related to Sunoco LP

The Sunoco LP Credit Facilities contain various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. The Sunoco LP Credit Facilities  require Sunoco LP to maintain a leverage ratio (as defined therein) of not more than (a) as of the last day of each fiscal quarter through December 31, 2017, 6.75 to 1.0, (b) as of March 31, 2018, 6.5 to 1.0, (c) as of June 30, 2018, 6.25 to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (in the case of the quarter ending March 31, 2019 and thereafter, subject to increases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of $50 million, as permitted under the Credit Facilities.  Indebtedness under the Credit Facilities is secured by a security interest in, among other things, all of Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Credit Facilities will be released.

Compliance With Our Covenants

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.

We and our subsidiaries are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017.

7. ETP CONVERTIBLE PREFERRED UNITS:

The ETP Convertible Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and are reflected as long-term liabilities in our consolidated balance sheets. The ETP Convertible Preferred Units are entitled to a preferential quarterly cash distribution of $0.445 per ETP Preferred Unit if outstanding on the record dates of ETP’s common unit distributions. In January 2017, ETP repurchased all of its1.9 million outstanding ETP Convertible Preferred Units for cash in the aggregate amount of $53 million.

8. EQUITY:

Limited Partner Units

Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.”

As of December 31, 2017, there were issued and outstanding 1.08 billion Common Units representing an aggregate 94.38% limited partner interest in the Partnership.

Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.

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Common Units

The change in ETE Common Units during the years ended December 31, 2017, 2016 and 2015 was as follows:

	Years Ended December 31,
	2017	2016	2015
Number of Common Units, beginning of period	1,046.9	1,044.8	1,077.5
Conversion of Class D Units to ETE Common Units	—	—	0.9
Repurchase of common units under buyback program	—	—	(33.6	)
Issuance of common units	32.2	2.1	—
Number of Common Units, end of period	1,079.1	1,046.9	1,044.8

ETE Equity Distribution Agreement

In March 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the year ended December 31, 2017.

ETE Series A Convertible Preferred Units

	Years Ended December 31,
	2017	2016	2015
Number of Series A Convertible Preferred Units, beginning of period	329.3	—	—
Issuance of Series A Convertible Preferred Units	—	329.3	—
Number of Series A Convertible Preferred Units, end of period	329.3	329.3	—

On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.

The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $450 million carrying value as of December 31, 2017.

ETE issued 329,295,770 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s

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Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates.

ETE January 2017 Private Placement and ETP Unit Purchase

In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units for approximately $568 million.

Common Unit Split

On July 27, 2015, ETE completed a two-for-one split of the Partnership’s outstanding common units by a distribution of one ETE common unit for each common unit outstanding and held by unitholders of record at the close of business on July 15, 2015.

Repurchase Program

In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 33.6 million ETE Common Units under this program in 2015. No units were repurchased under this program in 2017 or 2016, and there was $936 million available to use under the program as of December 31, 2017.

Class D Units

In 2013, the Partnership issued 3,080,000 Class D Units of ETE pursuant to an agreement with a former executive. The Class D Units were convertible to ETE Common Units, subject to certain vesting requirements which were not met prior to the former executive’s termination in 2016.

Sale of Common Units by Subsidiaries

The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented.

Sale of Common Units by ETP

ETP’s Equity Distribution Program

From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, ETP entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion.

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During the year ended December 31, 2017, ETP issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $752 million of ETP’s Common Units remained available to be issued under ETP’s currently effective equity distribution agreement.

ETP’s Equity Incentive Plan Activity

ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by ETP to satisfy tax-withholding obligations.

ETP’s Distribution Reinvestment Program

ETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan.

During the years ended December 31, 2017, 2016 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units.

As of December 31, 2017, a total of 20.8 million Common Units remain available to be issued under the existing registration statement.

August 2017 Units Offering

In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

ETP Class E Units

There are currently 8.9 million ETP Class E Units outstanding, all of which are currently owned by HHI. The ETP Class E Units generally do not have any voting rights. The ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the Class E Unitholders, up to $1.41per unit per year. As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in ETP’s consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the ETP Class E Units at a future date.

ETP Class G Units

There are currently 90.7 million ETP Class G Units outstanding, all of which are held by wholly-owned subsidiaries of ETP. The ETP Class G Units generally do not have any voting rights. The ETP Class G Units are entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and its subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per ETP Class G Unit per year. Allocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are reflected as treasury units in the consolidated financial statements.

ETP Class H Units

Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017.

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ETP Class I Units

In connection with the Bakken Pipeline Transaction discussed in Note 3, in March 2015, ETP issued 100 ETP Class I Units. The ETP Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the ETP Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the ETP Class I Units and (ii) after making cash distributions to ETP Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in ETP’s Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a100%membership interest, sold a49%interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for$2.00 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access and ETCO. The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

Class K Units

On December 29, 2016, ETP issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in ETP, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. If ETP is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5%per annum until paid. As of December 31, 2017, a total of101.5 millionClass K Units were held by wholly-owned subsidiaries of ETP.

Sales of Common Units by Sunoco Logistics

Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.

In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.

In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.

In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In connection with the Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated.

ETP Series A and Series Preferred Units

In November 2017, ETP issued950,000of its6.250%Series A Preferred Units at a price of$1,000per unit, and550,000of its6.625%Series B Preferred Units at a price of$1,000per unit.

Distributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETP Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETP Series A Preferred Units are redeemable at ETP’s option on or after February 15,

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2023 at a redemption price of $1,000 per ETP Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Distributions on the ETP Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETP Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETP Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per ETP Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

PennTex Tender Offer and Limited Call Right Exercise

In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.

Sales of Common Units by Sunoco LP

In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased17,286,859Sunoco 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 October 2016, Sunoco LP entered into an equity distribution agreement pursuant to which Sunoco LP may sell from time to time common units having aggregate offering prices of up to $400 million. Through December 31, 2016, Sunoco LP received net proceeds of $71 million from the issuance of 2.8 million Sunoco LP common units pursuant to such equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes. From January 1, 2017 through December 31, 2017, Sunoco LP issued additional 1.3 million units with total net proceeds of $33 million, net of commissions of $0.3 million. As of December 31, 2017, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.

In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP.

On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership.

In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha Petroleum, Ltd as consideration for the contribution by Aloha to an indirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries.

In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $213 million. The net proceeds from the offering were used to repay outstanding balances under the Sunoco LP revolving credit facility.

Sunoco LP Series A Preferred Units

On March 30, 2017, the Partnership purchased 12.0 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units is10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference.

In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.

Contributions to Subsidiaries

The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP has the right, but not the obligation, to contribute a proportionate amount of capital to ETP to maintain

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its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest.

Parent Company Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Sunoco LP related to limited and general partner interests, including IDRs, as well as cash generated from our investment in Lake Charles LNG.

Our distributions declared and paid with respect to our common units for the periods presented were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 6, 2015	February 19, 2015	0.2250
March 31, 2015	May 8, 2015	May 19, 2015	0.2450
June 30, 2015	August 6, 2015	August 19, 2015	0.2650
September 30, 2015	November 5, 2015	November 19, 2015	0.2850
December 31, 2015	February 4, 2016	February 19, 2016	0.2850
March 31, 2016 (1)	May 6, 2016	May 19, 2016	0.2850
June 30, 2016 (1)	August 8, 2016	August 19, 2016	0.2850
September 30, 2016 (1)	November 7, 2016	November 18, 2016	0.2850
December 31, 2016 (1)	February 7, 2017	February 21, 2017	0.2850
March 31, 2017 (1)	May 10, 2017	May 19, 2017	0.2850
June 30, 2017 (1)	August 7, 2017	August 21, 2017	0.2850
September 30, 2017 (1)	November 7, 2017	November 20, 2017	0.2950
December 31, 2017 (1)	February 8, 2018	February 20, 2018	0.3050

⁽¹⁾  Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See additional information below.

Our distributions declared and paid with respect to our Convertible Unit during the years ended December 31, 2016 and 2017 were as follows:

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2016	May 6, 2016	May 19, 2016	$	0.1100
June 30, 2016	August 8, 2016	August 19, 2016	0.1100
September 30, 2016	November 7, 2016	November 18, 2016	0.1100
December 31, 2016	February 7, 2017	February 21, 2017	0.1100
March 31, 2017	May 10, 2017	May 19, 2017	0.1100
June 30, 2017	August 7, 2017	August 21, 2017	0.1100
September 30, 2017	November 7, 2017	November 20, 2017	0.1100
December 31, 2017	February 8, 2018	February 20, 2018	0.1100

ETP’s Quarterly Distributions of Available Cash

Under ETP’s limited partnership agreement, within 45 days after the end of each quarter, ETP 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 ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP’s business. ETP 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.

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If cash distributions exceed$0.0833per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”

As the holder of Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	IDRs	Partners (1)
Minimum Quarterly Distribution	$0.0750	—%	100%
First Target Distribution	up to $0.0833	—%	100%
Second Target Distribution	above $0.0833 up to $0.0958	13%	87%
Third Target Distribution	above $0.0958 up to $0.2638	35%	65%
Thereafter	above $0.2638	48%	52%

⁽¹⁾Includes general partner and limited partner interests, based on the proportionate ownership of each.

The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:

Quarter Ended	ETP		Sunoco Logistics
December 31, 2014	$	0.6633	$	0.4000
March 31, 2015	0.6767		0.4190
June 30, 2015	0.6900		0.4380
September 30, 2015	0.7033		0.4580
December 31, 2015	0.7033		0.4790
March 31, 2016	0.7033		0.4890
June 30, 2016	0.7033		0.5000
September 30, 2016	0.7033		0.5100
December 31, 2016	0.7033		0.5200

Distributions on common units declared and paid by Post-Merger ETP were as follows:

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 16, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 15, 2017	0.5500
September 30, 2017	November 7, 2017	November 14, 2017	0.5650
December 31, 2017	February 8, 2018	February 14, 2018	0.5650

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

	Total Year
2018	$	153
2019	128
Each year beyond 2019	33

Distributions declared and paid by ETP to the Series A and Series B preferred unitholders 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

Sunoco LP Quarterly Distributions of Available Cash

The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Effective July 1, 2015, ETE exchanged 21 million ETP common units, owned by ETE, the owner of ETP’s general partner interest, for 100% of the general partner interest and all of the IDRs of Sunoco LP. ETP had previously owned our IDRs since September 2014, prior to that date the IDRs were owned by Susser.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Common Unitholders	Holder of IDRs
Minimum Quarterly Distribution	$0.4375	100%	—%
First Target Distribution	$0.4375 to $0.503125	100%	—%
Second Target Distribution	$0.503125 to $0.546875	85%	15%
Third Target Distribution	$0.546875 to $0.656250	75%	25%
Thereafter	Above $0.656250	50%	50%

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Distributions declared and paid by Sunoco LP for the periods presented were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 17, 2015	February 27, 2015	0.6000
March 31, 2015	May 19, 2015	May 29, 2015	0.6450
June 30, 2015	August 18, 2015	August 28, 2015	0.6934
September 30, 2015	November 17, 2015	November 27, 2015	0.7454
December 31, 2015	February 5, 2016	February 16, 2016	0.8013
March 31, 2016	May 6, 2016	May 16, 2016	0.8173
June 30, 2016	August 5, 2016	August 15, 2016	0.8255
September 30, 2016	November 7, 2016	November 15, 2016	0.8255
December 31, 2016	February 13, 2017	February 21, 2017	0.8255
March 31, 2017	May 9, 2017	May 16, 2017	0.8255
June 30, 2017	August 7, 2017	August 15, 2017	0.8255
September 30, 2017	November 7, 2017	November 14, 2017	0.8255
December 31, 2017	February 06, 2018	February 14, 2018	0.8255

Accumulated Other Comprehensive Income (Loss)

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

	December 31,
	2017			2016
Available-for-sale securities	$	8		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain (loss) related to pensions and other postretirement benefits	(5		)	7
Investments in unconsolidated affiliates, net	5			4
Subtotal	3			8
Amounts attributable to noncontrolling interest	(3		)	(8		)
Total AOCI included in partners’ capital, net of tax	$	—		$	—

The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss):

	December 31,
	2017			2016
Available-for-sale securities	$	(2	)	$	(2	)
Foreign currency translation adjustment	3			3
Actuarial loss relating to pension and other postretirement benefits	3			—
Total	$	4		$	1

9. UNIT-BASED COMPENSATION PLANS:

We, ETP and Sunoco LP have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards.

ETE Long-Term Incentive Plan

The Board of Directors or the Compensation Committee of the board of directors of our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom

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units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 12.0 million units. As of December 31, 2017, 10.8 million units remain available to be awarded under the plan.

During the year ended December 31, 2017, 1.2 million ETE unit awards were granted to ETE employees and certain employees of ETP and 15,648 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest 60% in three years and 40% in five years and do not entitle the holders to receive distributions during the vesting period.

During the year ended December 31, 2017 and 2016, a total of 2,018 and 28,648 ETE Common Units vested, with a total fair value of $39 thousand and $205 thousand, respectively, as of the vesting date. As of December 31, 2017, a total of 1,251,002 restricted units remain outstanding, for which we expect to recognize a total of $21 million in compensation over a weighted average period of 3.5 years.

Subsidiary Unit-Based Compensation Plans

Each of ETP and Sunoco LP has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards” to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a five-year period, and vesting The Subsidiary Unit Awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding.

The following table summarizes the activity of the Subsidiary Unit Awards:

	ETP				Sunoco LP
	Number of Units		Weighted  Average Grant-Date Fair Value Per Unit		Number of Units		Weighted  Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 2016	9.4		$	27.68	2.0		$	34.43
Legacy Sunoco Logistics unvested awards as of December 31, 2016	3.2		28.57		—		—
Awards granted	4.9		17.69		0.2		28.31
Awards vested	(2.3	)	34.22		(0.3	)	45.48
Awards forfeited	(1.1	)	25.03		(0.2	)	34.71
Unvested awards as of December 31, 2017	14.1		23.18		1.7		31.89

Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31:
2017	$	17.69	$	28.31
2016	23.82		26.95
2015	23.47		40.63

The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2017, 2016, and 2015 was $40 million, $40 million, and $57 million, respectively, based on the market price of the respective subsidiaries’ common units as of the vesting date. As of December 31, 2017, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $216 million, and the weighted average period over which this cost is expected to be recognized in expense is 2.8 years.

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10. INCOME TAXES:

As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:

	Years Ended December 31,
	2017			2016			2015
Current expense (benefit):
Federal	$	54		$	(47	)	$	(308	)
State	(16		)	(34		)	(54		)
Total	38			(81		)	(362		)
Deferred expense (benefit):
Federal	(2,055		)	(189		)	268
State	184			12			(29		)
Total	(1,871		)	(177		)	239
Total income tax expense (benefit) from continuing operations	$	(1,833	)	$	(258	)	$	(123	)

Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense (benefit) at the United States statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2017, 2016 and 2015 is as follows:

	2017			2016			2015
Income tax expense (benefit) at United States statutory rate of 35 percent	$	248		$	71		$	316
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(477		)	(576		)	(355		)
Goodwill impairment	207			278			—
State tax, net of federal tax benefit	124			(10		)	(29		)
Dividend received deduction	(14		)	(15		)	(22		)
Federal rate change	(1,812		)	—			—
Audit settlement	—			—			(7		)
Change in tax status of subsidiary	(124		)	—			—
Other	15			(6		)	(26		)
Income tax expense (benefit) from continuing operations	$	(1,833	)	$	(258	)	$	(123	)

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Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:

	December 31,
	2017			2016
Deferred income tax assets:
Net operating losses and alternative minimum tax credit	$	683		$	472
Pension and other postretirement benefits	21			30
Long-term debt	14			32
Other	191			182
Total deferred income tax assets	909			716
Valuation allowance	(189		)	(118		)
Net deferred income tax assets	720			598
Deferred income tax liabilities:
Property, plant and equipment	(1,036		)	(1,633		)
Investments in unconsolidated affiliates	(2,726		)	(3,789		)
Trademarks	(173		)	(273		)
Other	(100		)	(15		)
Total deferred income tax liabilities	(4,035		)	(5,710		)
Net deferred income taxes	$	(3,315	)	$	(5,112	)

The table below provides a rollforward of the net deferred income tax liability as follows:

	December 31,
	2017			2016
Net deferred income tax liability, beginning of year	$	(5,112	)	$	(4,590	)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)	—			(460		)
Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3)	—			(243		)
Tax provision, including provision from discontinued operations	1,825			201
Other	(28		)	(20		)
Net deferred income tax liability	$	(3,315	)	$	(5,112	)

ETP Holdco and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $403 million, all of which will expire in 2031 through 2037. Our corporate subsidiaries have $62 million of federal alternative minimum tax credits at December 31, 2017, of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have net operating loss carryforward benefits of $274 million, $217 million net of federal tax, which expire between January 1, 2018 and 2037. A valuation allowance of $186 million is applicable to the state net operating loss carryforward benefits applicable to significant restriction on their use in the Commonwealth of Pennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit.

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The following table sets forth the changes in unrecognized tax benefits:

	Years Ended December 31,
	2017			2016			2015
Balance at beginning of year	$	615		$	610		$	440
Additions attributable to tax positions taken in the current year	—			8			178
Additions attributable to tax positions taken in prior years	28			18			—
Reduction attributable to tax positions taken in prior years	(25		)	(20		)	—
Lapse of statute	(9		)	(1		)	(8		)
Balance at end of year	$	609		$	615		$	610

As of December 31, 2017, we have $605 million ($576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.

Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $9 million, net of tax.

Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in its litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the consolidated balance sheet as of December 31, 2017.

In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety.  In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact.  Nextel has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court.  Sunoco, Inc. has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter.  However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 million after federal income tax benefits) against the receivable.

In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007.

Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments.

ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

Income Tax Benefit.On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from35% to21%for taxable years beginning afterDecember 31, 2017. As a result, the Partnership recognized a deferred tax benefit of$1.81 billionin December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

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11. REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Contingent Residual Support Agreement – AmeriGas

In connection with the closing of the contribution of its propane operations in January 2012, ETP previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.

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 millionprincipal amount of6.375%senior notes due 2023 issued by Sunoco LP, (ii)$800 millionprincipal amount of6.25%senior notes due 2021 issued by Sunoco LP and (iii)$2.035 billionaggregate 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 billionaggregate principal amount of4.875%, senior notes due 2023;

• $800 millionaggregate principal amount of5.50%senior notes due 2026; and

• $400 millionaggregate principal amount of5.875%senior notes due 2028.

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

FERC Audit

In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.

Commitments

In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

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

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Years Ended December 31,
	2017			2016			2015
Rental expense(1)	$	196		$	187		$	281
Less: Sublease rental income	(25		)	(26		)	(26		)
Rental expense, net	$	171		$	161		$	255

⁽¹⁾  Includes contingent rentals totaling $16 million, $18 million and $20 million for the years ended December 31, 2017, 2016 and 2015, respectively.

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Future minimum lease commitments for such leases are:

Years Ending December 31:
2018	$	113
2019	100
2020	96
2021	83
2022	71
Thereafter	606
Future minimum lease commitments	1,069
Less: Sublease rental income	(152		)
Net future minimum lease commitments	$	917

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 consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways 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 is pending. Dakota Access intervened in the case. The SRST soon added a request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot.

After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.

The SRST appealed the denial of the preliminary injunction to the United States Court of Appeals for the D.C. Circuit and filed an emergency motion in the United States District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. 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 December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and TRO to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the Tribe. The District Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.

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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 rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any 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. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018.

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 auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. 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 is required to file the revised plan with the Court by April 1, 2018. 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 report was filed with the court on December 29, 2017.

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. Briefing on YST’s motion is ongoing.

While we believe that the pending lawsuits are unlikely to halt or suspend the operation of the pipeline, we cannot assure this outcome. We 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) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As ofDecember 31, 2017, Sunoco, Inc. is a defendant insevencases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Fourof these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is

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pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland.

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. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to 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, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, 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 (the “Regency Litigation 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 the Regency Litigation 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. The Regency Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC.

The Regency Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency 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. Enterprise’s response is due February 26, 2018.

Sunoco Logistics Merger Litigation

Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well

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as an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the Motion to Dismiss, the ETP Unitholder Plaintiffs chose to voluntarily dismiss their claims without prejudice in November 2017.

The ETP-SXL Defendants cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what the outcome of any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger.

Litigation Filed By or Against Williams

On April 6, 2016, Williams filed a complaint, The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG, against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.

On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions.

ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.

After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.

Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Defendants breached an additional representation and warranty in the Merger Agreement.

Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On

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September 29, 2016, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016.

On March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and Order on the June 2016 trial and denied Williams’ motion for reargument on April 5, 2017. As a result of the Delaware Supreme Court’s affirmance, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.

Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.

Unitholder Litigation Relating to the Issuance

In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware (the “Issuance Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016.

The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.

The Issuance Defendants and the Issuance Plaintiffs filed cross-motions for partial summary judgment. On February 28, 2017, the Court denied both motions for partial summary judgment. A trial in the Issuance Litigation is currently set for February 19-21, 2018.

The Issuance Defendants cannot predict the outcome of the Issuance Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendants predict the amount of time and expense that will be required to resolve the Issuance Litigation. The Issuance Defendants believe the Issuance Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Issuance.

Litigation filed by BP Products

On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately$62 million, a figure that BP reduced in subsequent filings to approximately$41 million.

SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.

On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s$13 millionalternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.

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On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.

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 December 31, 2017 and 2016, accruals of approximately $33 million and $77 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.

No amounts have been recorded in our December 31, 2017 or 2016 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 this year, 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, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief.In short, the DOJ and EPA proposed federal penalties totaling$7 million

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for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately$1 millionto resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.

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 ofDecember 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 43 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.

	December 31,
	2017		2016
Current	$	35	$	26
Non-current	337		318
Total environmental liabilities	$	372	$	344

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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 years ended December 31, 2017 and 2016, the Partnership recorded $32 million and $43 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, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an 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 and 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 its 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.

In January 2012, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. ETP also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of$100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas.  The proposed penalties are in excess of$100,000. The case went to hearing in November 2016 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows, or financial position.

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In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of$100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, Occupational Safety and Health 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.

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 operations and operational gas sales on our interstate transportation and storage operations. These contracts are not designated as hedges for accounting purposes.

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

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

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing operations. These contracts are not designated as hedges for accounting purposes.

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

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The following table details our outstanding commodity-related derivatives:

	December 31, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	1,078		2018	(683	)	2017
Basis Swaps IFERC/NYMEX (1)	48,510		2018-2020	2,243		2017
Options – Puts	13,000		2018	—		—
Power (Megawatt):
Forwards	435,960		2018-2019	391,880		2017 - 2018
Futures	(25,760	)	2018	109,564		2017 - 2018
Options — Puts	(153,600	)	2018	(50,400	)	2017
Options — Calls	137,600		2018	186,400		2017
Crude (MBbls) – Futures	—		—	(617	)	2017
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	4,650		2018-2020	10,750		2017 - 2018
Swing Swaps IFERC	87,253		2018-2019	(5,663	)	2017
Fixed Swaps/Futures	(4,390	)	2018-2019	(52,653	)	2017 - 2019
Forward Physical Contracts	(145,105	)	2018-2020	(22,492	)	2017
Natural Gas Liquid (MBbls) – Forwards/Swaps	6,744		2018-2019	(5,787	)	2017
Refined Products (MBbls) – Futures	(3,901	)	2018-2019	(3,144	)	2017
Corn (Bushels) – Futures	1,870,000		2018	1,580,000		2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(39,770	)	2018	(36,370	)	2017
Fixed Swaps/Futures	(39,770	)	2018	(36,370	)	2017
Hedged Item — Inventory	39,770		2018	36,370		2017

⁽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 are designated as hedges for accounting purposes:

			Notional Amount Outstanding
Entity	Term	Type(1)	December 31, 2017		December 31, 2016
ETP	July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
ETP	July 2018(2)	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
ETP	July 2019(2)	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
ETP	July 2020(2)	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
ETP	December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
ETP	March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300

⁽¹⁾  Floating rates are based on 3-month LIBOR.

⁽²⁾  Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern 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
	December 31, 2017		December 31, 2016		December 31, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	14	$	—	$	(2	)	$	(4	)
	14		—		(2		)	(4		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	262		338		(281		)	(416		)
Commodity derivatives	45		25		(58		)	(58		)
Interest rate derivatives	—		—		(219		)	(193		)
Embedded derivatives in ETP Convertible Preferred Units	—		—		—			(1		)
	307		363		(558		)	(668		)
Total derivatives	$	321	$	363	$	(560	)	$	(672	)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	December 31, 2017			December 31, 2016			December 31, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(219	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	45			25			(58		)	(58		)
Broker cleared derivative contracts	Other current assets (liabilities)	276			338			(283		)	(420		)
		321			363			(560		)	(672		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(21		)	(4		)	21			4
Counterparty netting	Other current assets (liabilities)	(263		)	(338		)	263			338
Total net derivatives		$	37		$	21		$	(276	)	$	(330	)

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 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
		Years Ended December 31,
		2017		2016		2015
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	26	$	14	$	21
Total		$	26	$	14	$	21

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2017			2016			2015
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	31		$	(35	)	$	(11	)
Commodity derivatives – Non-trading	Cost of products sold	5			(177		)	15
Interest rate derivatives	Losses on interest rate derivatives	(37		)	(12		)	(18		)
Embedded derivatives	Other, net	1			4			12
Total		$	—		$	(220	)	$	(2	)

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13. RETIREMENT BENEFITS:

Savings and Profit Sharing Plans

We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETP, Sunoco LP and Lake Charles LNG. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries have made matching contributions of $38 million, $44 million and $40 million to the 401(k) savings plan for the years ended December 31, 2017, 2016, and 2015, respectively.

Pension and Other Postretirement Benefit Plans

Panhandle

Postretirement benefits expense for the years ended December 31, 2017, 2016, and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.

Sunoco, Inc.

Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.

Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.

Obligations and Funded Status

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.

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The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:

	December 31, 2017									December 31, 2016
	Pension Benefits									Pension Benefits
	Funded Plans			Unfunded Plans			Other Postretirement Benefits			Funded Plans			Unfunded Plans			Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$	18		$	51		$	166		$	20		$	57		$	181
Interest cost	1			1			4			1			2			4
Amendments	—			—			7			—			—			—
Benefits paid, net	(2		)	(6		)	(20		)	(1		)	(7		)	(21		)
Actuarial (gain) loss and other	2			1			(1		)	(2		)	(1		)	2
Settlements	(18		)	—			—			—			—			—
Benefit obligation at end of period	$	1		$	47		$	156		$	18		$	51		$	166
Change in plan assets:
Fair value of plan assets at beginning of period	$	12		$	—		$	256		$	15		$	—		$	261
Return on plan assets and other	3			—			11			(2		)	—			6
Employer contributions	6			—			10			—			—			10
Benefits paid, net	(2		)	—			(20		)	(1		)	—			(21		)
Settlements	(18		)	—			—			—			—			—
Fair value of plan assets at end of period	$	1		$	—		$	257		$	12		$	—		$	256
Amount underfunded (overfunded) at end of period	$	—		$	47		$	(101	)	$	6		$	51		$	(90	)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$	—		$	—		$	127		$	—		$	—		$	114
Current liabilities	—			(8		)	(2		)	—			(7		)	(2		)
Non-current liabilities	—			(39		)	(24		)	(6		)	(44		)	(23		)
	$	—		$	(47	)	$	101		$	(6	)	$	(51	)	$	89
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Net actuarial gain	$	—		$	5		$	(18	)	$	—		$	—		$	(13	)
Prior service cost	—			—			21			—			—			15
	$	—		$	5		$	3		$	—		$	—		$	2

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The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:

	December 31, 2017						December 31, 2016
	Pension Benefits						Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits		Funded Plans		Unfunded Plans		Other Postretirement Benefits
Projected benefit obligation	$	1	$	47	N/A		$	18	$	51	N/A
Accumulated benefit obligation	1		47		$	156	18		51		$	166
Fair value of plan assets	1		—		257		12		—		256

Components of Net Periodic Benefit Cost

	December 31, 2017					December 31, 2016
	Pension Benefits		Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Interest cost	$	2	$	4		$	3		$	4
Expected return on plan assets	—		(9		)	(1		)	(8		)
Prior service cost amortization	—		2			—			1
Net periodic benefit cost	$	2	$	(3	)	$	2		$	(3	)

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:

	December 31, 2017				December 31, 2016
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	3.27	%	2.34	%	3.65	%	2.34	%
Rate of compensation increase	N/A		N/A		N/A		N/A

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:

	December 31, 2017				December 31, 2016
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	3.52	%	3.10	%	3.60	%	3.06	%
Expected return on assets:
Tax exempt accounts	3.50	%	7.00	%	3.50	%	7.00	%
Taxable accounts	N/A		4.50	%	N/A		4.50	%
Rate of compensation increase	N/A		N/A		N/A		N/A

The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest

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rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.

The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:

	December 31,
	2017		2016
Health care cost trend rate	7.20	%	6.73	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.99	%	4.96	%
Year that the rate reaches the ultimate trend rate	2023		2021

Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.

Plan Assets

For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%. 

The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.

The fair value of the pension plan assets by asset category at the dates indicated is as follows:

			Fair Value Measurements at December 31, 2017
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Mutual funds (1)	$	1	$	1	$	—	$	—
Total	$	1	$	1	$	—	$	—

⁽¹⁾ Comprised of 100% equities as of December 31, 2017.

			Fair Value Measurements at December 31, 2016
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Mutual funds (1)	$	12	$	12	$	—	$	—
Total	$	12	$	12	$	—	$	—

⁽¹⁾  Comprised of 100% equities as of December 31, 2016.

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The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:

			Fair Value Measurements at December 31, 2017
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	33	$	33	$	—	$	—
Mutual funds (1)	154		154		—		—
Fixed income securities	70		—		70		—
Total	$	257	$	187	$	70	$	—

⁽¹⁾ Primarily comprised of approximately 38% equities, 61% fixed income securities and 2% cash as of December 31, 2017.

			Fair Value Measurements at December 31, 2016
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	23	$	23	$	—	$	—
Mutual funds (1)	142		142		—		—
Fixed income securities	91		—		91		—
Total	$	256	$	165	$	91	$	—

⁽¹⁾  Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016.

The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  

Contributions

We expect to contribute $8 million to pension plans and $10 million to other postretirement plans in 2018.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments

Panhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:

Years	Pension Benefits - Unfunded Plans (1)		Other Postretirement Benefits (Gross, Before Medicare Part D)
2018	$	8	$	24
2019	6		23
2020	6		21
2021	5		19
2022	4		17
2023 – 2027	15		37

⁽¹⁾     Expected benefit payments of funded pension plans are less than $1 million for the next ten years.

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

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14. RELATED PARTY TRANSACTIONS:

In June 2017, ETP acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8.

ETE previously paid ETP to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016.

In addition, subsidiaries of ETE recorded sales with affiliates of $303 million, $221 million and $290 million during the years ended December 31, 2017, 2016 and 2015, respectively.

15. REPORTABLE SEGMENTS:

Subsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the following:

• activities of the Parent Company; and

• the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.

The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.

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 (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.

Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

F - 78

Eliminations in the tables below include the following:

• MACS, Sunoco LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP, as discussed above.

	Years Ended December 31,
	2017			2016			2015
Revenues:
Investment in ETP:
Revenues from external customers	$	28,613		$	21,618		$	34,156
Intersegment revenues	441			209			136
	29,054			21,827			34,292
Investment in Sunoco LP:
Revenues from external customers	11,713			9,977			12,419
Intersegment revenues	10			9			11
	11,723			9,986			12,430
Investment in Lake Charles LNG:
Revenues from external customers	197			197			216
Adjustments and Eliminations:	(451		)	(218		)	(10,842		)
Total revenues	$	40,523		$	31,792		$	36,096
Costs of products sold:
Investment in ETP	$	20,801		$	15,080		$	26,714
Investment in Sunoco LP	10,615			8,830			11,450
Adjustments and Eliminations	(450		)	(217		)	(9,496		)
Total costs of products sold	$	30,966		$	23,693		$	28,668
Depreciation, depletion and amortization:
Investment in ETP	$	2,332		$	1,986		$	1,929
Investment in Sunoco LP	169			176			150
Investment in Lake Charles LNG	39			39			39
Corporate and Other	14			15			17
Adjustments and Eliminations	—			—			(184		)
Total depreciation, depletion and amortization	$	2,554		$	2,216		$	1,951

	Years Ended December 31,
	2017			2016		2015
Equity in earnings of unconsolidated affiliates:
Investment in ETP	$	156		$	59	$	469
Adjustments and Eliminations	(12		)	211		(193		)
Total equity in earnings of unconsolidated affiliates	$	144		$	270	$	276

F - 79

	Years Ended December 31,
	2017			2016			2015
Segment Adjusted EBITDA:
Investment in ETP	$	6,712		$	5,733		$	5,517
Investment in Sunoco LP	732			665			719
Investment in Lake Charles LNG	175			179			196
Corporate and Other	(31		)	(170		)	(104		)
Adjustments and Eliminations	(268		)	(272		)	(590		)
Total Segment Adjusted EBITDA	7,320			6,135			5,738
Depreciation, depletion and amortization	(2,554		)	(2,216		)	(1,951		)
Interest expense, net of interest capitalized	(1,922		)	(1,804		)	(1,622		)
Gains on acquisitions	—			83			—
Impairment of investments in unconsolidated affiliates	(313		)	(308		)	—
Impairment losses	(1,039		)	(1,040		)	(339		)
Losses on interest rate derivatives	(37		)	(12		)	(18		)
Non-cash unit-based compensation expense	(99		)	(70		)	(91		)
Unrealized gains (losses) on commodity risk management activities	59			(136		)	(65		)
Losses on extinguishments of debt	(89		)	—			(43		)
Inventory valuation adjustments	24			97			(67		)
Adjusted EBITDA related to discontinued operations	(223		)	(199		)	(228		)
Adjusted EBITDA related to unconsolidated affiliates	(716		)	(675		)	(713		)
Equity in earnings of unconsolidated affiliates	144			270			276
Other, net	155			79			23
Income from continuing operations before income tax benefit	$	710		$	204		$	900
Income tax benefit from continuing operations	(1,833		)	(258		)	(123		)
Income from continuing operations	2,543			462			1,023
Income (loss) from discontinued operations, net of tax	(177		)	(462		)	38
Net income	$	2,366		$	—		$	1,061

	December 31,
	2017			2016			2015
Total assets:
Investment in ETP	$	77,965		$	70,105		$	65,128
Investment in Sunoco LP	8,344			8,701			8,842
Investment in Lake Charles LNG	1,646			1,508			1,369
Corporate and Other	598			711			638
Adjustments and Eliminations	(2,307		)	(2,100		)	(4,833		)
Total	$	86,246		$	78,925		$	71,144

F - 80

	Years Ended December 31,
	2017		2016		2015
Additions to property, plant and equipment, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):
Investment in ETP	$	5,901	$	5,810	$	8,167
Investment in Sunoco LP	103		119		178
Investment in Lake Charles LNG	2		—		1
Adjustments and Eliminations	—		—		(123		)
Total	$	6,006	$	5,929	$	8,223

	December 31,
	2017			2016			2015
Advances to and investments in affiliates:
Investment in ETP	$	3,816		$	4,280		$	5,003
Adjustments and Eliminations	(1,111		)	(1,240		)	(1,541		)
Total	$	2,705		$	3,040		$	3,462

The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP.

Investment in ETP

	Years Ended December 31,
	2017		2016		2015
Intrastate Transportation and Storage	$	2,891	$	2,155	$	1,912
Interstate Transportation and Storage	915		946		1,008
Midstream	2,510		2,342		2,607
NGL and refined products transportation and services	8,326		5,973		4,569
Crude oil transportation and services	11,672		7,539		8,980
All Other	2,740		2,872		15,216
Total revenues	29,054		21,827		34,292
Less: Intersegment revenues	441		209		136
Revenues from external customers	$	28,613	$	21,618	$	34,156

Investment in Sunoco LP

	Years Ended December 31,
	2017		2016		2015
Retail operations	$	2,263	$	1,991	$	2,226
Wholesale operations	9,460		7,995		10,204
Total revenues	11,723		9,986		12,430
Less: Intersegment revenues	10		9		11
Revenues from external customers	$	11,713	$	9,977	$	12,419

Investment in Lake Charles LNG

Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 2015, respectively, were related to LNG terminalling.

F - 81

16. QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year.

	Quarters Ended
	March 31*		June 30*		September 30*		December 31		Total Year
2017:
Revenues	$	9,660	$	9,427	$	9,984	$	11,452	$	40,523
Operating income (loss)	758		746		924		285		2,713
Net income (loss)	319		121		758		1,168		2,366
Limited Partners’ interest in net income	232		204		240		239		915
Basic net income per limited partner unit	$	0.22	$	0.18	$	0.22	$	0.22	$	0.85
Diluted net income per limited partner unit	$	0.21	$	0.18	$	0.22	$	0.22	$	0.83

	Quarters Ended
	March 31*		June 30*		September 30*			December 31*			Total Year*
2016:
Revenues	$	6,447	$	7,866	$	8,156		$	9,323		$	31,792
Operating income	680		814		624			(275		)	1,843
Net income (loss)	320		417		(3		)	(734		)	—
Limited Partners’ interest in net income	311		239		207			226			983
Basic net income per limited partner unit	$	0.30	$	0.23	$	0.20		$	0.22		$	0.94
Diluted net income per limited partner unit	$	0.30	$	0.23	$	0.19		$	0.21		$	0.92

* As adjusted. See Note 2 and Note 3. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.

The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $1.04 billion, respectively. Impairment losses in 2017 were primarily related to ETP’s interstate transportation and storage operations, NGL and refined products operations and other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its interstate transportation and storage operations.

F - 82

17. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

BALANCE SHEETS

	December 31,
	2017			2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1		$	2
Accounts receivable from related companies	65			55
Other current assets	1			—
Total current assets	67			57
PROPERTY, PLANT AND EQUIPMENT, net	27			36
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	6,082			5,088
INTANGIBLE ASSETS, net	—			1
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	8			10
Total assets	$	6,193		$	5,201
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	—		$	1
Accounts payable to related companies	—			22
Interest payable	66			66
Accrued and other current liabilities	4			3
Total current liabilities	70			92
LONG-TERM DEBT, less current maturities	6,700			6,358
NOTE PAYABLE TO AFFILIATE	617			443
OTHER NON-CURRENT LIABILITIES	2			2
COMMITMENTS AND CONTINGENCIES
PARTNERS’ DEFICIT:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)	(1,643		)	(1,871		)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)	450			180
Total partners’ deficit	(1,196		)	(1,694		)
Total liabilities and partners’ deficit	$	6,193		$	5,201

F - 83

STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2017			2016			2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(31	)	$	(185	)	$	(112	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(347		)	(327		)	(294		)
Equity in earnings of unconsolidated affiliates	1,381			1,511			1,601
Loss on extinguishment of debt	(47		)	—			—
Other, net	(2		)	(4		)	(5		)
INCOME BEFORE INCOME TAXES	954			995			1,190
Income tax expense	—			—			1
NET INCOME	954			995			1,189
General Partner’s interest in net income	2			3			3
Convertible Unitholders’ interest in income	37			9			—
Class D Unitholder’s interest in net income	—			—			3
Limited Partners’ interest in net income	$	915		$	983		$	1,183

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STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2017			2016			2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	831		$	918		$	1,103
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Bakken Pipeline Transaction	—			—			(817		)
Contributions to unconsolidated affiliates	(861		)	(70		)	—
Capital expenditures	(1		)	(16		)	(19		)
Contributions in aid of construction costs	7			—			—
Net cash used in investing activities	(855		)	(86		)	(836		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,219			225			3,672
Principal payments on debt	(1,881		)	(210		)	(1,985		)
Distributions to partners	(1,010		)	(1,022		)	(1,090		)
Proceeds from affiliate	174			176			210
Common Units issued for cash	568			—			—
Units repurchased under buyback program	—			—			(1,064		)
Debt issuance costs	(47		)	—			(11		)
Net cash provided by (used in) financing activities	23			(831		)	(268		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(1		)	1			(1		)
CASH AND CASH EQUIVALENTS, beginning of period	2			1			2
CASH AND CASH EQUIVALENTS, end of period	$	1		$	2		$	1

F - 85

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

OF CERTAIN SUBSIDIARIES INCLUDED PURSUANT

TO RULE 3-16 OF REGULATION S-X

	Page
1. Energy Transfer Partners, L.P. Financial Statements	S - 2

S - 1

1. ENERGY TRANSFER PARTNERS, L.P. FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	S - 3
Consolidated Balance Sheets – December 31, 2017 and 2016	S - 4
Consolidated Statements of Operations – Years Ended December 31, 2017, 2016 and 2015	S - 6
Consolidated Statements of Comprehensive Income – Years Ended December 31, 2017, 2016 and 2015	S - 7
Consolidated Statements of Equity – Years Ended December 31, 2017, 2016 and 2015	S - 8
Consolidated Statements of Cash Flows – Years Ended December 31, 2017, 2016 and 2015	S - 10
Notes to Consolidated Financial Statements	S - 12

S - 2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of Energy Transfer Partners, L.L.C. and

Unitholders of Energy Transfer Partners, L.P.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Energy Transfer Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 2018(not separately included herein) expressed an unqualified opinion thereon.

Change in accounting principle

As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2004.

Dallas, Texas

February 23, 2018

S - 3

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	December 31,
	2017			2016*
ASSETS
Current assets:
Cash and cash equivalents	$	306		$	360
Accounts receivable, net	3,946			3,002
Accounts receivable from related companies	318			209
Inventories	1,589			1,626
Income taxes receivable	135			128
Derivative assets	24			20
Other current assets	210			298
Total current assets	6,528			5,643
Property, plant and equipment	67,699			58,220
Accumulated depreciation and depletion	(9,262		)	(7,303		)
	58,437			50,917
Advances to and investments in unconsolidated affiliates	3,816			4,280
Other non-current assets, net	758			672
Intangible assets, net	5,311			4,696
Goodwill	3,115			3,897
Total assets	$	77,965		$	70,105

* As adjusted. See Note 2.

S - 4

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	December 31,
	2017		2016*
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	4,126	$	2,900
Accounts payable to related companies	209		43
Derivative liabilities	109		166
Accrued and other current liabilities	2,143		1,905
Current maturities of long-term debt	407		1,189
Total current liabilities	6,994		6,203
Long-term debt, less current maturities	32,687		31,741
Long-term notes payable – related company	—		250
Non-current derivative liabilities	145		76
Deferred income taxes	2,883		4,394
Other non-current liabilities	1,084		952
Commitments and contingencies
Legacy ETP Preferred Units	—		33
Redeemable noncontrolling interests	21		15
Equity:
Series A Preferred Units (950,000 units authorized, issued and outstanding as of December 31, 2017)	944		—
Series B Preferred Units (550,000 units authorized, issued and outstanding as of December 31, 2017)	547		—
Limited Partners:
Common Unitholders (1,164,112,575 and 794,803,854 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)	26,531		14,925
Class E Unitholder (8,853,832 units authorized, issued and outstanding – held by subsidiary)	—		—
Class G Unitholder (90,706,000 units authorized, issued and outstanding – held by subsidiary)	—		—
Class H Unitholder (81,001,069 units authorized, issued and outstanding as of December 31, 2016)	—		3,480
Class I Unitholder (100 units authorized, issued and outstanding)	—		2
Class K Unitholders (101,525,429 units authorized, issued and outstanding – held by subsidiaries)	—		—
General Partner	244		206
Accumulated other comprehensive income	3		8
Total partners’ capital	28,269		18,621
Noncontrolling interest	5,882		7,820
Total equity	34,151		26,441
Total liabilities and equity	$	77,965	$	70,105

* As adjusted. See Note 2.

S - 5

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

	Years Ended December 31,
	2017			2016*			2015*
REVENUES:
Natural gas sales	$	4,172		$	3,619		$	3,671
NGL sales	6,972			4,841			3,936
Crude sales	10,184			6,766			8,378
Gathering, transportation and other fees	4,265			4,003			3,997
Refined product sales (see Note 3)	1,515			1,047			9,958
Other (see Note 3)	1,946			1,551			4,352
Total revenues	29,054			21,827			34,292
COSTS AND EXPENSES:
Cost of products sold (see Note 3)	20,801			15,080			26,714
Operating expenses (see Note 3)	2,170			1,839			2,608
Depreciation, depletion and amortization	2,332			1,986			1,929
Selling, general and administrative (see Note 3)	434			348			475
Impairment losses	920			813			339
Total costs and expenses	26,657			20,066			32,065
OPERATING INCOME	2,397			1,761			2,227
OTHER INCOME (EXPENSE):
Interest expense, net	(1,365		)	(1,317		)	(1,291		)
Equity in earnings from unconsolidated affiliates	156			59			469
Impairment of investments in unconsolidated affiliates	(313		)	(308		)	—
Gains on acquisitions	—			83			—
Losses on extinguishments of debt	(42		)	—			(43		)
Losses on interest rate derivatives	(37		)	(12		)	(18		)
Other, net	209			131			22
INCOME BEFORE INCOME TAX BENEFIT	1,005			397			1,366
Income tax benefit	(1,496		)	(186		)	(123		)
NET INCOME	2,501			583			1,489
Less: Net income attributable to noncontrolling interest	420			295			134
Less: Net loss attributable to predecessor	—			—			(34		)
NET INCOME ATTRIBUTABLE TO PARTNERS	2,081			288			1,389
General Partner’s interest in net income	990			948			1,064
Preferred Unitholders’ interest in net income	12			—			—
Class H Unitholder’s interest in net income	93			351			258
Class I Unitholder’s interest in net income	—			8			94
Common Unitholders’ interest in net income (loss)	$	986		$	(1,019	)	$	(27	)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$	0.94		$	(1.38	)	$	(0.07	)
Diluted	$	0.93		$	(1.38	)	$	(0.08	)

* As adjusted. See Note 2.

S - 6

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

	Years Ended December 31,
	2017			2016*			2015*
Net income	$	2,501		$	583		$	1,489
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	6			2			(3		)
Actuarial gain (loss) relating to pension and other postretirement benefits	(12		)	(1		)	65
Foreign currency translation adjustment	—			(1		)	(1		)
Change in other comprehensive income (loss) from unconsolidated affiliates	1			4			(1		)
	(5		)	4			60
Comprehensive income	2,496			587			1,549
Less: Comprehensive income attributable to noncontrolling interest	420			295			134
Less: Comprehensive loss attributable to predecessor	—			—			(34		)
Comprehensive income attributable to partners	$	2,076		$	292		$	1,449

* As adjusted. See Note 2.

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in millions)

					Limited Partners
	Series A Preferred Units		Series B Preferred Units		Common Unit holders			Class H Units			Class I Units			General Partner			Accumulated Other Comprehensive Income (Loss)			Non-controlling Interest			Predecessor Equity			Total
Balance, December 31, 2014*	$	—	$	—	$	10,427		$	1,512		$	—		$	184		$	(56	)	$	5,143		$	8,088		$	25,298
Distributions to partners	—		—		(1,863		)	(247		)	(80		)	(944		)	—			—			—			(3,134		)
Distributions to noncontrolling interest	—		—		—			—			—			—			—			(338		)	—			(338		)
Units issued for cash	—		—		1,428			—			—			—			—			—			—			1,428
Subsidiary units issued for cash	—		—		298			—			—			2			—			1,219			—			1,519
Capital contributions from noncontrolling interest	—		—		—			—			—			—			—			875			—			875
Bakken Pipeline Transaction	—		—		(999		)	1,946			—			—			—			72			—			1,019
Sunoco LP Exchange Transaction	—		—		(52		)	—			—			—			—			(940		)	—			(992		)
Susser Exchange Transaction	—		—		(68		)	—			—			—			—			—			—			(68		)
Acquisition and disposition of noncontrolling interest	—		—		(26		)	—			—			—			—			(39		)	—			(65		)
Predecessor distributions to partners	—		—		—			—			—			—			—			—			(202		)	(202		)
Predecessor units issued for cash	—		—		—			—			—			—			—			—			34			34
Regency Merger	—		—		7,890			—			—			—			—			—			(7,890		)	—
Other comprehensive income, net of tax	—		—		—			—			—			—			60			—			—			60
Other, net	—		—		23			—			—			—			—			36			4			63
Net income (loss)	—		—		(27		)	258			94			1,064			—			134			(34		)	1,489
Balance, December 31, 2015*	—		—		17,031			3,469			14			306			4			6,162			—			26,986
Distributions to partners	—		—		(2,134		)	(340		)	(20		)	(1,048		)	—			—			—			(3,542		)
Distributions to noncontrolling interest	—		—		—			—			—			—			—			(481		)	—			(481		)
Units issued for cash	—		—		1,098			—			—			—			—			—			—			1,098
Subsidiary units issued	—		—		37			—			—			—			—			1,351			—			1,388

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Capital contributions from noncontrolling interest	—		—		—			—			—			—			—			236			—		236
Sunoco, Inc. retail business to Sunoco LP transaction	—		—		(405		)	—			—			—			—			—			—		(405		)
PennTex Acquisition	—		—		307			—			—			—			—			236			—		543
Other comprehensive income, net of tax	—		—		—			—			—			—			4			—			—		4
Other, net	—		—		10			—			—			—			—			21			—		31
Net income (loss)	—		—		(1,019		)	351			8			948			—			295			—		583
Balance, December 31, 2016*	—		—		14,925			3,480			2			206			8			7,820			—		26,441
Distributions to partners	—		—		(2,419		)	(95		)	(2		)	(952		)	—			—			—		(3,468		)
Distributions to noncontrolling interest	—		—		—			—			—			—			—			(430		)	—		(430		)
Units issued for cash	937		542		2,283			—			—			—			—			—			—		3,762
Sunoco Logistics Merger	—		—		9,416			(3,478		)	—			—			—			(5,938		)	—		—
Capital contributions from noncontrolling interest	—		—		—			—			—			—			—			2,202			—		2,202
Sale of Bakken Pipeline interest	—		—		1,260			—			—			—			—			740			—		2,000
Sale of Rover Pipeline interest	—		—		93			—			—			—			—			1,385			—		1,478
Acquisition of PennTex noncontrolling interest	—		—		(48		)	—			—			—			—			(232		)	—		(280		)
Other comprehensive loss, net of tax	—		—		—			—			—			—			(5		)	—			—		(5		)
Other, net	—		—		35			—			—			—			—			(85		)	—		(50		)
Net income	7		5		986			93			—			990			—			420			—		2,501
Balance, December 31, 2017	$	944	$	547	$	26,531		$	—		$	—		$	244		$	3		$	5,882		$	—	$	34,151

* As adjusted. See Note 2.

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

	Years Ended December 31,
	2017			2016*			2015*
OPERATING ACTIVITIES:
Net income	$	2,501		$	583		$	1,489
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	2,332			1,986			1,929
Deferred income taxes	(1,531		)	(169		)	202
Amortization included in interest expense	2			(20		)	(36		)
Inventory valuation adjustments	—			—			(58		)
Unit-based compensation expense	74			80			79
Impairment losses	920			813			339
Gains on acquisitions	—			(83		)	—
Losses on extinguishments of debt	42			—			43
Impairment of investments in unconsolidated affiliates	313			308			—
Distributions on unvested awards	(31		)	(25		)	(16		)
Equity in earnings of unconsolidated affiliates	(156		)	(59		)	(469		)
Distributions from unconsolidated affiliates	440			406			440
Other non-cash	(261		)	(271		)	(22		)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	(160		)	(246		)	(1,173		)
Net cash provided by operating activities	4,485			3,303			2,747
INVESTING ACTIVITIES:
Cash proceeds from sale of Bakken Pipeline interest	2,000			—			—
Cash proceeds from sale of Rover Pipeline interest	1,478			—			—
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction	—			2,200			—
Proceeds from Bakken Pipeline Transaction	—			—			980
Proceeds from Susser Exchange Transaction	—			—			967
Proceeds from sale of noncontrolling interest	—			—			64
Cash paid for acquisition of PennTex noncontrolling interest	(280		)	—			—
Cash paid for Vitol Acquisition, net of cash received	—			(769		)	—
Cash paid for PennTex Acquisition, net of cash received	—			(299		)	—
Cash transferred to ETE in connection with the Sunoco LP Exchange	—			—			(114		)
Cash paid for acquisition of a noncontrolling interest	—			—			(129		)
Cash paid for all other acquisitions	(264		)	(159		)	(675		)
Capital expenditures, excluding allowance for equity funds used during construction	(8,335		)	(7,550		)	(9,098		)
Contributions in aid of construction costs	24			71			80
Contributions to unconsolidated affiliates	(268		)	(59		)	(45		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	136			135			124
Proceeds from the sale of assets	35			25			23
Change in restricted cash	—			14			19
Other	1			1			(16		)
Net cash used in investing activities	(5,473		)	(6,390		)	(7,820		)

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FINANCING ACTIVITIES:
Proceeds from borrowings	26,736			19,916			22,462
Repayments of long-term debt	(26,494		)	(15,799		)	(17,843		)
Cash (paid to) received from affiliate notes	(255		)	124			233
Common Units issued for cash	2,283			1,098			1,428
Preferred Units issued for cash	1,479			—			—
Subsidiary units issued for cash	—			1,388			1,519
Predecessor units issued for cash	—			—			34
Capital contributions from noncontrolling interest	1,214			236			841
Distributions to partners	(3,468		)	(3,542		)	(3,134		)
Predecessor distributions to partners	—			—			(202		)
Distributions to noncontrolling interest	(430		)	(481		)	(338		)
Redemption of Legacy ETP Preferred Units	(53		)	—			—
Debt issuance costs	(83		)	(22		)	(63		)
Other	5			2			—
Net cash provided by financing activities	934			2,920			4,937
Decrease in cash and cash equivalents	(54		)	(167		)	(136		)
Cash and cash equivalents, beginning of period	360			527			663
Cash and cash equivalents, end of period	$	306		$	360		$	527

* As adjusted. See Note 2.

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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)

1. OPERATIONS AND BASIS OF PRESENTATION:

Organization. The consolidated financial statements presented herein contain the results of Energy Transfer Partners, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETP”). The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner.

In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled.

In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of maintaining clarity, the following references are used herein:

• References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger;

• References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and

• References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.

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 Sunoco Logistics Merger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements.

The historical common units and net income (loss) 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.

The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales.

The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia.

The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.

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The Partnership owns a controlling interest in 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.

Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the date the financial statements were issued.

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.

The Partnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, these undivided interests are consolidated proportionately.

2. ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Change in Accounting Policy

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:

	Year Ended December 31, 2016									Year Ended December 31, 2015
	As Originally Reported*			Effect of Change			As Adjusted			As Originally Reported*			Effect of Change			As Adjusted
Consolidated Statement of Operations and Comprehensive Income:
Cost of products sold	$	15,039		$	41		$	15,080		$	26,682		$	32		$	26,714
Operating income	1,802			(41		)	1,761			2,259			(32		)	2,227
Income before income tax benefit	438			(41		)	397			1,398			(32		)	1,366
Net income	624			(41		)	583			1,521			(32		)	1,489
Net income attributable to partners	297			(9		)	288			1,398			(9		)	1,389
Net loss per common unit - basic	(1.37		)	(0.01		)	(1.38		)	(0.06		)	(0.01		)	(0.07		)
Net loss per common unit - diluted	(1.37		)	(0.01		)	(1.38		)	(0.07		)	(0.01		)	(0.08		)
Comprehensive income	628			(41		)	587			1,581			(32		)	1,549
Comprehensive income attributable to partners	301			(9		)	292			1,458			(9		)	1,449
Consolidated Statements of Cash Flows:
Net income	624			(41		)	583			1,521			(32		)	1,489
Net change in operating assets and liabilities (change in inventories)	(117		)	(129		)	(246		)	(1,367		)	194			(1,173		)
Consolidated Balance Sheets (at period end):
Inventories	1,712			(86		)	1,626			1,213			(45		)	1,168
Total partners' capital	18,642			(21		)	18,621			20,836			(12		)	20,824

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

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Recent Accounting Pronouncements

ASU 2014-09

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.

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The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.

For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of our midstream segment agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.

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. The Partnership expects to adopt ASU 2016-02 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 2016-16

On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.

ASU 2017-04

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

ASU 2017-12

In August 2017, the FASB issued ASU 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.

Revenue Recognition

Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.

Our intrastate transportation and storage and interstate transportation and storage segments’ results 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. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the

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pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.

Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.

In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and segment margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.

We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we 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, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.

In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.

We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

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Regulatory Accounting – Regulatory Assets and Liabilities

Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

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

	Years Ended December 31,
	2017			2016			2015
Accounts receivable	$	(950	)	$	(919	)	$	819
Accounts receivable from related companies	67			30			(243		)
Inventories	37			(497		)	(157		)
Other current assets	39			83			(178		)
Other non-current assets, net	(94		)	(78		)	188
Accounts payable	758			972			(1,215		)
Accounts payable to related companies	(3		)	29			(160		)
Accrued and other current liabilities	(47		)	39			(83		)
Other non-current liabilities	24			33			(219		)
Price risk management assets and liabilities, net	9			62			75
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(160	)	$	(246	)	$	(1,173	)

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Non-cash investing and financing activities and supplemental cash flow information are as follows:

	Years Ended December 31,
	2017		2016			2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,059	$	822		$	896
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP	—		194			—
Net gains from subsidiary common unit transactions	—		37			300
NON-CASH FINANCING ACTIVITIES:
Issuance of Common Units in connection with the PennTex Acquisition	$	—	$	307		$	—
Issuance of Common Units in connection with the Regency Merger	—		—			9,250
Issuance of Class H Units in connection with the Bakken Pipeline Transaction	—		—			1,946
Contribution of assets from noncontrolling interest	988		—			34
Redemption of Common Units in connection with the Bakken Pipeline Transaction	—		—			999
Redemption of Common Units in connection with the Sunoco LP Exchange	—		—			52
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	1,329	$	1,411		$	1,467
Cash paid for (refund of) income taxes	50		(229		)	71

Accounts Receivable

Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty.

We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.

We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.

Inventories

As discussed under “Change in Accounting Policy” in Note 2, the Partnership changed its accounting policy for certain inventory in the fourth quarter of 2017.

Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

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Inventories consisted of the following:

	December 31,
	2017		2016
Natural gas, NGLs, and refined products	$	733	$	758
Crude oil	551		651
Spare parts and other	305		217
Total inventories	$	1,589	$	1,626

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

Other Current Assets

Other current assets consisted of the following:

	December 31,
	2017		2016
Deposits paid to vendors	$	64	$	74
Prepaid expenses and other	146		224
Total other current assets	$	210	$	298

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.

Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.

In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets.In 2016, the Partnership recorded a$133 millionfixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a$10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented.

Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

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Components and useful lives of property, plant and equipment were as follows:

	December 31,
	2017			2016
Land and improvements	$	1,706		$	676
Buildings and improvements (1 to 45 years)	1,960			1,617
Pipelines and equipment (5 to 83 years)	44,050			36,356
Natural gas and NGL storage facilities (5 to 46 years)	1,681			1,452
Bulk storage, equipment and facilities (2 to 83 years)	3,036			3,701
Vehicles (1 to 25 years)	124			217
Right of way (20 to 83 years)	3,424			3,349
Natural resources	434			434
Other (1 to 40 years)	534			484
Construction work-in-process	10,750			9,934
	67,699			58,220
Less – Accumulated depreciation and depletion	(9,262		)	(7,303		)
Property, plant and equipment, net	$	58,437		$	50,917

We recognized the following amounts for the periods presented:

	Years Ended December 31,
	2017		2016		2015
Depreciation and depletion expense	$	2,060	$	1,793	$	1,713
Capitalized interest	283		199		163

Advances to and Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.

Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:

	December 31,
	2017		2016
Regulatory assets	$	85	$	86
Deferred charges	210		217
Restricted funds	192		190
Long-term affiliated receivable	85		90
Other	186		89
Total other non-current assets, net	$	758	$	672

(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.

Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.

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Intangible Assets

Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.

Components and useful lives of intangible assets were as follows:

	December 31, 2017					December 31, 2016
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	6,250	$	(1,003	)	$	5,362	$	(737	)
Patents (10 years)	48		(26		)	48		(21		)
Trade Names (20 years)	66		(25		)	66		(22		)
Other (5 to 20 years)	1		—			2		(2		)
Total intangible assets	$	6,365	$	(1,054	)	$	5,478	$	(782	)

Aggregate amortization expense of intangible assets was as follows:

	Years Ended December 31,
	2017		2016		2015
Reported in depreciation, depletion and amortization	$	272	$	193	$	216

Estimated aggregate amortization expense for the next five years is as follows:

Years Ending December 31:
2018	$	280
2019	278
2020	278
2021	268
2022	256

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

In 2015, we recorded $24 million of intangible asset impairments related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows.

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

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Changes in the carrying amount of goodwill were as follows:

	Intrastate Transportation and Storage		Interstate Transportation and Storage			Midstream			NGL and Refined Products Transportation and Services			Crude Oil Transportation and Services		All Other			Total
Balance, December 31, 2015	$	10	$	912		$	718		$	772		$	912	$	2,104		$	5,428
Reduction due to contribution of legacy Sunoco, Inc. retail business	—		—			—			—			—		(1,289		)	(1,289		)
Acquired	—		—			177			—			251		—			428
Impaired	—		(638		)	(32		)	—			—		—			(670		)
Balance, December 31, 2016	10		274			863			772			1,163		815			3,897
Acquired	—		—			8			—			4		—			12
Impaired	—		(262		)	—			(79		)	—		(452		)	(793		)
Other	—		—			(1		)	—			—		—			(1		)
Balance, December 31, 2017	$	10	$	12		$	870		$	693		$	1,167	$	363		$	3,115

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.

During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of$262 millionin the interstate transportation and storage segment,$79 millionin the NGL and refined products transportation and services segment and$452 millionin the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.

During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve.

During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.

The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

Asset Retirement Obligations

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted

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risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.

Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as ofDecember 31, 2017and2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $165 million and $170 million, respectively.

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

Long-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	December 31,
	2017		2016
Interest payable	$	443	$	440
Customer advances and deposits	59		56
Accrued capital expenditures	1,006		749
Accrued wages and benefits	208		212
Taxes payable other than income taxes	108		63
Exchanges payable	154		208
Other	165		177
Total accrued and other current liabilities	$	2,143	$	1,905

Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

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Redeemable Noncontrolling Interests

The noncontrolling interest holders in one of our consolidated subsidiaries has the option to sell its interests to us.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on ETP’s consolidated balance sheet.

Environmental Remediation

We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2017 was $34.28 billion and $33.09 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $32.93 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, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2017, no transfers were made between any levels within the fair value hierarchy.

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2017 and 2016 based on inputs used to derive their fair values:

	Fair Value Total			Fair Value Measurements at December 31, 2017
				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	)

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	Fair Value Total			Fair Value Measurements at December 31, 2016
				Level 1			Level 2			Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	14		$	14		$	—		$	—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	96			96			—			—
Forward Physical Swaps	1			—			1			—
Power:
Forwards	4			—			4			—
Futures	1			1			—			—
Options – Calls	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	233			233			—			—
Refined Products – Futures	1			1			—			—
Crude – Futures	9			9			—			—
Total commodity derivatives	362			355			7			—
Other non-current assets	13			8			5			—
Total assets	$	375		$	363		$	12		$	—
Liabilities:
Interest rate derivatives	$	(193	)	$	—		$	(193	)	$	—
Embedded derivatives in the Legacy ETP Preferred Units	(1		)	—			—			(1		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(11		)	(11		)	—			—
Swing Swaps IFERC	(3		)	—			(3		)	—
Fixed Swaps/Futures	(149		)	(149		)	—			—
Power:
Forwards	(5		)	—			(5		)	—
Futures	(1		)	(1		)	—			—
Natural Gas Liquids – Forwards/Swaps	(273		)	(273		)	—			—
Refined Products – Futures	(17		)	(17		)	—			—
Crude – Futures	(13		)	(13		)	—			—
Total commodity derivatives	(472		)	(464		)	(8		)	—
Total liabilities	$	(666	)	$	(464	)	$	(201	)	$	(1	)

Contributions in Aid of Construction Costs

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.

Shipping and Handling Costs

Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

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Costs and Expenses

Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

We record the collection of taxes to be remitted to government authorities on a net basis except for our all other segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). For the year ended December 31, 2015, excise taxes collected by Sunoco LP were $1.85 billion. The Partnership deconsolidated Sunoco LP effective July 1, 2015 and no excise taxes were collected by our consolidated operations subsequent to that date.

Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.

Income Taxes

ETP is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).

As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, and 2015, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company and until July 31, 2015, Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

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At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.

Unit-Based Compensation

For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.

Pensions and Other Postretirement Benefit Plans

The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.  Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.

Allocation of Income

For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for United States Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our 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 our General Partner, the holder of the IDRs pursuant to our 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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3. ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

2018 Transactions

CDM Contribution Agreement

In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP 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)19,191,351common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately$335 million, (ii)6,397,965units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately$112 millionand (iii) an amount in cash equal to$1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions.

In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii)12,466,912USAC Common Units for cash consideration equal to$250 million.

2017 Transactions

Rover Contribution Agreement

In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a49.9%interest in the holding company that owns65%of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.

ETP and Sunoco Logistics Merger

As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the Sunoco Logistics Merger.

Permian Express Partners

In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal.Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including$547 millionof intangible assets and$435 millionof property, plant and equipment.

In July 2017, ETP contributed an approximate15%ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets.ExxonMobil’s contribution resulted in an increase of$988 millionin noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

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Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a100%membership interest, sold a49%interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for$2.00 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access and ETCO. The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

2016 Transactions

PennTex Acquisition

On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately$627 millionin ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, the Partnership purchased PennTex’s remaining outstanding common units in June 2017.

Summary of Assets Acquired and Liabilities Assumed

We accounted for the PennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.

The total purchase price was allocated as follows:

	At November 1, 2016
Total current assets	$	34
Property, plant and equipment	393
Goodwill(1)	177
Intangible assets	446
	1,050
Total current liabilities	6
Long-term debt, less current maturities	164
Other non-current liabilities	17
Noncontrolling interest	236
	423
Total consideration	627
Cash received	21
Total consideration, net of cash received	$	606

⁽¹⁾  None of the goodwill is expected to be deductible for tax purposes.

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

Sunoco Logistics’ Vitol Acquisition

In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for$760 millionplus working capital. The acquisition provides Sunoco Logistics with an approximately2 millionbarrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a50%interest in SunVit Pipeline LLC (“SunVit”), which increased Sunoco Logistics’ overall ownership of SunVit to100%. The$769 millionpurchase price, net of cash received, consisted primarily of net working capital of$13 millionlargely attributable to inventory and receivables; property, plant and equipment of$286 millionprimarily related to pipeline and terminalling assets; intangible assets of$313 millionattributable to customer relationships; and goodwill of$251 million.

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Bakken Financing

In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The$2.50 billioncredit facility provided substantially all of the remaining capital necessary to complete the projects. As ofDecember 31, 2017, $2.50 billionwas outstanding under this credit facility.

Bayou Bridge

In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a30%interest in the entity and Sunoco Logistics is the operator of the system.

Sunoco Retail to Sunoco LP

In March 2016, ETP contributed to Sunoco LP its remaining68.42%interest in Sunoco, LLC and100%interest in the legacy Sunoco, Inc. retail business for$2.23 billion. Sunoco LP paid$2.20 billionin cash, including a working capital adjustment and issued5.7 millionSunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016. In connection with this transaction, the Partnership deconsolidated the legacy Sunoco, Inc. retail business, including goodwill of$1.29 billionand intangible assets of$294 million. The results of Sunoco, LLC and the legacy Sunoco, Inc. retail business’ operations have not been presented as discontinued operations and Sunoco, Inc.’s retail business assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.

Following is a summary of amounts reflected for the prior periods in ETP’s consolidated statements of operations related to Sunoco, LLC and the legacy Sunoco, Inc. retail business, which operations are no longer consolidated:

	Year Ended December 31, 2015
Revenues	$	12,482
Cost of products sold	11,174
Operating expenses	798
Selling, general and administrative expenses	106

2015 Transactions

Sunoco LP

In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million in Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015.

In July 2015, in exchange for the contribution of 100%of Susser from ETP to Sunoco LP, Sunoco LP paid $970 millionin cash and issued to ETP subsidiaries22 millionSunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its79,308Sunoco LP common units for79,308Sunoco LP Class A units, (ii)10.9 millionSunoco LP subordinated units owned by Susser subsidiaries were converted into10.9 millionSunoco LP Class A units and (iii) Sunoco LP issued79,308Sunoco LP common units and 10.9 millionSunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries.

Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE (the “Sunoco LP Exchange”). In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE provided ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. In connection with this transaction, the Partnership deconsolidated Sunoco LP, including goodwill of $1.81 billion and intangible assets of $982 million related to Sunoco LP. At December 31, 2017, the Partnership held 37.8 million Sunoco LP common units accounted for under the equity method. Subsequent to Sunoco LP’s

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repurchase of a portion of its common units on February 7, 2018, as discussed in Note 4, our investment in Sunoco LP consists of 26.2 million units. The results of Sunoco LP’s operations have not been presented as discontinued operations and Sunoco LP’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.

Bakken Pipeline

In March 2015, ETE transferred 46.2 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, the Partnership also issued to ETE 100 Class I Units that provided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017.

In October 2015, Sunoco Logistics completed the acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access and ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction.

Regency Merger

On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency, with Regency surviving as a wholly-owned subsidiary of the Partnership (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 Partnership common units. ETP issued 258.3 million Partnership common units to Regency unitholders, including 23.3 million units issued to Partnership subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding Legacy ETP Preferred Units on a one-for-one basis.

In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.

The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger.

ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.

4. ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

Citrus

ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, an approximately 5,360-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment.

FEP

We have a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. The Partnership recorded an impairment of its investment

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in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor.

MEP

We own a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016.

HPC

We own a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. Our investment in HPC is reflected in the intrastate transportation and storage segment. The Partnership evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. During the year ended December 31, 2017, the Partnership recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.

Sunoco LP

Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from the Partnership. As a result, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. As of December 31, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units, and is reflected in the all other segment.

In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased17,286,859Sunoco 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.

The carrying values of the Partnership’s advances to and investments in unconsolidated affiliates as of December 31, 2017 and 2016 were as follows:

	December 31,
	2017		2016
Citrus	$	1,754	$	1,729
FEP	121		101
MEP	242		318
HPC	28		382
Sunoco LP	1,095		1,225
Others	576		525
Total	$	3,816	$	4,280

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The following table presents equity in earnings (losses) of unconsolidated affiliates:

	Years Ended December 31,
	2017			2016			2015
Citrus	$	144		$	102		$	97
FEP	53			51			55
MEP	38			40			45
HPC(1)	(168		)	31			32
Sunoco, LLC	—			—			(10		)
Sunoco LP(2)	12			(211		)	202
Other	77			46			48
Total equity in earnings of unconsolidated affiliates	156			59			469

⁽¹⁾  For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.

⁽²⁾  For the years ended December 31, 2017 and 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $176 million and $277 million, respectively.

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP, HPC and Sunoco LP (on a 100% basis) for all periods presented:

	December 31,
	2017		2016
Current assets	$	4,750	$	1,532
Property, plant and equipment, net	9,893		10,310
Other assets	2,286		5,980
Total assets	$	16,929	$	17,822
Current liabilities	$	2,075	$	1,918
Non-current liabilities	9,375		10,343
Equity	5,479		5,561
Total liabilities and equity	$	16,929	$	17,822

	Years Ended December 31,
	2017		2016			2015
Revenue	$	13,081	$	11,150		$	13,815
Operating income	636		859			1,052
Net income (loss)	294		(22		)	664

In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

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5. NET INCOME (LOSS) PER LIMITED PARTNER UNIT:

The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit.

The historical common units and net income (loss) 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.

	Years Ended December 31,
	2017			2016			2015
Net income	$	2,501		$	583		$	1,489
Less: Income attributable to noncontrolling interest	420			295			134
Less: Loss attributable to predecessor	—			—			(34		)
Net income, net of noncontrolling interest	2,081			288			1,389
General Partner’s interest in net income	990			948			1,064
Preferred Unitholders’ interest in net income	12			—			—
Class H Unitholder’s interest in net income	93			351			258
Class I Unitholder’s interest in net income	—			8			94
Common Unitholders’ interest in net income (loss)	986			(1,019		)	(27		)
Additional earnings allocated from (to) General Partner	9			(10		)	(5		)
Distributions on employee unit awards, net of allocation to General Partner	(27		)	(19		)	(16		)
Net income (loss) available to Common Unitholders	$	968		$	(1,048	)	$	(48	)
Weighted average Common Units – basic	1,032.7			758.2			649.2
Basic net income (loss) per Common Unit	$	0.94		$	(1.38	)	$	(0.07	)
Income (loss) available to Common Unitholders	$	968		$	(1,048	)	$	(48	)
Loss attributable to Legacy ETP Preferred Units	—			—			(6		)
Diluted income (loss) available to Common Unitholders	$	968		$	(1,048	)	$	(54	)
Weighted average Common Units – basic	1,032.7			758.2			649.2
Dilutive effect of unvested Unit Awards	5.1			—			—
Dilutive effect of Legacy ETP Preferred Units	—			—			1.0
Weighted average Common Units – diluted	1,037.8			758.2			650.2
Diluted income (loss) per Common Unit	$	0.93		$	(1.38	)	$	(0.08	)

6. DEBT OBLIGATIONS:

Our debt obligations consist of the following:

	December 31,
	2017		2016
ETP Debt
6.125% Senior Notes due February 15, 2017	$	—	$	400
2.50% Senior Notes due June 15, 2018 (1)	650		650
6.70% Senior Notes due July 1, 2018 (1)	600		600
9.70% Senior Notes due March 15, 2019	400		400
9.00% Senior Notes due April 15, 2019	450		450
5.50% Senior Notes due February 15, 2020	250		250
5.75% Senior Notes due September 1, 2020	400		400

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4.15% Senior Notes due October 1, 2020	1,050		1,050
4.40% Senior Notes due April 1, 2021	600		600
6.50% Senior Notes due July 15, 2021	—		500
4.65% Senior Notes due June 1, 2021	800		800
5.20% Senior Notes due February 1, 2022	1,000		1,000
4.65% Senior Notes due February 15, 2022	300		300
5.875% Senior Notes due March 1, 2022	900		900
5.00% Senior Notes due October 1, 2022	700		700
3.45% Senior Notes due January 15, 2023	350		350
3.60% Senior Notes due February 1, 2023	800		800
5.50% Senior Notes due April 15, 2023	—		700
4.50% Senior Notes due November 1, 2023	600		600
4.90% Senior Notes due February 1, 2024	350		350
7.60% Senior Notes due February 1, 2024	277		277
4.25% Senior Notes due April 1, 2024	500		500
9.00% Debentures due November 1, 2024	65		65
4.05% Senior Notes due March 15, 2025	1,000		1,000
5.95% Senior Notes due December 1, 2025	400		400
4.75% Senior Notes due January 15, 2026	1,000		1,000
3.90% Senior Notes due July 15, 2026	550		550
4.20% Senior Notes due April 15, 2027	600		—
4.00% Senior Notes due October 1, 2027	750		—
8.25% Senior Notes due November 15, 2029	267		267
4.90% Senior Notes due March 15, 2035	500		500
6.625% Senior Notes due October 15, 2036	400		400
7.50% Senior Notes due July 1, 2038	550		550
6.85% Senior Notes due February 15, 2040	250		250
6.05% Senior Notes due June 1, 2041	700		700
6.50% Senior Notes due February 1, 2042	1,000		1,000
6.10% Senior Notes due February 15, 2042	300		300
4.95% Senior Notes due January 15, 2043	350		350
5.15% Senior Notes due February 1, 2043	450		450
5.95% Senior Notes due October 1, 2043	450		450
5.30% Senior Notes due April 1, 2044	700		700
5.15% Senior Notes due March 15, 2045	1,000		1,000
5.35% Senior Notes due May 15, 2045	800		800
6.125% Senior Notes due December 15, 2045	1,000		1,000
5.30% Senior Notes due April 15, 2047	900		—
5.40% Senior Notes due October 1, 2047	1,500		—
Floating Rate Junior Subordinated Notes due November 1, 2066	546		546
ETP $4.0 billion Revolving Credit Facility due December 2022	2,292		—
ETP $1.0 billion 364-Day Credit Facility due November 2018 (2)	50		—
ETLP $3.75 billion Revolving Credit Facility due November 2019	—		2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020	—		1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017	—		630
Unamortized premiums, discounts and fair value adjustments, net	33		66
Deferred debt issuance costs	(170	)	(166	)
	29,210		29,454
Transwestern Debt
5.64% Senior Notes due May 24, 2017	—		82
5.36% Senior Notes due December 9, 2020	175		175
5.89% Senior Notes due May 24, 2022	150		150
5.66% Senior Notes due December 9, 2024	175		175
6.16% Senior Notes due May 24, 2037	75		75
Deferred debt issuance costs	(1	)	(1	)
	574		656
Panhandle Debt
6.20% Senior Notes due November 1, 2017	—		300

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7.00% Senior Notes due June 15, 2018	400			400
8.125% Senior Notes due June 1, 2019	150			150
7.60% Senior Notes due February 1, 2024	82			82
7.00% Senior Notes due July 15, 2029	66			66
8.25% Senior Notes due November 15, 2029	33			33
Floating Rate Junior Subordinated Notes due November 1, 2066	54			54
Unamortized premiums, discounts and fair value adjustments, net	28			50
	813			1,135
Sunoco, Inc. Debt
5.75% Senior Notes due January 15, 2017	—			400
Bakken Project Debt
Bakken Project $2.50 billion Credit Facility due August 2019	2,500			1,100
Deferred debt issuance costs	(8		)	(13		)
	2,492			1,087
PennTex Debt
PennTex $275 million Revolving Credit Facility due December 2019	—			168
Other	5			30
	33,094			32,930
Less: Current maturities of long-term debt	407			1,189
	$	32,687		$	31,741

⁽¹⁾  As of December 31, 2017management had the intent and ability to refinance the$650 million2.50%senior notes due June 15, 2018 and the$600 million6.70%senior notes due July 1, 2018, and therefore neither was classified as current.

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

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $118 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs:

2018	$	1,700
2019	3,500
2020	1,875
2021	1,400
2022	5,346
Thereafter	19,391
Total	$	33,212

Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.

ETP Senior Notes

The ETP senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually.

The ETP senior notes are unsecured obligations of the Partnership and as a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

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Transwestern Senior Notes

The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually.

Panhandle Junior Subordinated Notes

The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 4.39% at December 31, 2017.

Credit Facilities and Commercial Paper

ETP Credit Facilities

On December 1, 2017 the Partnership entered into a five-year,$4.0 billionunsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a$1.0 billion364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitments may be increased up to$6.0 billionunder certain conditions.We use the ETP Credit Facilities to provide temporary financing for our growth projects, as well as for general partnership purposes.

As ofDecember 31, 2017, the ETP Five-Year Facility had$2.29 billion outstanding, of which$2.01 billionwas commercial paper. The amount available for future borrowings was$1.56 billionafter taking into account letters of credit of$150 million. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was2.48%.

As ofDecember 31, 2017, the ETP 364-Day Facility had$50 millionoutstanding, and the amount available for future borrowings was$950 million. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was5.00%.

ETLP Credit Facility

The ETLP Credit Facility allowed for borrowings of up to$3.75 billionand was used to provide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.

Sunoco Logistics Credit Facilities

ETP maintained a$2.50 billionunsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.

In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of$1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017.

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 billioncredit 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 ofDecember 31, 2017, the Bakken Credit Facility had$2.50 billionof outstanding borrowings. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was3.00%.

PennTex Revolving Credit Facility

PennTex previously maintained a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

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Covenants Related to Our Credit Agreements

Covenants Related to ETP

The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

The ETP Credit Facilities contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:

• incur indebtedness;

• grant liens;

• enter into mergers;

• dispose of assets;

• make certain investments;

• make Distributions (as defined in the ETP Credit Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit Facilities);

• engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

• engage in transactions with affiliates; and

• enter into restrictive agreements.

The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt.The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from1.125% to 2.000%and the applicable margin for base rate loans ranges from0.125%to1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from0.125%to0.300%.  The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from1.125%to1.750%and the applicable margin for base rate loans ranges from0.250%to0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from0.125%to0.225%.

The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0to1, which can generally be increased to5.5to1during a Specified Acquisition Period. Our Leverage Ratio was 3.96to1atDecember 31, 2017, as calculated in accordance with the credit agreements.

The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.

Covenants Related to Panhandle

Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-

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acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.

In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.

Covenants Related to Bakken Credit Facility

The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:

• prohibition of certain incremental secured indebtedness;

• prohibition of certain liens / negative pledge;

• limitations on uses of loan proceeds;

• limitations on asset sales and purchases;

• limitations on permitted business activities;

• limitations on mergers and acquisitions;

• limitations on investments;

• limitations on transactions with affiliates; and

• maintenance of commercially reasonable insurance coverage.

A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than1.20to1(the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.

Compliance with our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as ofDecember 31, 2017.

7. LEGACY ETP PREFERRED UNITS:

The Legacy ETP Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and were reflected as long-term liabilities in our consolidated balance sheets. The Legacy ETP Preferred Units were entitled to a preferential quarterly cash distribution of $0.445 per Preferred Unit if outstanding on the record dates of the Partnership’s common unit distributions. In January 2017, ETP repurchased all of its1.9 millionoutstanding Legacy ETP Preferred Units for cash in the aggregate amount of$53 million.

8. EQUITY:

Limited Partner interests are represented by Common, Class E Units, Class G Units, Class I Units, Class J Units and Class K Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s outstanding securities also include preferred units, as described below. No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance.

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IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs.

Common Units

The change in Common Units was as follows:

	Years Ended December 31,
	2017 (1)	2016 (1)		2015 (1)
Number of Common Units, beginning of period	794.8	758.5		533.4
Common Units redeemed in connection with certain transactions	—	(26.7	)	(77.8	)
Common Units issued in connection with public offerings	54.0	—		—
Common Units issued in connection with certain acquisitions	—	13.3		258.2
Common Units issued in connection with the Distribution Reinvestment Plan	12.0	9.9		11.7
Common Units issued in connection with Equity Distribution Agreements	22.6	39.0		31.7
Common Units issued to ETE in a private placement transaction	23.7	—		—
Common Unit increase from Sunoco Logistics Merger (2)	255.4	—		—
Issuance of Common Units under equity incentive plans	1.6	0.8		1.3
Number of Common Units, end of period	1,164.1	794.8		758.5

⁽¹⁾  The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.

⁽²⁾  Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger.

Our Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”

Equity Distribution Program

From time to time, we have sold Common Units through equity distribution agreements. Such sales of Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreements.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion.

During the year ended December 31, 2017, we issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $752 million of our Common Units remained available to be issued under our currently effective equity distribution agreement.

Equity Incentive Plan Activity

We issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations.

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Distribution Reinvestment Program

Our Distribution Reinvestment Plan (the “DRIP”) provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, the Partnership initiated a new distribution reinvestment plan.

During the years ended December 31, 2017, 2016 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units.

As of December 31, 2017, a total of 20.8 million Common Units remain available to be issued under the existing registration statement.

August 2017 Units Offering

In August 2017, the Partnership issued54 millionETP common units in an underwritten public offering.Net proceeds of$997 millionfrom the offering were used by the Partnership to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

January 2017 Private Placement

In January 2017, the Partnership sold23.7 millionETP Common Units to ETE in a private placement transaction for gross proceeds of approximately$568 million.

Class E Units

There are currently8.9 millionClass E Units outstanding, all of which are currently owned by HHI. The Class E Units generally do not have any voting rights.The Class E Units are entitled to aggregate cash distributions equal to11.1%of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to$1.41per unit per year.As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the Class E Units at a future date.

Class G Units

There are currently90.7 millionClass G Units outstanding, all of which are held by a wholly-owned subsidiary of the Partnership.The Class G Units generally do not have any voting rights.The Class G Units are entitled to aggregate cash distributions equal to35%of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of$3.75per Class G Unit per year.Allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are reflected as treasury units in the consolidated financial statements.

Class H Units

Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017.

Class I Units

In connection with the Bakken Pipeline Transaction discussed in Note 3, in April 2015, ETP issued 100 Class I Units. The Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the Class I Units for the current taxable period and all previous taxable periods is equal to the

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cumulative amount of all distributions made to the holders of the Class I Units and (ii) after making cash distributions to Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in our Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a100%membership interest, sold a49%interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for$2.00 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access and ETCO. The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

Class K Units

On December 29, 2016, the Partnership issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in the Partnership, Class K Units, each of which is entitled to a quarterly cash distribution of$0.67275per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco.If the Partnership is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue1.5%per annum until paid.As ofDecember 31, 2017, a total of101.5 millionClass K Units were held by wholly-owned subsidiaries of ETP.

Sales of Common Units by legacy Sunoco Logistics

Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.

In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.

In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.

In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In connection with the Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated.

ETP Preferred Units

In November 2017, ETP issued950,000of its6.250%Series A Preferred Units at a price of$1,000per unit, and550,000of its6.625%Series B Preferred Units at a price of$1,000per unit.

Distributions on the Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation

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preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

PennTex Tender Offer and Limited Call Right Exercise

In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for$20.00per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.

Quarterly Distributions of Available Cash

Under the Partnership’s limited partnership agreement, within45 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.

If cash distributions exceed$0.0833per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”

The following table shows the target distribution levels and distribution “splits” between the general and limited partners and the holders of the Partnership’s incentive distribution rights (”IDRs”):

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	IDRs	Partners (1)
Minimum Quarterly Distribution	$0.0750	—%	100%
First Target Distribution	up to $0.0833	—%	100%
Second Target Distribution	above $0.0833 up to $0.0958	13%	87%
Third Target Distribution	above $0.0958 up to $0.2638	35%	65%
Thereafter	above $0.2638	48%	52%

⁽¹⁾Includes general partner and limited partner interests, based on the proportionate ownership of each.

The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:

Quarter Ended	ETP		Sunoco Logistics
December 31, 2014	$	0.6633	$	0.4000
March 31, 2015	0.6767		0.4190
June 30, 2015	0.6900		0.4380
September 30, 2015	0.7033		0.4580
December 31, 2015	0.7033		0.4790
March 31, 2016	0.7033		0.4890
June 30, 2016	0.7033		0.5000
September 30, 2016	0.7033		0.5100
December 31, 2016	0.7033		0.5200

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Distributions on common units declared and paid by Post-Merger ETP were as follows:

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 16, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 15, 2017	0.5500
September 30, 2017	November 7, 2017	November 14, 2017	0.5650
December 31, 2017	February 8, 2018	February 14, 2018	0.5650

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

	Total Year
2018	$	153
2019	128
Each year beyond 2019	33

Distributions declared and paid by ETP to the preferred unitholders 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:

	December 31,
	2017			2016
Available-for-sale securities	$	8		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain related to pensions and other postretirement benefits	(5		)	7
Investments in unconsolidated affiliates, net	5			4
Total AOCI, net of tax	$	3		$	8

The table below sets forth the tax amounts included in the respective components of other comprehensive income:

	December 31,
	2017			2016
Available-for-sale securities	$	(2	)	$	(2	)
Foreign currency translation adjustment	3			3
Actuarial loss relating to pension and other postretirement benefits	3			—
Total	$	4		$	1

9. UNIT-BASED COMPENSATION PLANS:

ETP Unit-Based Compensation Plan

We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent

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rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2017, an aggregate total of 8.4 million ETP Common Units remain available to be awarded under our equity incentive plans.

Restricted Units

We have granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five-year service vesting requirement.

The following table shows the activity of the awards granted to employees and non-employee directors:

	Number of Units		Weighted Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 2016	9.4		$	27.68
Legacy Sunoco Logistics unvested awards as of December 31, 2016	3.2		28.57
Awards granted	4.9		17.69
Awards vested	(2.3	)	34.22
Awards forfeited	(1.1	)	25.03
Unvested awards as of December 31, 2017	14.1		23.18

During the years ended December 31, 2017, 2016, and 2015, the weighted average grant-date fair value per unit award granted was $17.69, $23.82 and $23.47, respectively. The total fair value of awards vested was $40 million, $40 million and $57 million, respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2017, a total of 14.1 million unit awards remain unvested, for which ETP expects to recognize a total of $189 million in compensation expense over a weighted average period of 2.7 years.

Cash Restricted Units. The Partnership previously granted cash restricted units, which entitled the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. The Partnership does not currently have any cash restricted units outstanding.

10. INCOME TAXES:

As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows:

	Years Ended December 31,
	2017			2016			2015
Current expense (benefit):
Federal	$	53		$	18		$	(274	)
State	(18		)	(35		)	(51		)
Total	35			(17		)	(325		)
Deferred expense (benefit):
Federal	(1,723		)	(173		)	231
State	192			4			(29		)
Total	(1,531		)	(169		)	202
Total income tax benefit	$	(1,496	)	$	(186	)	$	(123	)

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Historically, our effective rate has differed from the statutory rate primarily due to Partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2017, 2016 and 2015 is as follows:

	Years Ended December 31,
	2017			2016*			2015*
Income tax expense at United States statutory rate of 35 percent	$	352		$	139		$	479
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(457		)	(504		)	(504		)
Federal rate change	(1,559		)	—			—
Goodwill impairments	172			223			—
State income taxes (net of federal income tax effects)	131			(17		)	(37		)
Dividend received deduction	(14		)	(15		)	(24		)
Audit settlement	—			—			(7		)
Change in tax status of subsidiary	(124		)	—			—
Other	3			(12		)	(30		)
Income tax benefit	$	(1,496	)	$	(186	)	$	(123	)

* As adjusted. See Note 2.

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:

	December 31,
	2017			2016
Deferred income tax assets:
Net operating losses and alternative minimum tax credit	$	604		$	380
Pension and other postretirement benefits	21			30
Long-term debt	14			32
Other	93			84
Total deferred income tax assets	732			526
Valuation allowance	(189		)	(118		)
Net deferred income tax assets	$	543		$	408
Deferred income tax liabilities:
Property, plant and equipment	$	(664	)	$	(1,054	)
Investment in unconsolidated affiliates	(2,664		)	(3,728		)
Other	(98		)	(20		)
Total deferred income tax liabilities	(3,426		)	(4,802		)
Net deferred income taxes	$	(2,883	)	$	(4,394	)

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The table below provides a rollforward of the net deferred income tax liability as follows:

	December 31,
	2017			2016
Net deferred income tax liability, beginning of year	$	(4,394	)	$	(4,082	)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)	—			(460		)
Tax provision	1,531			169
Other	(20		)	(21		)
Net deferred income tax liability, end of year	$	(2,883	)	$	(4,394	)

ETP Holdco and other corporate subsidiaries have federal net operating loss carryforward of $1.57 billion, all of which will expire in 2031 through 2037. Our corporate subsidiaries have $62 million of federal alternative minimum tax credits at December 31, 2017, of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have state net operating loss carryforward benefits of $210 million, net of federal tax, which expire between 2018 and 2036. A valuation allowance of $186 million is applicable to the state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit.

The following table sets forth the changes in unrecognized tax benefits:

	Years Ended December 31,
	2017			2016			2015
Balance at beginning of year	$	615		$	610		$	440
Additions attributable to tax positions taken in the current year	—			8			—
Additions attributable to tax positions taken in prior years	28			18			178
Reduction attributable to tax positions taken in prior years	(25		)	(20		)	—
Lapse of statute	(9		)	(1		)	(8		)
Balance at end of year	$	609		$	615		$	610

As of December 31, 2017, we have $605 million ($576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.

Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $9 million, net of tax.

Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in this litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the financial statements as of December 31, 2017.

In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety.  In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact.  Nextel has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court.  Sunoco, Inc. has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter.  However, based upon the Pennsylvania Supreme Court’s

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October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 million after federal income tax benefits) against the receivable.

In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for the 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007.

Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments.

ETP and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from35% to21%for taxable years beginning afterDecember 31, 2017. As a result, the Partnership recognized a deferred tax benefit of$1.56 billionin December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

11. REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Contingent Residual Support Agreement – AmeriGas

In connection with the closing of the contribution of its propane operations in January 2012, ETP previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.

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 millionprincipal amount of6.375%senior notes due 2023 issued by Sunoco LP, (ii)$800 millionprincipal amount of6.25%senior notes due 2021 issued by Sunoco LP and (iii)$2.035 billionaggregate 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 billionaggregate principal amount of4.875%, senior notes due 2023;

• $800 millionaggregate principal amount of5.50%senior notes due 2026; and

• $400 millionaggregate principal amount of5.875%senior notes due 2028.

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

FERC Audit

In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.

Commitments

In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP

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believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

ETP’s joint venture agreements require that it funds its proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon ETP’s 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:

	Years Ended December 31,
	2017		2016			2015
Rental expense(1)	$	90	$	81		$	176
Less: Sublease rental income	—		(1		)	(16		)
Rental expense, net	$	90	$	80		$	160

⁽¹⁾  Includes contingent rentals totaling $26 million for the year ended December 31, 2015.

Future minimum lease commitments for such leases are:

Years Ending December 31:
2018	$	39
2019	36
2020	37
2021	30
2022	23
Thereafter	92
Future minimum lease commitments	257
Less: Sublease rental income	(8		)
Net future minimum lease commitments	$	249

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 consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways 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 is pending. Dakota Access intervened in the case. The SRST soon added a

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request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot.

After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.

The SRST appealed the denial of the preliminary injunction to the United States Court of Appeals for the D.C. Circuit and filed an emergency motion in the United States District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. 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 December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and TRO to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the Tribe. The District Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.

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 rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any 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. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018.

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 auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. 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 is required to file the revised plan with the Court by April 1, 2018. 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 report was filed with the court on December 29, 2017.

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. Briefing on YST’s motion is ongoing.

While we believe that the pending lawsuits are unlikely to halt or suspend the operation of the pipeline, we cannot assure this outcome. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.

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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) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As ofDecember 31, 2017, Sunoco, Inc. is a defendant insevencases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Fourof these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland.

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. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to 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, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, 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 (the “Regency Litigation 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 the Regency Litigation 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. The Regency Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC.

The Regency Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency 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.

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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. Enterprise’s response is due February 26, 2018.

Sunoco Logistics Merger Litigation

Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the Motion to Dismiss, the ETP Unitholder Plaintiffs chose to voluntarily dismiss their claims without prejudice in November 2017.

The ETP-SXL Defendants cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what the outcome of any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger.

Litigation filed by BP Products

On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately$62 million, a figure that BP reduced in subsequent filings to approximately$41 million.

SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.

On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s$13 millionalternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.

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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 December 31, 2017 and 2016, accruals of approximately $33 million and $77 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.

No amounts have been recorded in our December 31, 2017 or 2016 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 this year, 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, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief.In short, the DOJ and EPA proposed federal penalties totaling$7 millionfor the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately$1 millionto resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.

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

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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 December 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 43 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.

	December 31,
	2017		2016
Current	$	36	$	26
Non-current	314		283
Total environmental liabilities	$	350	$	309

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.

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During the years ended December 31, 2017 and 2016, the Partnership recorded $23 million and $43 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, USEPA 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$200,000to 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.

In January 2012, we experienced a release on our products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which we are obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. We also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. We have also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, we received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and 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.

In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to our West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. We do not expect there to be a material impact to our results of operations, cash flows or financial position.

In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of our Permian Express 2 pipeline system in Texas. The proposed penalties are in excess of$100,000. The case went to Hearing in November 2016 and remains open with PHMSA. We do not expect there to be a material impact to our results of operations, cash flows or financial position.

In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of$100,000. The case went to hearing in March 2017 and remains open with PHMSA. We do not expect there to be a material impact to our results of operations, cash flows, or financial position.

In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on our Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of$100,000. We do not expect there to be a material impact to our results of operations, cash flows or financial position.

Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, Occupational Safety and Health 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

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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.

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.

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:

	December 31, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	1,078		2018	(683	)	2017
Basis Swaps IFERC/NYMEX(1)	48,510		2018-2020	2,243		2017
Options – Calls	13,000		2018	—		—
Power (Megawatt):
Forwards	435,960		2018-2019	391,880		2017-2018
Futures	(25,760	)	2018	109,564		2017-2018
Options – Puts	(153,600	)	2018	(50,400	)	2017
Options – Calls	137,600		2018	186,400		2017
Crude (MBbls) – Futures	—		—	(617	)	2017
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	4,650		2018-2020	10,750		2017-2018
Swing Swaps IFERC	87,253		2018-2019	(5,663	)	2017
Fixed Swaps/Futures	(4,700	)	2018-2019	(52,653	)	2017-2019
Forward Physical Contracts	(145,105	)	2018-2020	(22,492	)	2017
Natural Gas Liquid (MBbls) – Forwards/Swaps	6,679		2018-2019	(5,787	)	2017
Refined Products (MBbls) – Futures	(3,783	)	2018-2019	(2,240	)	2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(39,770	)	2018	(36,370	)	2017
Fixed Swaps/Futures	(39,770	)	2018	(36,370	)	2017
Hedged Item – Inventory	39,770		2018	36,370		2017

⁽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
		December 31, 2017		December 31, 2016
July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018(2)	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
July 2019(2)	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
July 2020(2)	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300

⁽¹⁾  Floating rates are based on 3-month LIBOR.

⁽²⁾  Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

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

The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

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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
	December 31, 2017		December 31, 2016		December 31, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	14	$	—	$	(2	)	$	(4	)
	14		—		(2		)	(4		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	262		338		(281		)	(416		)
Commodity derivatives	44		24		(55		)	(52		)
Interest rate derivatives	—		—		(219		)	(193		)
Embedded derivatives in Legacy ETP Preferred Units	—		—		—			(1		)
	306		362		(555		)	(662		)
Total derivatives	$	320	$	362	$	(557	)	$	(666	)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	December 31, 2017			December 31, 2016			December 31, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(219	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	44			24			(55		)	(52		)
Broker cleared derivative contracts	Other current assets (liabilities)	276			338			(283		)	(420		)
		320			362			(557		)	(666		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(20		)	(4		)	20			4
Counterparty netting	Other current assets (liabilities)	(263		)	(338		)	263			338
Total net derivatives		$	37		$	20		$	(274	)	$	(324	)

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

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

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Years Ended December 31,
		2017		2016		2015
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	26	$	14	$	21
Total		$	26	$	14	$	21

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2017			2016			2015
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	31		$	(35	)	$	(11	)
Commodity derivatives – Non-trading	Cost of products sold	3			(173		)	23
Interest rate derivatives	Losses on interest rate derivatives	(37		)	(12		)	(18		)
Embedded derivatives	Other, net	1			4			12
Total		$	(2	)	$	(216	)	$	6

13. RETIREMENT BENEFITS:

Savings and Profit Sharing Plans

We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $38 million, $44 million and $39 million to these 401(k) savings plans for the years ended December 31, 2017, 2016, and 2015, respectively.

Pension and Other Postretirement Benefit Plans

Panhandle

Postretirement benefits expense for the years ended December 31, 2017, 2016 and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.

Sunoco, Inc.

Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.

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Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.

Obligations and Funded Status

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:

	December 31, 2017									December 31, 2016
	Pension Benefits									Pension Benefits
	Funded Plans			Unfunded Plans			Other Postretirement Benefits			Funded Plans			Unfunded Plans			Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$	18		$	51		$	165		$	20		$	57		$	180
Interest cost	1			1			4			1			2			4
Amendments	—			—			7			—			—			—
Benefits paid, net	(2		)	(6		)	(20		)	(1		)	(7		)	(21		)
Actuarial (gain) loss and other	2			1			(1		)	(2		)	(1		)	2
Settlements	(18		)	—			—			—			—			—
Benefit obligation at end of period	1			47			155			18			51			165
Change in plan assets:
Fair value of plan assets at beginning of period	12			—			248			15			—			253
Return on plan assets and other	3			—			11			(2		)	—			6
Employer contributions	6			—			10			—			—			10
Benefits paid, net	(2		)	—			(20		)	(1		)	—			(21		)
Settlements	(18		)	—			—			—			—			—
Fair value of plan assets at end of period	1			—			249			12			—			248
Amount underfunded (overfunded) at end of period	$	—		$	47		$	(94	)	$	6		$	51		$	(83	)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$	—		$	—		$	120		$	—		$	—		$	108
Current liabilities	—			(8		)	(2		)	—			(7		)	(2		)
Non-current liabilities	—			(39		)	(24		)	(6		)	(44		)	(23		)
	$	—		$	(47	)	$	94		$	(6	)	$	(51	)	$	83
Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of:
Net actuarial gain	$	—		$	5		$	(17	)	$	—		$	—		$	(12	)
Prior service cost	—			—			20			—			—			14
	$	—		$	5		$	3		$	—		$	—		$	2

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The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:

	December 31, 2017						December 31, 2016
	Pension Benefits						Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits		Funded Plans		Unfunded Plans		Other Postretirement Benefits
Projected benefit obligation	$	1	$	47	N/A		$	18	$	51	N/A
Accumulated benefit obligation	1		47		$	155	18		51		$	165
Fair value of plan assets	1		—		249		12		—		248

Components of Net Periodic Benefit Cost

	December 31, 2017					December 31, 2016
	Pension Benefits		Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Interest cost	$	2	$	4		$	3		$	4
Expected return on plan assets	—		(9		)	(1		)	(8		)
Prior service cost amortization	—		2			—			1
Settlements	—		—			—			—
Net periodic benefit cost	$	2	$	(3	)	$	2		$	(3	)

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:

	December 31, 2017				December 31, 2016
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	3.27	%	2.34	%	3.65	%	2.34	%
Rate of compensation increase	N/A		N/A		N/A		N/A

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:

	December 31, 2017				December 31, 2016
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	3.52	%	3.10	%	3.60	%	3.06	%
Expected return on assets:
Tax exempt accounts	3.50	%	7.00	%	3.50	%	7.00	%
Taxable accounts	N/A		4.50	%	N/A		4.50	%
Rate of compensation increase	N/A		N/A		N/A		N/A

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The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.

The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:

	December 31,
	2017		2016
Health care cost trend rate	7.20	%	6.73	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.99	%	4.96	%
Year that the rate reaches the ultimate trend rate	2023		2021

Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.

Plan Assets

For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%.

The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.

The fair value of the pension plan assets by asset category at the dates indicated is as follows:

			Fair Value Measurements at December 31, 2017
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Mutual funds(1)	$	1	$	1	$	—	$	—
Total	$	1	$	1	$	—	$	—

⁽¹⁾  Comprised of approximately 100% equities as of December 31, 2017.

			Fair Value Measurements at December 31, 2016
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Mutual funds(1)	$	12	$	12	$	—	$	—
Total	$	12	$	12	$	—	$	—

⁽¹⁾  Comprised of approximately 100% equities as of December 31, 2016.

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The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:

			Fair Value Measurements at December 31, 2017
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Cash and cash equivalents	$	33	$	33	$	—	$	—
Mutual funds(1)	146		146		—		—
Fixed income securities	70		—		70		—
Total	$	249	$	179	$	70	$	—

⁽¹⁾  Primarily comprised of approximately 48% equities, 51% fixed income securities and 1% cash as of December 31, 2017.

			Fair Value Measurements at December 31, 2016
	Fair Value Total		Level 1		Level 2		Level 3
Asset category:
Cash and cash equivalents	$	23	$	23	$	—	$	—
Mutual funds(1)	134		134		—		—
Fixed income securities	91		—		91		—
Total	$	248	$	157	$	91	$	—

⁽¹⁾  Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016.

The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. 

Contributions

We expect to contribute $8 million to pension plans and $10 million to other postretirement plans in 2018.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments

Panhandle and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:

Years	Pension Benefits - Unfunded Plans (1)		Other Postretirement Benefits (Gross, Before Medicare Part D)
2018	$	8	$	24
2019	6		23
2020	6		21
2021	5		19
2022	4		17
2023 – 2027	15		37

⁽¹⁾     Expected benefit payments of funded pension plans are less than $1 million for the next ten years.

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

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14. RELATED PARTY TRANSACTIONS:

In June 2017, the Partnership acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed inNote 8.

ETE previously paid us to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by us on behalf of ETE and its subsidiaries. These agreements expired in 2016.

The Partnership also 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:

	Years Ended December 31,
	2017		2016		2015
Affiliated revenues	$	697	$	377	$	417

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

	December 31,
	2017		2016
Accounts receivable from related companies:
ETE	$	—	$	22
Sunoco LP	219		96
FGT	11		15
Other	88		76
Total accounts receivable from related companies	$	318	$	209
Accounts payable to related companies:
Sunoco LP	195		20
Other	14		23
Total accounts payable to related companies	$	209	$	43

	December 31,
	2017		2016
Long-term notes receivable (payable) – related companies:
Sunoco LP	$	85	$	87
Phillips 66	—		(250		)
Net long-term notes receivable (payable) – related companies	$	85	$	(163	)

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15. 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 Partnership previously presented its retail marketing business as a separate reportable segment. Due to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP. As of December 31, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 millionunits, representing43.6%of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, our investment consists of26.2 millionunits, representing31.8%of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been aggregated into the all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented.

Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

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

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 (excluding lower of cost or market 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:

	Years Ended December 31,
	2017			2016			2015
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	2,891		$	2,155		$	1,912
Intersegment revenues	192			458			338
	3,083			2,613			2,250
Interstate transportation and storage:
Revenues from external customers	915			946			1,008
Intersegment revenues	19			23			17
	934			969			1,025
Midstream:
Revenues from external customers	2,510			2,342			2,607
Intersegment revenues	4,433			2,837			2,449
	6,943			5,179			5,056
NGL and refined products transportation and services:
Revenues from external customers	8,326			5,973			4,569
Intersegment revenues	322			436			428
	8,648			6,409			4,997
Crude oil transportation and services:
Revenues from external customers	11,672			7,539			8,980
Intersegment revenues	31			—			—
	11,703			7,539			8,980
All other:
Revenues from external customers	2,740			2,872			15,216
Intersegment revenues	161			400			558
	2,901			3,272			15,774
Eliminations	(5,158		)	(4,154		)	(3,790		)
Total revenues	$	29,054		$	21,827		$	34,292

	Years Ended December 31,
	2017			2016			2015
Cost of products sold:
Intrastate transportation and storage	$	2,327		$	1,897		$	1,554
Midstream	4,761			3,381			3,264
NGL and refined products transportation and services	6,508			4,553			3,431
Crude oil transportation and services	9,826			6,416			8,158
All other	2,509			2,942			14,029
Eliminations	(5,130		)	(4,109		)	(3,722		)
Total cost of products sold	$	20,801		$	15,080		$	26,714

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	Years Ended December 31,
	2017		2016		2015
Depreciation, depletion and amortization:
Intrastate transportation and storage	$	147	$	144	$	129
Interstate transportation and storage	214		207		210
Midstream	954		840		720
NGL and refined products transportation and services	401		355		290
Crude oil transportation and services	402		251		218
All other	214		189		362
Total depreciation, depletion and amortization	$	2,332	$	1,986	$	1,929

	Years Ended December 31,
	2017			2016			2015
Equity in earnings (losses) of unconsolidated affiliates:
Intrastate transportation and storage	$	(156	)	$	35		$	32
Interstate transportation and storage	236			193			197
Midstream	20			19			(19		)
NGL and refined products transportation and services	33			41			29
Crude oil transportation and services	4			(4		)	(9		)
All other	19			(225		)	239
Total equity in earnings of unconsolidated affiliates	$	156		$	59		$	469

	Years Ended December 31,
	2017			2016			2015
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	626		$	613		$	543
Interstate transportation and storage	1,098			1,117			1,155
Midstream	1,481			1,133			1,237
NGL and refined products transportation and services	1,641			1,496			1,179
Crude oil transportation and services	1,379			834			521
All other	487			540			882
Total Segment Adjusted EBITDA	6,712			5,733			5,517
Depreciation, depletion and amortization	(2,332		)	(1,986		)	(1,929		)
Interest expense, net	(1,365		)	(1,317		)	(1,291		)
Gains on acquisitions	—			83			—
Impairment losses	(920		)	(813		)	(339		)
Losses on interest rate derivatives	(37		)	(12		)	(18		)
Non-cash unit-based compensation expense	(74		)	(80		)	(79		)
Unrealized gains (losses) on commodity risk management activities	56			(131		)	(65		)
Inventory valuation adjustments	—			—			58
Losses on extinguishments of debt	(42		)	—			(43		)
Adjusted EBITDA related to unconsolidated affiliates	(984		)	(946		)	(937		)
Equity in earnings from unconsolidated affiliates	156			59			469
Impairment of investments in unconsolidated affiliates	(313		)	(308		)	—
Other, net	148			115			23
Income before income tax benefit	$	1,005		$	397		$	1,366

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	December 31,
	2017		2016		2015
Assets:
Intrastate transportation and storage	$	5,020	$	5,176	$	4,882
Interstate transportation and storage	13,518		10,833		11,345
Midstream	20,004		17,873		17,039
NGL and refined products transportation and services	17,600		14,074		11,568
Crude oil transportation and services	17,736		15,909		10,941
All other	4,087		6,240		9,353
Total assets	$	77,965	$	70,105	$	65,128

	Years Ended December 31,
	2017		2016		2015
Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):
Intrastate transportation and storage	$	175	$	76	$	105
Interstate transportation and storage	726		280		866
Midstream	1,308		1,255		2,174
NGL and refined products transportation and services	2,971		2,198		2,853
Crude oil transportation and services	453		1,841		1,358
All other	268		160		811
Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis)	$	5,901	$	5,810	$	8,167

	December 31,
	2017		2016		2015
Advances to and investments in unconsolidated affiliates:
Intrastate transportation and storage	$	85	$	399	$	406
Interstate transportation and storage	2,118		2,149		2,516
Midstream	126		111		117
NGL and refined products transportation and services	234		235		258
Crude oil transportation and services	22		18		21
All other	1,231		1,368		1,685
Total advances to and investments in unconsolidated affiliates	$	3,816	$	4,280	$	5,003

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16. QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below. The sum of net income per Limited Partner unit by quarter does not equal the net income per limited partner unit for the year due to the computation of income allocation between the General Partner and Limited Partners and variations in the weighted average units outstanding used in computing such amounts.

	Quarters Ended
	March 31*		June 30*			September 30*		December 31		Total Year
2017:
Revenues	$	6,895	$	6,576		$	6,973	$	8,610	$	29,054
Operating income	683		736			779		199		2,397
Net income	393		296			715		1,097		2,501
Common Unitholders’ interest in net income (loss)	32		(49		)	335		668		986
Basic net income (loss) per Common Unit	$	0.03	$	(0.04	)	$	0.29	$	0.57	$	0.94
Diluted net income (loss) per Common Unit	$	0.03	$	(0.04	)	$	0.29	$	0.57	$	0.93

	Quarters Ended
	March 31*			June 30*		September 30*			December 31*			Total Year*
2016:
Revenues	$	4,481		$	5,289	$	5,531		$	6,526		$	21,827
Operating income	598			708		594			(139		)	1,761
Net income	360			465		94			(336		)	583
Common Unitholders’ interest in net income (loss)	(71		)	58		(252		)	(754		)	(1,019		)
Basic net income (loss) per Common Unit	$	(0.11	)	$	0.06	$	(0.34	)	$	(0.97	)	$	(1.38	)
Diluted net income (loss) per Common Unit	$	(0.11	)	$	0.06	$	(0.34	)	$	(0.97	)	$	(1.38	)

* As adjusted. See Note 2. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.

The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $920 million and $813 million, respectively. Impairment losses in 2017 were primarily related to our Trunkline, SUG Holdings, CDM, Sea Robin and refined products reporting units. Impairment losses in 2016 were primarily related to our PEPL reporting unit, Sea Robin reporting unit and midstream midcontinent operations. The three months ended December 31, 2017 and September 30, 2016 reflected the recognition of a non-cash impairment of our investments in subsidiaries of $313 million and $308 million, respectively, in our interstate transportation and storage segment.

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

17. CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

Prior to the Sunoco Logistics Merger, Sunoco Logistics Partners Operations L.P., a subsidiary of Sunoco Logistics was the issuer of multiple series of senior notes that were guaranteed by Sunoco Logistics. Subsequent to the Sunoco Logistics Merger, these notes continue to be guaranteed by the parent company.

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.”

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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. To present the supplemental condensed consolidating financial information on a comparable basis, the prior period financial information has been recast as if the Sunoco Logistics Merger occurred on January 1, 2015.

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

	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	—			—			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

	December 31, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	41		$	319	$	—		$	360
All other current assets	—			2			5,281		—			5,283
Property, plant and equipment	—			—			50,917		—			50,917
Investments in unconsolidated affiliates	23,350			10,664			4,280		(34,014		)	4,280
All other assets	—			5			9,260		—			9,265
Total assets	$	23,350		$	10,712		$	70,057	$	(34,014	)	$	70,105
Current liabilities	(1,761		)	(3,800		)	11,764		—			6,203
Non-current liabilities	299			7,313			30,148		(299		)	37,461
Noncontrolling interest	—			—			1,232		—			1,232
Total partners’ capital	24,812			7,199			26,913		(33,715		)	25,209
Total liabilities and equity	$	23,350		$	10,712		$	70,057	$	(34,014	)	$	70,105

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	Year Ended December 31, 2017
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	29,054		$	—		$	29,054
Operating costs, expenses, and other	—		1			26,656			—			26,657
Operating income (loss)	—		(1		)	2,398			—			2,397
Interest expense, net	—		(156		)	(1,209		)	—			(1,365		)
Equity in earnings of unconsolidated affiliates	2,564		1,242			156			(3,806		)	156
Impairment of investments in unconsolidated affiliate	—		—			(313		)	—			(313		)
Losses on interest rate derivatives	—		—			(37		)	—			(37		)
Other, net	—		—			168			(1		)	167
Income before income tax benefit	2,564		1,085			1,163			(3,807		)	1,005
Income tax benefit	—		—			(1,496		)	—			(1,496		)
Net income	2,564		1,085			2,659			(3,807		)	2,501
Less: Net income attributable to noncontrolling interest	—		—			420			—			420
Net income attributable to partners	$	2,564	$	1,085		$	2,239		$	(3,807	)	$	2,081
Other comprehensive income (loss)	$	—	$	—		$	(5	)	$	—		$	(5	)
Comprehensive income	2,564		1,085			2,654			(3,807		)	2,496
Comprehensive income attributable to noncontrolling interest	—		—			420			—			420
Comprehensive income attributable to partners	$	2,564	$	1,085		$	2,234		$	(3,807	)	$	2,076

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	Year Ended December 31, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	21,827		$	—		$	21,827
Operating costs, expenses, and other	—		1			20,065			—			20,066
Operating income (loss)	—		(1		)	1,762			—			1,761
Interest expense, net	—		(157		)	(1,160		)	—			(1,317		)
Equity in earnings of unconsolidated affiliates	554		863			59			(1,417		)	59
Impairment of investment in unconsolidated affiliate	—		—			(308		)	—			(308		)
Losses on interest rate derivatives	—		—			(12		)	—			(12		)
Other, net	—		—			214			—			214
Income before income tax benefit	554		705			555			(1,417		)	397
Income tax benefit	—		—			(186		)	—			(186		)
Net income	554		705			741			(1,417		)	583
Less: Net income attributable to noncontrolling interest	—		—			41			—			41
Net income attributable to partners	$	554	$	705		$	700		$	(1,417	)	$	542
Other comprehensive income	$	—	$	—		$	4		$	—		$	4
Comprehensive income	554		705			745			(1,417		)	587
Comprehensive income attributable to noncontrolling interest	—		—			41			—			41
Comprehensive income attributable to partners	$	554	$	705		$	704		$	(1,417	)	$	546

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	Year Ended December 31, 2015
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	34,292		$	—		$	34,292
Operating costs, expenses, and other	—		1			32,064			—			32,065
Operating income (loss)	—		(1		)	2,228			—			2,227
Interest expense, net	—		(133		)	(1,158		)	—			(1,291		)
Equity in earnings of unconsolidated affiliates	1,441		526			469			(1,967		)	469
Losses on interest rate derivatives	—		—			(18		)	—			(18		)
Other, net	—		—			(21		)	—			(21		)
Income before income tax benefit	1,441		392			1,500			(1,967		)	1,366
Income tax benefit	—		—			(123		)	—			(123		)
Net income	1,441		392			1,623			(1,967		)	1,489
Less: Net income attributable to noncontrolling interest	—		—			53			—			53
Net income attributable to partners	$	1,441	$	392		$	1,570		$	(1,967	)	$	1,436
Other comprehensive income	$	—	$	—		$	60		$	—		$	60
Comprehensive income	1,441		392			1,683			(1,967		)	1,549
Comprehensive income attributable to noncontrolling interest	—		—			53			—			53
Comprehensive income attributable to partners	$	1,441	$	392		$	1,630		$	(1,967	)	$	1,496

	Year Ended December 31, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows from operating activities	$	2,564		$	1,047		$	4,681		$	(3,807	)	$	4,485
Cash flows from investing activities	(2,240		)	(1,368		)	(5,672		)	3,807			(5,473		)
Cash flows from financing activities	(324		)	277			981			—			934
Change in cash	—			(44		)	(10		)	—			(54		)
Cash at beginning of period	—			41			319			—			360
Cash at end of period	$	—		$	(3	)	$	309		$	—		$	306

	Year Ended December 31, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows from operating activities	$	553		$	675		$	3,492		$	(1,417	)	$	3,303
Cash flows from investing activities	(976		)	(2,400		)	(4,431		)	1,417			(6,390		)
Cash flows from financing activities	423			1,729			768			—			2,920
Change in cash	—			4			(171		)	—			(167		)
Cash at beginning of period	—			37			490			—			527
Cash at end of period	$	—		$	41		$	319		$	—		$	360

S - 75

	Year Ended December 31, 2015
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows from operating activities	$	1,441		$	388		$	2,886		$	(1,968	)	$	2,747
Cash flows from investing activities	(2,271		)	(1,815		)	(5,702		)	1,968			(7,820		)
Cash flows from financing activities	830			1,363			2,744			—			4,937
Change in cash	—			(64		)	(72		)	—			(136		)
Cash at beginning of period	—			101			562			—			663
Cash at end of period	$	—		$	37		$	490		$	—		$	527

S - 76

EX-10.1

AMENDED AND RESTATED ENERGY TRANSFER EQUITY, L.P. LONG-TERM INCENTIVE PLAN

SECTION 1. Purpose of the Plan.

The Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan (the “Plan”) has been adopted by LE GP, LLC, a Delaware limited liability company (the “Company”), the general partner of Energy Transfer Equity, L.P., a Delaware limited partnership (the “Partnership”). The Plan is intended to promote the interests of the Partnership, the Company and their respective Affiliates by providing to Employees, Consultants and Directors incentive compensation awards based on Units to encourage superior performance. The Plan is also contemplated to enhance the ability of the Company, the Partnership and their respective Affiliates to attract and retain the services of individuals who are essential for the growth and profitability of the Company, the Partnership and their respective Affiliates and to encourage them to devote their best efforts to advancing the business of the Company, the Partnership and their respective Affiliates.

The Plan as set forth herein constitutes an amendment and restatement of the Energy Transfer Equity, L.P. Long-Term Incentive Plan (the “Prior Plan”). The Board has approved this amendment and restatement of the Prior Plan to be effective as of December 20, 2017 (the “Amendment Date”). The Plan as set forth herein shall supersede and replace the Prior Plan in its entirety. Notwithstanding any provision herein to the contrary, each Award granted under the Prior Plan prior to the Amendment Date shall be subject to the terms and provisions applicable to such Award under the Prior Plan as in effect immediately prior to the Amendment Date.

SECTION 2. Definitions.

As used in the Plan, the following terms shall have the meanings set forth below:

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“ASC Topic 718” means Accounting Standards Codification Topic 718, Compensation— Stock Compensation, or any successor accounting standard.

“Award” means an Option, Restricted Unit, Phantom Unit, Unit Appreciation Right or Substitute Award granted under the Plan, and shall include any tandem DERs granted with respect to an Option, Phantom Unit or Unit Appreciation Right.

“Award Agreement” means the written or electronic agreement by which an Award shall be evidenced.

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“Board” means the Board of Directors of the Company.

“Change of Control” means, and shall be deemed to have occurred upon the occurrence of one or more of the following events:

(i)any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other than an Affiliate of the Company, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of fifty percent (50%) or more of the voting power of the voting securities of the Company (or such other entity serving as general partner of the Partnership) or the Partnership;

(ii)the Company or an Affiliate of the Company ceases to be the general partner of the Partnership; or

(iii)the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the assets of the Partnership in one or more transactions to any Person other than the Company or an Affiliate of either the Company or the Partnership.

Notwithstanding the foregoing, if a Change of Control constitutes a payment event with respect to an Award that is subject to Section 409A, the transaction or event described in subsection (i), (ii) or (iii) above must also constitute a “change in control event” within the meaning of Treasury regulation Section 1.409A-3(i)(5), as applied to non-corporate entities and as relates to the holder of such Award, to the extent required to comply with Section 409A.

“Code” means the Internal Revenue Code of 1986, as amended.

“Committee” means the Board, the Compensation Committee of the Board or such other committee as may be appointed by the Board to administer the Plan.

“Consultant” means an individual, other than a Director or Employee, who renders consulting services to the Company, the Partnership or any of their respective Affiliates.

“DER” means a distribution equivalent right representing a right to receive an amount in cash, Units, Restricted Units and/or Phantom Units equal in value to the distributions made by the Partnership with respect to a Unit during the period such Award is outstanding or, if applicable, such other amount set forth in the applicable Award Agreement.

“Director” means a member of the board of directors of the Company or an Affiliate of the Company who is not an Employee or a Consultant.

“Employee” means an employee of the Company, the Partnership or any of their respective Affiliates.

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“ETP Common Units” means common units of Energy Transfer Partners, L.P., a Delaware limited partnership.

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

“Fair Market Value” means the closing sales price of a Unit on the principal national securities exchange or other market in which trading in Units occurs on the applicable date (or if there is no trading in the Units on such date, on the next preceding date on which there was trading) as reported in The Wall Street Journal (or other reporting service approved by the Committee). If Units are not traded on a national securities exchange or other market at the time a determination of fair market value is required to be made hereunder, the determination of fair market value shall be made in good faith by the Committee.

“Option” means an option to purchase Units granted under the Plan.

“Participant” means an Employee, Consultant or Director granted an Award under the Plan.

“Partnership Agreement” means the Third Amended and Restated Agreement of Limited Partnership of the Partnership, as it may be amended or amended and restated from time to time.

“Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, governmental agency or political subdivision thereof or other entity.

“Phantom Unit” means a phantom (notional) Unit granted under the Plan that, to the extent vested, entitles the Participant to receive a Unit, an amount of cash equal to the Fair Market Value of a Unit, other securities or property (including, without limitation, ETP Common Units) equal to the Fair Market Value of a Unit, or a combination thereof, as determined by the Committee in its discretion and set forth in the applicable Award Agreement.

“Restricted Period” means the period established by the Committee with respect to an Award during which the Award remains subject to restrictions established by the Committee, including, without limitation, a period during which an Award or Unit is subject to forfeiture, or restrictions on transfer, or is not yet exercisable by or payable to the Participant, as the case may be.

“Restricted Unit” means a Unit granted under the Plan that is subject to a Restricted Period.

“Rule 16b-3” means Rule 16b-3 promulgated by the SEC under the Exchange Act, or any successor rule or regulation thereto as in effect from time to time.

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“SEC” means the Securities and Exchange Commission, or any successor thereto.

“Section 409A” means Section 409A of the Code and the Department of Treasury regulations and other interpretive guidance issued thereunder, including, without limitation, any such regulations or guidance that may be amended or issued after the Amendment Date.

“Substitute Award” means an award granted pursuant to Section 6(d)(viii) of the Plan.

“UDR” means a distribution made by the Partnership with respect to a Restricted Unit.

“Unit” means a Common Unit of the Partnership.

“Unit Appreciation Right” or “UAR” means an Award, that, upon exercise, entitles the holder to receive the excess of the Fair Market Value of a Unit on the exercise date over the exercise price established for such Unit Appreciation Right. Such excess shall be paid in Units, in cash or any combination thereof, as determined by the Committee in its discretion and set forth in the applicable Award Agreement.

SECTION 3. Administration. The Plan shall be administered by the Committee. A majority of the Committee shall constitute a quorum, and the acts of the members of the Committee who are present at any meeting thereof at which a quorum is present, or acts unanimously approved by the members of the Committee in writing, shall be the acts of the Committee; provided, however, that in the event that the Board is not also serving as the Committee, the Board, in its sole discretion, may at any time and from time to time exercise any and all rights and duties of the Committee under the Plan. Subject to the following and applicable law, the Committee, in its sole discretion, may delegate any or all of its powers and duties under the Plan, including the power to grant Awards under the Plan, to the Chief Executive Officer of the Company and/or any other executive officer of the Company, subject to such limitations on such delegated powers and duties as the Committee may impose, if any. Upon any such delegation all references in the Plan to the “Committee”, other than in Section 7, shall be deemed to include the Chief Executive Officer and/or any other executive officer; provided, however, that such delegation shall not limit the Chief Executive Officer’s and/or any other executive officer’s right to receive Awards under the Plan. Notwithstanding the foregoing, the Chief Executive Officer and/or any other executive officer may not grant Awards to, or take any action with respect to any Award previously granted to, a person who is an officer subject to Rule 16b-3 or a member of the Board. Subject to the terms of the Plan and applicable law, and in addition to other express powers and authorizations conferred on the Committee by the Plan, the Committee shall have full power and authority to: (i) designate Participants; (ii) determine the type or types of Awards to be granted to a Participant; (iii) determine the number of Units to be covered by Awards; (iv) determine the terms and conditions of any Award; (v) determine whether, to what extent, and under what circumstances Awards may be settled, exercised, canceled, or forfeited; (vi) interpret and administer the Plan and any instrument or agreement relating to an Award made under the Plan; (vii) establish, amend, suspend, or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the Plan; and (viii) make any other

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determination and take any other action that the Committee deems necessary or desirable for the administration of the Plan. The Committee may correct any defect or supply any omission or reconcile any inconsistency in the Plan or an Award Agreement in such manner and to such extent as the Committee deems necessary or appropriate. Unless otherwise expressly provided in the Plan, all designations, determinations, interpretations, and other decisions under or with respect to the Plan or any Award shall be within the sole discretion of the Committee, may be made at any time and shall be final, conclusive, and binding upon all Persons, including the Company, the Partnership, any of their respective Affiliates, any Participant, and any beneficiary of any Award.

SECTION 4. Units.

(a)    Limits on Units Deliverable. Subject to adjustment as provided in Section 4(c), the number of Units that may be delivered with respect to Awards under the Plan is 12,000,000 (inclusive of Units deliverable with respect to outstanding Awards under the Plan as of the Amendment Date). Units withheld from an Award to either satisfy the exercise price of such Award or the Company’s or an Affiliate of the Company’s tax withholding obligations with respect to the Award shall not be considered to be Units delivered under the Plan for this purpose. If any Award is forfeited, canceled, exercised, or otherwise terminates or expires without the actual delivery of Units pursuant to such Award, the Units subject to such Award shall again be available for Awards under the Plan. There shall not be any limitation on the number of Awards that may be granted and paid in cash.

(b)Sources of Units Deliverable Under Awards. Any Units delivered pursuant to an Award shall consist, in whole or in part, of Units acquired (i) in the open market, (ii) from the Partnership, including newly issued Units, (iii) from any Affiliate of the Partnership, or (iv) from any other Person, or any combination of the foregoing, as determined by the Committee in its discretion.

(c)Adjustments. With respect to any “equity restructuring” event that could result in an additional compensation expense to the Company, the Partnership, or any of their respective Affiliates pursuant to the provisions of ASC Topic 718 if adjustments to Awards with respect to such event were discretionary, the Committee shall equitably adjust the number and type of Units (or other securities or property) covered by each outstanding Award and the terms and conditions, including the exercise price and performance goals (if any), of such Award to equitably reflect such event and shall adjust the number and type of Units (or other securities or property) with respect to which Awards may be granted under the Plan after such event. With respect to any other similar event that would not result in an accounting charge under ASC Topic 718 if the adjustment to Awards with respect to such event were subject to discretionary action, the Committee shall have complete discretion to adjust Awards and the number and type of Units (or other securities or property) with respect to which Awards may be granted under the Plan in such manner as it deems appropriate with respect to such other event.

SECTION 5. Eligibility.

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Any Employee, Consultant or Director who performs services, directly or indirectly, for the benefit of the Partnership shall be eligible to be designated as a Participant and receive an Award under the Plan.

SECTION 6. Awards.

(a)Options. The Committee shall have the authority to determine the Employees, Consultants and Directors to whom Options shall be granted, the number of Units to be covered by each Option, whether DERs are granted with respect to such Option, the purchase or exercise price therefor, the Restricted Period and other conditions and limitations applicable to the exercise of the Option, including the following terms and conditions and such additional terms and conditions, as the Committee shall determine, that are not inconsistent with the provisions of the Plan.

(i)    Exercise Price. The exercise price per Unit purchasable under an Option shall be determined by the Committee at the time the Option is granted but, except with respect to a Substitute Award, may not be less than the Fair Market Value of a Unit as of the date of grant of the Option.

(ii)Time and Method of Exercise. The Committee shall determine the exercise terms and the Restricted Period, if any, with respect to an Option grant, which may include, without limitation, (A) a provision for accelerated vesting upon the achievement of specified performance goals or such other events as the Committee may provide, and

(B) the method or methods by which payment of the exercise price with respect thereto may be made or deemed to have been made, which may include, without limitation, cash, check acceptable to the Company, a “cashless-broker” exercise through procedures approved by the Company, withholding Units to be acquired upon the Option exercise, or any combination of methods, having a Fair Market Value on the exercise date equal to the relevant exercise price.

(iii)Forfeitures. Except as otherwise provided in the terms of the Option grant, upon termination of a Participant’s employment with or consulting services to the Company and its Affiliates or membership on the Board, whichever is applicable, for any reason during the applicable Restricted Period, all Options shall be forfeited by the Participant. The Committee may, in its discretion, waive in whole or in part such forfeiture with respect to a Participant’s Options.

(iv)Option DERs. To the extent provided by the Committee, in its discretion, a grant of Options may include a tandem DER grant, which may provide that such DERs shall be paid directly to the Participant, be credited to a bookkeeping account (with or without interest in the discretion of the Committee) subject to the same vesting restrictions as the tandem Options Award, or be subject to such other provisions or restrictions as determined by the Committee in its discretion.

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(b)Unit Appreciation Rights. The Committee shall have the authority to determine the Employees, Consultants and Directors to whom Unit Appreciation Rights shall be granted, the number of Units to be covered by each grant, whether DERs are granted with respect to such Unit Appreciation Right and the terms of any DERs, the exercise price therefor and the conditions and limitations applicable to the exercise of the Unit Appreciation Right, including the following terms and conditions and such additional terms and conditions, as the Committee shall determine, that are not inconsistent with the provisions of the Plan.

(i)    Exercise Price. The exercise price per Unit Appreciation Right shall be determined by the Committee at the time the Unit Appreciation Right is granted but may not be less than the Fair Market Value of a Unit as of the date of grant.

(ii)    Time of Exercise. The Committee shall determine the time or times at which a Unit Appreciation Right may be exercised in whole or in part, which may include, without limitation, accelerated vesting upon the achievement of specified performance goals or such other events as the Committee may provide.

(iii)    Forfeitures. Except as otherwise provided in the terms of the Award Agreement, upon termination of a Participant’s employment or consulting arrangement with the Company and its Affiliates or membership on the Board, whichever is applicable, for any reason during the applicable Restricted Period, all outstanding Unit Appreciation Rights awarded the Participant shall be automatically forfeited on such termination. The Committee may, in its discretion, waive in whole or in part such forfeiture with respect to a Participant’s Unit Appreciation Rights.

(c)Restricted Units and Phantom Units. The Committee shall have the authority to determine the Employees, Consultants and Directors to whom Restricted Units or Phantom Units shall be granted, the number of Restricted Units or Phantom Units to be granted to each such Participant, the Restricted Period, the conditions under which the Restricted Units or Phantom Units may become vested or forfeited and such other terms and conditions as the Committee may establish with respect to such Awards.

(i)    DERs. To the extent provided by the Committee, in its discretion, a grant of Phantom Units may include a tandem DER grant, which may provide that such DERs shall be paid directly to the Participant, be credited to a bookkeeping account (with or without interest in the discretion of the Committee), be “reinvested” in Restricted Units or in additional Phantom Units, and be subject to the same or different vesting restrictions as the tandem Phantom Unit Award, or be subject to such other provisions or restrictions as determined by the Committee in its discretion.

(ii)    UDRs. To the extent provided by the Committee, in its discretion, a grant of Restricted Units may provide that distributions made by the Partnership with respect to the Restricted Units shall be subject to the same forfeiture and other restrictions as the

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Restricted Unit and, if restricted, such distributions shall be held, without interest, until the Restricted Unit vests or is forfeited with the UDR being paid or forfeited at the same time, as the case may be. In addition, the Committee may provide that such distributions be used to acquire additional Restricted Units for the Participant. Such additional Restricted Units may be subject to such vesting and other terms as the Committee may prescribe. Absent such a restriction on the UDRs in the applicable Award Agreement, UDRs shall be paid to the holder of the Restricted Unit without restriction.

(iii)    Forfeitures. Except as otherwise provided in the terms of the applicable Award Agreement, upon termination of a Participant’s employment with or consulting services to the Company and its Affiliates or membership on the Board, whichever is applicable, for any reason during the applicable Restricted Period, all outstanding Restricted Units and Phantom Units awarded the Participant shall be automatically forfeited on such termination. The Committee may, in its discretion, waive in whole or in part such forfeiture with respect to a Participant’s Restricted Units and/or Phantom Units.

(iv) Lapse of Restrictions.

(A)    Phantom Units. Upon or as soon as reasonably practical following the vesting of each Phantom Unit, subject to the provisions of Section 8(b), the Participant shall be entitled to receive from the Company one Unit, cash equal to the Fair Market Value of a Unit, other securities or property (including, without limitation, ETP Common Units) equal to the Fair Market Value of a Unit or a combination thereof, as determined by the Committee in its discretion.

(B)    Restricted Units. Upon or as soon as reasonably practical following the vesting of each Restricted Unit, subject to satisfying the tax withholding obligations of Section 8(b), the Participant shall be entitled to have the restrictions removed from his or her Unit so that the Participant then holds an unrestricted Unit.

(d) General.

(i)    Awards May Be Granted Separately or Together. Awards may, in the discretion of the Committee, be granted either alone or in addition to, in tandem with, or in substitution for any other Award granted under the Plan or any award granted under any other plan of the Company or any Affiliate of the Company. Awards granted in addition to or in tandem with other Awards or awards granted under any other plan of the Company or any Affiliate of the Company may be granted either at the same time as or at a different time from the grant of such other Awards or awards.

(ii) Limits on Transfer of Awards.

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(A)    Except as provided in Paragraph (C) below, each Option and UAR shall be exercisable only by the Participant during the Participant’s lifetime, or by the person to whom the Participant’s rights shall pass by will or the laws of descent and distribution.

(B)    Except as provided in Paragraph (C) below, no Award and no right under any such Award may be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by a Participant and any such purported assignment, alienation, pledge, attachment, sale, transfer or encumbrance shall be void and unenforceable against the Company, the Partnership or any of their respective Affiliates.

(C)    To the extent specifically provided by the Committee with respect to an Award, an Award may be transferred by a Participant without consideration to any “family member” of the Participant, as defined in the instructions to use of the Form S-8 Registration Statement under the Securities Act of 1933, as amended, or any related family trusts, limited partnerships or similar entities or other transferee specifically approved by the Committee.

(iii)    Term of Awards. The term of each Award shall be for such period as may be determined by the Committee.

(iv)    Unit Certificates. The Units or other securities of the Partnership pursuant to an Award may be evidenced in any manner deemed appropriate by the Committee in its sole discretion, including, without limitation, in the form of a certificate issued in the name of the Participant or by book entry, electronic or otherwise and shall be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the Plan or the rules, regulations, and other requirements of the SEC, any securities exchange upon which such Units or other securities are then listed, and any applicable federal or state laws, and the Committee may cause a legend or legends to be inscribed on any such certificates to make appropriate reference to such restrictions.

(v)    Consideration for Grants. Awards may be granted for such consideration, including services, as the Committee determines.

(vi)    Delivery of Units or other Securities and Payment by Participant of Consideration. Notwithstanding anything in the Plan or any Award Agreement to the contrary, delivery of Units pursuant to the exercise or vesting of an Award may be deferred for any period during which, in the good faith determination of the Committee, the Company is not reasonably able to obtain Units to deliver pursuant to such Award without violating applicable law or the applicable rules or regulations of any governmental agency or authority or securities exchange. No Units or other securities shall be delivered pursuant to any Award until payment in full of any amount required to be paid pursuant to the Plan or the applicable Award

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Agreement (including, without limitation, any exercise price or tax withholding) is received by the Company.

(vii)    Change of Control. Unless specifically provided otherwise in the applicable Award Agreement, upon a Change of Control all outstanding Awards shall automatically vest and be payable at their maximum target level or become exercisable in full, as the case may be.

(viii)    Substitute Awards. Awards may be granted under the Plan in substitution for similar assumed, canceled or forfeited awards held by individuals who become Employees, Consultants or Directors as a result of a merger, consolidation or acquisition by the Company or an Affiliate of the Company of another entity or the assets of another entity. Such Substitute Awards that are Options may have exercise prices less than the Fair Market Value of a Unit on the date of such substitution.

(ix)    Prohibition on Repricing of Options and UARs. Subject to the provisions of Section 4(c) and Section 7(c), the terms of outstanding Award Agreements may not be amended without the approval of the Partnership’s unitholders so as to (A) reduce the Unit exercise price of any outstanding Options or UARs, (B) grant a new Option, UAR or other Award in substitution for, or upon the cancellation of, any previously granted Option or UAR that has the effect of reducing the exercise price thereof, (C) exchange any Option or UAR for Units, cash or other consideration when the exercise price per Unit under such Option or UAR exceeds the Fair Market Value of the underlying Units, or (D) take any other action that would be considered a “repricing” of an Option or UAR under the listing standards of the New York Stock Exchange or, if the Units are not then-listed on such exchange, to the extent applicable, on any other national securities exchange on which the Units are listed. Subject to Section 4(c), Section 7(c) and Section 8(m), the Committee shall have the authority, without the approval of the Partnership’s unitholders, to amend any outstanding Award to increase the per Unit exercise price of any outstanding Options or UARs or to cancel and replace any outstanding Options or UARs with the grant of Options or UARs having a per Unit exercise price that is equal to or greater than the per Unit exercise price of the original Options or UARs.

SECTION 7. Amendment and Termination.

Except to the extent prohibited by applicable law:

(a)Amendments to the Plan. Except as required by applicable law or the rules of the principal securities exchange on which the Units are traded and subject to Section 7(b) below, the Board or the Committee may amend, alter, suspend, discontinue, or terminate the Plan in any manner, including increasing the number of Units available for Awards under the Plan, without the consent of any partner, Participant, other holder or beneficiary of an Award, or any other Person.

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(b)Amendments to Awards. Subject to Section 7(a), the Committee may waive any conditions or rights under, amend any terms of, or alter any Award theretofore granted, provided no change, other than pursuant to Section 7(c), in any Award shall materially reduce the benefit to a Participant without the consent of such Participant.

(c)Actions Upon the Occurrence of Certain Events. Upon the occurrence of any event described in Section 4(c) of the Plan, any Change of Control, any change in applicable law or regulation affecting the Plan or Awards thereunder, or any change in accounting principles affecting the financial statements of the Partnership, the Committee, in its sole discretion and on such terms and conditions as it deems appropriate, may take any one or more of the following actions in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the Plan or an outstanding Award:

(i)    provide for either (A) the termination of any Award in exchange for an amount of cash, if any, equal to the amount that would have been attained upon the exercise of such Award or realization of the Participant’s rights (and, for the avoidance of doubt, if as of the date of the occurrence of such transaction or event, the Committee determines in good faith that no amount would have been attained upon the exercise of such Award or realization of the Participant’s rights, then such Award may be terminated by the Company without payment) or (B) the replacement of such Award with other rights or property selected by the Committee in its sole discretion;

(ii)    provide that such Award be assumed by the successor or survivor entity, or a parent or subsidiary thereof, or be exchanged for similar options, rights or awards covering the equity of the successor or survivor, or a parent or subsidiary thereof, with appropriate adjustments as to the number and kind of equity interests and prices;

(iii)    make adjustments in the number and type of Units (or other securities or property) subject to outstanding Awards, and in the number and kind of outstanding Awards or in the terms and conditions of (including the exercise price), and the vesting/performance criteria included in, outstanding Awards, or both;

(iv)    provide that such Award shall be exercisable or payable, notwithstanding anything to the contrary in the Plan or the applicable Award Agreement; and

(v)    provide that the Award cannot be exercised or become payable after such event, i.e., shall terminate upon such event.

Notwithstanding the foregoing, with respect to any “equity restructuring” event that could result in an additional compensation expense to the Company or the Partnership pursuant to the provisions of ASC Topic 718, the provisions in Section 4(c) shall control to the extent they are in conflict with the discretionary provisions of this Section 7(c).

SECTION 8. General Provisions.

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(a)No Rights to Awards. No Person shall have any claim to be granted any Award under the Plan, and there is no obligation for uniformity of treatment of Participants. The terms and conditions of Awards need not be the same with respect to each recipient.

(b)Tax Withholding. Unless other arrangements have been made that are acceptable to the Company, the Company or any Affiliate of the Company is authorized to withhold from any Award, from any payment due or transfer made under any Award or from any compensation or other amount owing to a Participant the amount (in cash, Units, Units that would otherwise be issued pursuant to such Award, other securities or property (including, without limitation, ETP Common Units) of any applicable taxes payable in respect of the grant or settlement of an Award, its exercise, the lapse of restrictions thereon, or any payment or transfer under an Award or under the Plan and to take such other action as may be necessary in the opinion of the Company to satisfy its withholding obligations for the payment of such taxes.

(c)No Right to Employment or Services. The grant of an Award shall not be construed as giving a Participant the right to be retained in the employ of the Company or any Affiliate of the Company, continue consulting services or to remain on the Board, as applicable. Furthermore, the Company or an Affiliate of the Company may at any time dismiss a Participant from employment or consulting free from any liability or any claim under the Plan, unless otherwise expressly provided in the Plan, any Award agreement or other agreement.

(d)Governing Law. The validity, construction, and effect of the Plan and any rules and regulations relating to the Plan shall be determined in accordance with the laws of the State of Texas without regard to its conflict of laws principles.

(e)Severability. If any provision of the Plan or any Award is or becomes or is deemed to be invalid, illegal, or unenforceable in any jurisdiction or as to any Person or Award, or would disqualify the Plan or any Award under any law deemed applicable by the Committee, such provision shall be construed or deemed amended to conform to the applicable law, or if it cannot be construed or deemed amended without, in the determination of the Committee, materially altering the intent of the Plan or the Award, such provision shall be stricken as to such jurisdiction, Person or Award and the remainder of the Plan and any such Award shall remain in full force and effect.

(f)Other Laws. The Committee may refuse to issue or transfer any Units or other consideration under an Award if, in its sole discretion, it determines that the issuance or transfer of such Units or such other consideration might violate any applicable law or regulation, the rules of the principal securities exchange on which the Units are then traded, or entitle the Partnership or an Affiliate of the Partnership to recover the same under Section 16(b) of the Exchange Act, and any payment tendered to the Company by a Participant, other holder or beneficiary in connection with the exercise of such Award shall be promptly refunded to the relevant Participant, holder or beneficiary.

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(g)No Trust or Fund Created. Neither the Plan nor any Award shall create or be construed to create a trust or separate fund of any kind or a fiduciary relationship between the Company or any participating Affiliate of the Company and a Participant or any other Person. To the extent that any Person acquires a right to receive payments from the Company or any participating Affiliate of the Company pursuant to an Award, such right shall be no greater than the right of any general unsecured creditor of the Company or any participating Affiliate of the Company.

(h)No Fractional Units. No fractional Units shall be issued or delivered pursuant to the Plan or any Award, and the Committee shall determine whether cash, other securities, or other property shall be paid or transferred in lieu of any fractional Units or whether such fractional Units or any rights thereto shall be canceled, terminated, or otherwise eliminated.

(i)Headings. Headings are given to the Sections and subsections of the Plan solely as a convenience to facilitate reference. Such headings shall not be deemed in any way material or relevant to the construction or interpretation of the Plan or any provision thereof.

(j)Facility Payment. Any amounts payable hereunder to any person under legal disability or who, in the judgment of the Committee, is unable to properly manage his financial affairs, may be paid to the legal representative of such person, or may be applied for the benefit of such person in any manner that the Committee may select, and the Company shall be relieved of any further liability for payment of such amounts.

(k)Participation by Affiliates. In making Awards to Employees employed by an entity other than the Company, the Committee shall be acting on behalf of the Affiliate of the Company or the Partnership, and to the extent the Partnership has an obligation to reimburse the Company for compensation paid for services rendered for the benefit of the Partnership, such payments or reimbursement payments may be made by the Partnership directly to the Affiliate of the Company or the Partnership, and, if made to the Company, shall be received by the Company as agent for the Affiliate of the Company or the Partnership.

(l)Gender and Number. Words in the masculine gender shall include the feminine gender, the plural shall include the singular and the singular shall include the plural.

(m)Compliance with Section 409A. Nothing in the Plan or any Award Agreement shall operate or be construed to cause the Plan or an Award that is subject to Section 409A to fail to comply with the requirements of Section 409A. The applicable provisions of Section 409A are hereby incorporated by reference and shall control over any Plan or Award Agreement provision in conflict therewith or that would cause a failure of compliance thereunder, to the extent necessary to resolve such conflict or obviate such failure. Subject to any other restrictions or limitations contained herein, in the event that a “specified employee” (as defined under Section 409A) becomes entitled to a payment under an Award that constitutes a “deferral of compensation” (as defined under Section 409A) on account of a “separation from service” (as defined under Section 409A), to the extent required by the Code, such payment shall not occur until the date that is six

13

months plus one day from the date of such separation from service. Any amount that is otherwise payable within the six-month period described herein will be aggregated and paid in a lump sum without interest on the date that is six months plus one day from the date of such separation from service. Notwithstanding any provision herein to the contrary, none of the Board, the Committee, the Company, the Partnership or any of their respective Affiliates makes any representations that any Awards (or payments with respect to any Awards) are exempt from or compliant with Section 409A and in no event shall the Board, the Committee, the Company, the Partnership or any of their respective Affiliates be liable for all or any portion of any taxes, penalties, interest or other expenses that may be incurred by any Participant on account of non-compliance with Section 409A.

(n)Clawback. To the extent required by applicable law or any applicable securities exchange listing standards, or as otherwise determined by the Committee, Awards and amounts paid or payable pursuant to or with respect to Awards shall be subject to the provisions of any applicable clawback policies or procedures adopted by the Company or the Partnership, which clawback policies or procedures may provide for forfeiture, repurchase and/or recoupment of Awards and amounts paid or payable pursuant to or with respect to Awards. Notwithstanding any provision of the Plan or any Award Agreement to the contrary, the Company and the Partnership reserve the right, without the consent of any Participant or beneficiary of any Award, to adopt any such clawback policies and procedures, including such policies and procedures applicable to the Plan or any Award Agreement with retroactive effect.

SECTION 9. Term of the Plan.

The Plan, as amended and restated hereby, shall be effective on the Amendment Date and shall continue until the earliest of (i) the date terminated by the Board or the Committee, (ii) all Units available under the Plan have been delivered, or (iii) the 10th anniversary of the Amendment Date. Unless otherwise expressly provided in the Plan or in an applicable Award Agreement, however, any Award granted prior to such termination, and the authority of the Board or the Committee to amend, alter, adjust, suspend, discontinue, or terminate any such Award or to waive any conditions or rights under such Award, shall extend beyond such termination date.

14

EX-12.1

Exhibit 12.1

ENERGY TRANSFER EQUITY, L.P.

Computation of Ratio of Earnings to Fixed Charges

(in millions, except for ratio amounts)

(Unaudited)

	Years Ended December 31,
	2017			2016			2015			2014			2013
Fixed charges:
Interest expense	$	1,922		$	1,804		$	1,622		$	1,368		$	1,221
Capitalized interest	286			201			164			101			45
Interest expense included in rental expense	18			17			27			10			16
Distribution to the Series A Convertible Redeemable Preferred Units	—			—			3			3			6
Total fixed charges	2,226			2,022			1,816			1,482			1,288
Earnings:
Income from continuing operations before income taxes	710			204			900			1,339			411
Less: equity in earnings of affiliates	144			270			276			332			236
Total earnings	566			(66		)	624			1,007			175
Add:
Fixed charges	2,226			2,022			1,816			1,482			1,288
Amortization of capitalized interest	24			3			(21		)	8			7
Distributed income of equity investees	297			268			409			291			236
Less:
Interest capitalized	(286		)	(201		)	(164		)	(101		)	(45		)
Income available for fixed charges	$	2,827		$	2,026		$	2,664		$	2,687		$	1,661
Ratio of earnings to fixed charges	1.27			1.00			1.47			1.81			1.29

EX-18.1

February 23, 2018

Board of Directors

LE GP, LLC

8111 Westchester Drive, Suite 600

Dallas, TX 75225

Dear Directors:

We are providing this letter solely for inclusion as an exhibit to Energy Transfer Equity, L.P.’s (the “Partnership”) 2017 Form 10-K filing pursuant to Item 601 of Regulation S-K.

We have audited the consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017, as set forth in our report dated February 23, 2018. As stated in Note 2 to those financial statements, the Partnership changed its accounting for inventory costing from the last-in, first-out (LIFO) method to the weighted average cost method for all legacy Sunoco Logistics Partners L.P. inventory. Note 2 also states management’s belief that the newly adopted accounting principle is preferable in the circumstances because it more closely aligns with the accounting policies across the consolidated entity, given that the other entities are accounting for inventory costing using the weighted average cost method.

With regard to the aforementioned accounting change, it should be understood that authoritative criteria have not been established for evaluating the preferability of one acceptable method of accounting over another acceptable method and, in expressing our concurrence below, we have relied on management’s business planning and judgment and on management’s determination that this change in accounting principle is preferable.

Based on our reading of management’s stated reasons and justification for this change in accounting principle in the Form 10-K, and our discussions with management as to their judgment about the relevant business planning factors relating to the change, we concur with management that the newly adopted method of accounting is preferable in the Partnership’s circumstances.

Sincerely,

/s/ GRANT THORNTON LLP

Dallas, Texas

EX-21.1

Exhibit 21.1

LIST OF SUBSIDIARIES

SUBSIDIARIES OF ENERGY TRANSFER EQUITY, L.P., a Delaware limited partnership:

Energy Transfer LNG Export, LLC, a Delaware limited liability company

Energy Transfer LNG Holdings, LLC, a Delaware limited liability company

Energy Transfer Partners GP, L.P., a Delaware limited partnership

Energy Transfer Partners, L.L.C., a Delaware limited liability company

Energy Transfer Partners, L.P., a Delaware limited partnership

ET Crude Oil Terminals, LLC, a Delaware limited liability company

ET LNG GP, LLC, a Delaware limited liability company

ET LNG LP, a Delaware limited partnership

ETC Illinois LLC, a Delaware limited liability company

ETE Common Holdings, LLC, a Delaware limited liability company

ETE Services Company, LLC, a Delaware limited liability company

ETP Acquisition Sub, LLC, a Delaware limited liability company

ETP Merger Sub A, LLC, a Delaware limited liability company

ETP Merger Sub B, LLC, a Delaware limited liability company

Lake Charles LNG Company, LLC, Delaware limited liability company

Lake Charles LNG Export Company, LLC, a Delaware limited liability company

LE GP, LLC, a Delaware limited liability company

Sunoco GP LLC, a Delaware limited liability company

Sunoco LP, a Delaware limited partnership

Sunoco Partners Lease Acquisition & Marketing LLC, a Delaware limited partnership

Sunoco Partners LLC, a Pennsylvania limited liability company

SUBSIDIARIES OF ENERGY TRANSFER PARTNERS, L.P., a Delaware limited partnership:

Advanced Diesel LLC, a Idaho limited liability company

Advanced Meter Solutions LLC, a Delaware limited liability company

Aqua-ETC Water Solutions, LLC, a Delaware limited liability company

Arguelles Pipeline S de R.L. DE C.V., a Mexico SRL

Atlantic Petroleum (Out) LLC, a Delaware limited liability company

Atlantic Petroleum Company LLC, a Delaware limited liability company

Atlantic Petroleum Delaware Company LLC, a Delaware limited liability company

Atlantic Pipeline (Out) L.P. Texas limited partnership

Atlantic Refining & Marketing, LLC, a Delaware limited liability company

Bakken Gathering LLC, a Delaware limited liability company

Bakken Holdings Company LLC, a Delaware limited liability company

Bakken Pipeline Investments LLC, a Delaware limited liability company

Bayou Bridge Pipeline, LLC, a Delaware limited liability company

Bayview Refining Company, LLC, a Delaware limited liability company

BBP Construction Management, LLC, a Delaware limited liability company

CDM Environmental & Technical Services LLC, a Delaware limited liability company

CDM Resource Management LLC, a Delaware limited liability company

Chalkley Gathering Company, LLC, a Texas limited liability company

Citrus Energy Services, Inc., a Delaware corporation

Citrus ETP Finance LLC, a Delaware limited liability company

Citrus, LLC, a Delaware limited liability company

Clean Air Action Corporation, a Delaware corporation

CMA Pipeline Partnership, LLC, a Texas limited liability company

Comanche Trail Pipeline, LLC, a Texas limited liability company

Connect Gas Pipeline LLC, a Delaware limited liability company

Consorcio Terminales LLC, a Delaware limited liability company

CrossCountry Citrus, LLC, a Delaware limited liability company

CrossCountry Energy, LLC, a Delaware limited liability company

Dakota Access Holdings LLC, a Delaware limited liability company

Dakota Access Truck Terminals, LLC, a Delaware limited liability company

Dakota Access, LLC, a Delaware limited liability company

DAPL-ETCO Construction Management, LLC, a Delaware limited liability company

DAPL-ETCO Operations Management, LLC, a Delaware limited liability company

Dulcet Acquisition LLC, a Delaware limited liability company

Eastern Gulf Crude Access, LLC, a Delaware limited liability company

Edwards Lime Gathering, LLC, a Delaware limited liability company

ELG Oil LLC, a Delaware limited liability company

ELG Utility LLC, a Delaware limited liability company

Energy Transfer Aviation LLC, a Delaware limited liability company

Energy Transfer, LP, a Delaware limited partnership

Energy Transfer Canada, LLC, a Delaware limited liability company

Energy Transfer Crude Oil Company, LLC, a Delaware limited liability company

Energy Transfer Data Center, LLC, a Delaware limited liability company

Energy Transfer Employee Management LLC, a Delaware limited liability company

Energy Transfer Fuel GP, LLC, a Delaware limited liability company

Energy Transfer Fuel, LP, a Delaware limited partnership

Energy Transfer Group, L.L.C., a Texas limited liability company

Energy Transfer International Holdings LLC, a Delaware limited liability company

Energy Transfer Interstate Holdings, LLC, a Delaware limited liability company

Energy Transfer LNG Export, LLC, a Delaware limited liability company

Energy Transfer Management Holdings, LLC, a Delaware limited liability company

Energy Transfer Mexicana, LLC, a Delaware limited liability company

Energy Transfer Rail Company, LLC, a Delaware limited liability company

Energy Transfer Retail Power, LLC, a Delaware limited liability company

Energy Transfer Technologies, Ltd., a Texas limited partnership

Energy Transfer Terminalling Company, LLC, a Delaware limited liability company

ET Company I, Ltd., a Texas limited partnership

ET Crude Oil Terminals, LLC, a Delaware limited partnership

ET Fuel Pipeline, L.P., a Delaware limited partnership

ET Rover Pipeline Canada, ULC, a BC, Canada unlimited liability company

ET Rover Pipeline LLC, a Delaware limited liability company

ETC Bayou Bridge Holdings, LLC, a Delaware limited liability company

ETC Compression, LLC, a Delaware limited liability company

ETC Endure Energy L.L.C., a Delaware limited liability company

ETC Energy Transfer, LLC, a Delaware limited liability company

ETC Fayetteville Express Pipeline, LLC, a Delaware limited liability company

ETC Fayetteville Operating Company, LLC, a Delaware limited liability company

ETC Field Services LLC, a Delaware limited liability company

ETC Gas Company, Ltd., a Texas limited partnership

ETC Gathering, LLC, a Texas limited liability company

ETC Hydrocarbons, LLC, a Texas limited liability company

ETC Illinois LLC, a Delaware limited liability company

ETC Intrastate Procurement Company, LLC, a Delaware limited liability company

ETC Interstate Procurement Company, LLC, a Delaware limited liability company

ETC Katy Pipeline, Ltd., a Texas limited partnership

ETC M-A Acquisition LLC, a Delaware limited liability company

ETC Marketing, Ltd., a Texas limited partnership

ETC Midcontinent Express Pipeline, L.L.C., a Delaware limited liability company

ETC New Mexico Pipeline, L. P., a New Mexico limited partnership

ETC NGL Marketing, LLC, a Texas limited liability company

ETC NGL Transport, LLC, a Texas limited liability company

ETC North Dakota Terminalling, LLC, a Delaware limited liability company

ETC Northeast Development, LLC, a West Virginia limited liability company

ETC Northeast Field Services LLC, a Delaware limited liability company

ETC Northeast Holdings, LLC, a Delaware limited liability company

ETC Northeast Midstream, LLC, a Delaware limited liability company

ETC Northeast Pipeline, LLC, a Delaware limited liability company

ETC Oasis GP, LLC a Texas limited liability company

ETC Oasis, L.P., a Delaware limited partnership

ETC Texas Pipeline, Ltd., a Texas limited partnership

ETC Tiger Pipeline, LLC, a Delaware limited liability company

ETC Tilden System LLC, a Delaware limited liability company

ETC Water Solutions, LLC, a Delaware limited liability company

ETCO Holdings LLC, a Delaware limited liability company

ETP Crude LLC, a Texas limited liability company

ETP Holdco Corporation, a Delaware corporation

ETP Retail Holdings, LLC, a Delaware limited liability company

Evergreen Assurance, LLC, a Delaware limited liability company

Evergreen Capital Holdings, LLC, a Delaware limited liability company

Evergreen Resources Group, LLC, a Delaware limited liability company

Explorer Pipeline Company, a Delaware corporation

Fayetteville Express Pipeline, LLC, a Delaware limited liability company

FEP Arkansas Pipeline, LLC, an Arkansas limited liability company

Fieldcrest Resources LLC, a Delaware limited liability company

Five Dawaco, LLC, a Texas limited liability company

Florida Gas Transmission Company, LLC, a Delaware limited liability company

FLST LLC, a Delaware limited liability company

FrontStreet Hugoton LLC, a Delaware limited liability company

Galveston Bay Gathering, LLC, a Texas limited liability company

Gulf States Transmission LLC, a Louisiana limited liability company

Helios Assurance Company, a Bermuda limited company

Heritage ETC GP, L.L.C., a Delaware limited liability company

Heritage ETC, L.P., a Delaware limited partnership

Heritage Holdings, Inc., a Delaware corporation

Houston Pipe Line Company LP, a Delaware limited partnership

HP Houston Holdings, L.P., a Delaware limited partnership

HPL Asset Holdings LP, a Delaware limited partnership

HPL Consolidation LP, a Delaware limited partnership

HPL GP, LLC, a Delaware limited liability company

HPL Holdings GP, L.L.C., a Delaware limited liability company

HPL Houston Pipe Line Company, LLC, a Delaware limited liability company

HPL Leaseco LP, a Delaware limited partnership

HPL Resources Company LP, a Delaware limited partnership

HPL Storage GP LLC, a Delaware limited liability company

Inland Corporation, an Ohio corporation

Jalisco Corporation, a California corporation

Japan Sun Oil Company, Ltd., a Japanese corporation

K Rail LLC, a Delaware limited liability company

Kanawha Rail LLC, a Delaware limited liability company

LA GP, LLC, a Texas limited liability company

La Grange Acquisition, L.P., a Texas limited partnership

LaGrange-ETCOP Operating Company, LLC, a Delaware limited liability company

Lake Charles Exports, LLC, a Delaware limited liability company

Lake Charles LNG Export Company, LLC, a Delaware limited liability company

Lavan Petroleum Company (LAPCO), an Iran, Islamic Republic corporation

Lee 8 Storage Partnership, a Delaware limited partnership

Lesley Company LLC, a Delaware limited liability company

LG PL, LLC, a Texas limited liability company

LGM, LLC, a Texas limited liability company

Liberty Pipeline Group, LLC, a Delaware limited liability company

Libre Insurance Company, Ltd., a Bermuda corporation

LJL, LLC, a West Virginia limited liability company

Loadout LLC, a Delaware limited liability company

Lobo Pipeline Company LLC, a Delaware limited liability company

Lone Star NGL Asset GP LLC, a Delaware limited liability company

Lone Star NGL Asset Holdings II LLC, a Delaware limited liability company

Lone Star NGL Asset Holdings LLC, a Delaware limited liability company

Lone Star NGL Development LP, a Delaware limited partnership

Lone Star NGL Fractionators LLC, a Delaware limited liability company

Lone Star NGL Hattiesburg LLC, a Delaware limited liability company

Lone Star NGL LLC, a Delaware limited liability company

Lone Star NGL Marketing LLC, a Delaware limited liability company

Lone Star NGL Mont Belvieu GP LLC, a Delaware limited liability company

Lone Star NGL Mont Belvieu Pipelines LLC, a Delaware limited liability company

Lone Star NGL Mont Belvieu LP, a Delaware limited partnership

Lone Star NGL Pipeline LP, a Delaware limited partnership

Lone Star NGL Product Services LLC, a Delaware limited liability company

Lone Star NGL Refinery Services LLC, a Delaware limited liability company

Lone Star NGL Sea Robin LLC, a Delaware limited liability company

Lugrasa, S.A., a Panama corporation

Mascot, Inc. (MA), a Massachusetts corporation

Materials Handling Solutions LLC, a Delaware limited liability company

Mi Vida JV LLC, a Delaware limited liability company

Midcontinent Express Pipeline LLC, a Delaware limited liability company

Mid-Continent Pipe Line (Out) LLC, a Texas limited liability company

Midstream Gas Services, LLC, a Texas limited liability company

Midstream Logistics LLC, a Delaware limited liability company

Mid-Valley Pipeline Company, an Ohio corporation

Midwest Connector Capital Company LLC, a Delaware limited liability company

Oasis Partner Company, a Delaware corporation

Oasis Pipe Line Company Texas L.P., a Texas limited partnership

Oasis Pipe Line Company, a Delaware corporation

Oasis Pipe Line Finance Company, a Delaware corporation

Oasis Pipe Line Management Company, a Delaware corporation

Oasis Pipeline, LP, a Texas limited partnership

Ohio River System LLC, a Delaware limited liability company

Oil Casualty Insurance, Ltd., a Bermuda Limited Company

Oil Insurance Limited, Bermuda limited company

Orbit Gulf Coast NGL Exports, LLC, a Delaware limited liability company

Pacific Ethanol Central, LLC, a Delaware limited liability company

Pan Gas Storage LLC , a Delaware limited liability company

Panhandle Eastern Pipe Line Company, LP, a Delaware limited partnership

Panhandle Energy LNG Services, LLC, a Delaware limited liability company

Panhandle Storage LLC, a Delaware limited liability company

PEI Power Corporation, a Pennsylvania corporation

PEI Power II, LLC, a Pennsylvania corporation

Pelico Pipeline, LLC, a Delaware limited liability company

Penn Virginia Operating Co., LLC, a Delaware limited liability company

PennTex Midstream GP, LLC, a Delaware limited liability company

PennTex Midstream Operating, LLC, a Delaware limited liability company

PennTex Midstream Partners, LLC, a Delaware limited liability company

PennTex Midstream Partners, LP, a Delaware limited partnership

PennTex NLA Holdings, LLC, a Delaware limited liability company

PennTex North Louisiana Operating 3, LLC, a Delaware limited liability company

PennTex North Louisiana, LLC, a Delaware limited liability company

Permian Express Partners LLC, a Delaware limited liability company

Permian Express Partners Operating LLC, a Texas limited liability company

Permian Express Terminal LLC, a Delaware limited liability company

PES Equity Holdings, LLC, a Delaware limited liability company

PES Holdings, LLC, a Delaware limited liability company

PG Energy, Inc., a Pennsylvania corporation

Philadelphia Energy Solutions LLC, a Delaware limited liability company

Philadelphia Energy Solutions Refining and Marketing LLC, a Delaware limited liability company

Price River Terminal, LLC, a Texas limited liability company

Puerto Rico Sun Oil Company LLC, a Delaware limited liability company

PVR Midstream JV Holdings LLC, a Delaware limited liability company

Ranch Westex JV LLC, a Delaware limited liability company

Red Bluff Express Pipeline, LLC, a Delaware limited liability company

Regency Crude Marketing LLC, a Delaware limited liability company

Regency Employees Management Holdings LLC, a Delaware limited liability company

Regency Energy Finance Corp., a Delaware corporation

Regency Energy Partners LP, a Delaware limited partnership

Regency ERCP LLC, a Delaware limited liability company

Regency Gas Services LP, a Delaware limited partnership

Regency GOM LLC, a Texas limited liability company

Regency GP LLC, a Delaware limited liability company

Regency GP LP, a Delaware limited partnership

Regency Haynesville Intrastate Gas LLC, a Delaware limited liability company

Regency Hydrocarbons LLC, an Oklahoma limited liability company

Regency Intrastate Gas LP, a Delaware limited partnership

Regency Laverne LLC, an Oklahoma limited liability company

Regency Liquids Pipeline LLC, a Delaware limited liability company

Regency Marcellus Gas Gathering LLC, a Delaware limited liability company

Regency Mi Vida LLC, a Delaware limited liability company

Regency NEPA Gas Gathering LLC, a Texas limited liability company

Regency OLP GP LLC, a Delaware limited liability company

Regency Pipeline LLC, a Delaware limited liability company

Regency Quitman Gathering LLC, a Delaware limited liability company

Regency Ranch JV LLC, a Delaware limited liability company

Regency Texas Pipeline LLC, a Delaware limited liability company

Regency Utica Gas Gathering LLC, a Delaware limited liability company

Regency Utica Holdco LLC, a Delaware limited liability company

Regency Vaughn Gathering LLC, a Texas limited liability company

RGP Marketing LLC, a Texas limited liability company

RGP Westex Gathering Inc., a Texas corporation

RIGS GP LLC, a Delaware limited liability company

RIGS Haynesville Partnership Co., a Delaware partnership

Rover Pipeline LLC, a Delaware limited liability company

RSS Water Services LLC, a Delaware limited liability company

Sea Robin Pipeline Company, LLC , a Delaware limited liability company

SEC Energy Products & Services, L.P., a Texas limited partnership

SEC Energy Realty GP, LLC, a Texas limited liability company

SEC General Holdings, LLC, a Texas limited liability company

SEC-EP Realty Ltd., a Texas limited partnership

Southern Union Gas Company, Inc., a Texas corporation

Southern Union Panhandle LLC, a Delaware limited liability company

SU Gas Services Operating Company, Inc., a Delaware corporation

SU Holding Company, Inc., a Delaware corporation

SUG Holding Company, LLC, a Delaware limited liability company

Sun Alternate Energy Corporation, a Delaware corporation

Sun Atlantic Refining and Marketing B.V., a Netherlands other

Sun Atlantic Refining and Marketing B.V., LLC, a Delaware limited liability company

Sun Atlantic Refining and Marketing Company, LLC, a Delaware limited liability company

Sun Canada, Inc., a Delaware corporation

Sun Company, Inc., a Delaware corporation

Sun Company, Inc., a Pennsylvania corporation

Sun International Limited, a Bermuda corporation

Sun Lubricants and Specialty Products Inc., a Quebec corporation

Sun Mexico One, Inc., a Delaware corporation

Sun Mexico Two, Inc., a Delaware corporation

Sun Oil Company, a Delaware corporation

Sun Oil Export Company, a Delaware corporation

Sun Oil International, Inc., a Delaware corporation

Sun Petrochemicals LLC, a Delaware corporation

Sun Pipe Line Company of Delaware LLC, a Delaware limited liability company

Sun Pipe Line Company, LLC, a Texas limited liability company

Sun Pipe Line Delaware (Out) LLC, a Delaware limited liability company

Sun Refining and Marketing Company, a Delaware corporation

Sun Services Corporation, a Pennsylvania corporation

Sun Transport, LLC, a Pennsylvania limited liability company

Suncrest Resources LLC, a Delaware limited liability company

Sun-Del Pipeline LLC, a Delaware limited liability company

Sun-Del Services, Inc., a Delaware corporation

Sunoco (R&M), LLC, a Pennsylvania limited liability company

Sunoco de Mexico, S.A. de C.V., a Mexico Corporation

Sunoco Logistics Partners GP LLC, a Delaware limited liability company

Sunoco Logistics Partners Operations GP LLC, a Delaware limited liability company

Sunoco Logistics Partners Operations L.P., a Delaware limited partnership

Sunoco Midland Gathering LLC, a Texas limited liability company

Sunoco Midland Terminal LLC, a Texas limited liability company

Sunoco Overseas, Inc., a Delaware corporation

Sunoco Partners Marketing & Terminals L.P., a Texas limited partnership

Sunoco Partners NGL Facilities LLC, a Delaware limited liability company

Sunoco Partners Operating LLC, a Delaware limited liability company

Sunoco Partners Real Estate Acquisition LLC, a Delaware limited liability company

Sunoco Partners Rockies LLC, a Delaware limited liability company

Sunoco Pipeline Acquisition LLC, a Delaware limited liability company

Sunoco Pipeline L.P., a Texas limited partnership

Sunoco Power Marketing L.L.C., a Pennsylvania limited liability company

Sunoco Receivables Corporation, Inc., a Delaware corporation

Sunoco, Inc., a Pennsylvania corporation

Sweeney Gathering, L.P., a Texas limited liability company

SXL Acquisition Sub LLC, a Delaware limited liability company

TETC, LLC, a Texas limited liability company

Texas Energy Transfer Company, Ltd., a Texas limited partnership

Texas Energy Transfer Power, LLC, a Texas limited liability company

The New Claymont Investment Company, a Delaware corporation

The Energy Transfer/Sunoco Foundation, a Pennsylvania non-profit corporation

Toney Fork LLC, a Delaware limited liability company

Trade Star, LLC, a Idaho limited liability company

Trade Star Holdings, LLC, a Delaware limited liability company

Trade Star Leasing LLC, a Idaho limited liability company

Trade Star Properties LLC, a Idaho limited liability company

Trade Star Willston, LLC, a Idaho limited liability company

Trans-Pecos Pipeline, LLC, a Texas limited liability company

Transwestern Pipeline Company, LLC, a Delaware limited liability company

Trunkline Field Services LLC, a Delaware limited liability company

Trunkline Gas Company, LLC, a Delaware limited liability company

Trunkline LNG Holdings LLC, a Delaware limited liability company

Venezoil, C.A., a Venezuela other

Vista Mar Pipeline, LLC, a Texas limited liability company

Waha Express Pipeline, LLC, a Delaware limited liability company

West Shore Pipe Line Company, a Delaware corporation

West Texas Gathering Company, a Delaware corporation

West Texas Gulf Pipe Line Company, a Delaware corporation

Westex Energy LLC, a Delaware limited liability company

WGP-KHC, LLC, a Delaware limited liability company

Whiskey Bay Gathering Company, LLC, a Delaware limited liability company

Wolverine Pipe Line Company, a Delaware corporation

Yellowstone Pipe Line Company, a Delaware corporation

SUBSIDIARIES OF SUNOCO LP, a Delaware limited partnership:

Allied Energy Company LLC, an Alabama limited liability company

Aloha Petroleum LLC, a Delaware limited liability company

Aloha Petroleum, Ltd., a Hawaii Corporation

Applied Petroleum Technologies, Ltd., a Texas limited partnership

APT Management Company, LLC, a Texas limited liability company

C&G Investments, LLC, a Delaware limited liability company

Corpus Christie Reimco, LLC, a Texas limited liability company

Direct Fuels LLC, a Delaware limited liability company

GoPetro Transport LLC, a Texas limited liability company

MACS Retail LLC, a Virginia limited liability company

Mid-Atlantic Convenience Stores, LLC, a Delaware limited liability company

Quick Stuff of Texas, Inc., a Texas Corporation

SCL GP Interests LLC, a Delaware limited liability company

SSP BevCo I LLC, a Texas limited liability company

SSP BevCo II LLC, a Texas limited liability company

SSP Beverage, LLC, a Texas limited liability company

Stripes Acquisition LLC, a Texas limited liability company

Stripes Holdings LLC, a Delaware limited liability company

Stripes LLC, a Texas limited liability company

Stripes No. 1009 LLC, a Texas limited liability company

Sunmarks, LLC, a Delaware limited liability company

Sunoco Finance Corp., a Delaware corporation

Sunoco Retail LLC, a Pennsylvania limited liability company

Sunoco, LLC, a Delaware limited liability company

Susser Company, Ltd., a Texas limited partnership

Susser Finance Corporation, a Delaware corporation

Susser Financial Services LLC, a Delaware limited liability company

Susser Holdings Corporation, a Delaware corporation

Susser Holdings, L.L.C., a Delaware limited liability company

Susser Petroleum Company LLC, a Texas limited liability company

Susser Petroleum Property Company LLC, a Delaware limited liability company

TCFS Holdings, Inc. a Texas corporation

TND Beverage, LLC, a Texas limited liability company

Town & Country Food Stores, Inc., a Texas corporation

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our reports dated February 23, 2018, with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of Energy Transfer Equity, L.P. on Form 10-K for the year ended December 31, 2017. We consent to the incorporation by reference of said reports in the Registration Statements of Energy Transfer Equity, L.P. on Forms S-3 (File No. 333-216451, File No. 333-215969, File No. 333-215893, and File No. 333-146300) and on Form S-8 (File No. 333-146298).

/s/ GRANT THORNTON LLP

Dallas, Texas

February 23, 2018

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated February 23, 2018, with respect to the consolidated financial statements of Energy Transfer Partners, L.P. included in the Annual Report of Energy Transfer Equity, L.P. on Form 10-K for the year ended December 31, 2017. We consent to the incorporation by reference of said report in the Registration Statements of Energy Transfer Equity, L.P. on Forms S-3 (File No. 333-216451, File No. 333-215969, File No. 333-215893, and File No. 333-146300) and on Form S-8 (File No. 333-146298).

/s/ GRANT THORNTON LLP

Dallas, Texas

February 23, 2018

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRESIDENT (PRINCIPAL EXECUTIVE OFFICER)

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John W. McReynolds, certify that:

1. I have reviewed this annual report on Form 10-K of Energy Transfer Equity, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize, and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 23, 2018

/s/ John W. McReynolds

John W. McReynolds

President

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Thomas E. Long, certify that:

1. I have reviewed this annual report on Form 10-K of Energy Transfer Equity, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize, and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 23, 2018

/s/ Thomas E. Long

Thomas E. Long

Group Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John W. McReynolds, President, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: February 23, 2018

/s/ John W. McReynolds

John W. McReynolds

President

A signed original of this written statement required by Section 906 has been provided to and will be retained by Energy Transfer Equity, L.P. and furnished to the Securities and Exchange Commission upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Long, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: February 23, 2018

/s/ Thomas E. Long

Thomas E. Long

Group Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to and will be retained by Energy Transfer Equity, L.P. and furnished to the Securities and Exchange Commission upon request.

XML

Document and Entity Information Document - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Feb. 16, 2018	Jun. 30, 2017
Entity Information [Line Items]
Entity Registrant Name	Energy Transfer Equity, L.P.
Entity Central Index Key	0001276187
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		1,079,145,561
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 14,110

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	[1]
ASSETS
Cash and cash equivalents	$ 336	$ 467
Accounts receivable, net	4,504	3,557
Accounts receivable from related companies	53	47
Inventories	2,022	2,055
Income taxes receivable	136	128
Derivative assets	24	21
Other current assets	295	447
Current assets held for sale	3,313	177
Total current assets	10,683	6,899
Property, plant and equipment	71,177	61,562
Accumulated depreciation and depletion	(10,089)	(7,984)
Property, Plant and Equipment, Net	61,088	53,578
Advances to and investments in unconsolidated affiliates	2,705	3,040
Other non-current assets, net	886	815
Intangible assets, net	6,116	5,512
Goodwill	4,768	5,670
Non-current assets held for sale	0	3,411
Total assets	86,246	78,925
LIABILITIES AND EQUITY
Accounts payable	4,685	3,502
Accounts payable to related companies	31	42
Derivative liabilities	111	172
Accrued and other current liabilities	2,582	2,367
Current maturities of long-term debt	413	1,194
Current liabilities held for sale	75	0
Total current liabilities	7,897	7,277
Long-term debt, less current maturities	43,671	42,608
Long-term notes payable - related company	0	250
Deferred income taxes	3,315	5,112
Non-current derivative liabilities	145	76
Other non-current liabilities	1,217	1,075
Liabilities associated with assets held for sale	0	48
Commitments and contingencies
Redeemable noncontrolling interests	21	15
PREFERRED UNITS OF SUBSIDIARY (Note 7)	0	33
Partners' Capital
General Partner	(3)	(3)
Limited Partners:
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)	(1,643)	(1,871)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)	450	180
Total partners’ deficit	(1,196)	(1,694)
Noncontrolling interest	31,176	24,125
Total equity	29,980	22,431
Total liabilities and equity	$ 86,246	$ 78,925

[1] * As adjusted. See Note 2.

XML

Consolidated Balance Sheets Balance Sheet (Paranthetical) - shares	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Authorized	1,079,145,561	1,046,947,157
Issued	1,079,145,561	1,046,947,157
Outstanding	1,079,145,561	1,046,947,157	1,044,800,000	1,077,500,000
Preferred Units, Authorized	329,299,267	329,299,267
Preferred Units, Issued	329,299,267	329,299,267
Preferred Units, Outstanding	329,299,267	329,299,267
Class D Units [Member]
Class of Stock [Line Items]
Outstanding					3,080,000

XML

Consolidated Statements Of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	[1]	Dec. 31, 2015	[1]
REVENUES:
Natural gas sales	$ 4,172	$ 3,619		$ 3,671
NGL sales	6,972	4,841		3,935
Crude sales	10,184	6,766		8,378
Gathering, transportation and other fees	4,435	4,172		4,200
Refined product sales	11,975	10,097		11,321
Other	2,785	2,297		4,591
Total revenues	40,523	31,792	[2]	36,096
COSTS AND EXPENSES:
Cost of products sold	30,966	23,693		28,668
Operating expenses	2,644	2,307		2,303
Depreciation, depletion and amortization	2,554	2,216		1,951
Selling, general and administrative	607	693		548
Impairment losses	1,039	1,040		339
Total costs and expenses	37,810	29,949		33,809
OPERATING INCOME	2,713	1,843	[2]	2,287
OTHER INCOME (EXPENSE):
Interest expense, net	(1,922)	(1,804)		(1,622)
Equity in earnings from unconsolidated affiliates	144	270		276
Impairment of investments in unconsolidated affiliates	(313)	(308)		0
Gains on acquisitions	0	83		0
Losses on extinguishments of debt	(89)	0		(43)
Losses on interest rate derivatives	(37)	(12)		(18)
Other, net	214	132		20
Income from continuing operations before income tax benefit	710	204		900
Income tax benefit from continuing operations	(1,833)	(258)		(123)
INCOME FROM CONTINUING OPERATIONS	2,543	462		1,023
Income (loss) from discontinued operations, net of income taxes	(177)	(462)		38
NET INCOME	2,366	0	[2]	1,061
Less: Net income (loss) attributable to noncontrolling interest	1,412	(995)		(128)
NET INCOME ATTRIBUTABLE TO PARTNERS	954	995		1,189
General Partner’s interest in net income	2	3		3
Convertible Unitholders’ interest in net income	37	9		0
Class D Unitholder’s interest in net income	0	0		3
Limited Partners’ interest in net income	$ 915	$ 983	[2]	$ 1,183
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT (USD $ per unit):
Basic	$ 0.86	$ 0.95		$ 1.11
Diluted	0.84	0.93		1.11
NET INCOME PER LIMITED PARTNER UNIT (USD $ per Unit):
Basic	0.85	0.94	[2]	1.11
Diluted	$ 0.83	$ 0.92	[2]	$ 1.11

[1] * As adjusted. See Note 2.

[2] * As adjusted. See Note 2 and Note 3.

XML

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Net income	$ 2,366	$ 0	[1],[2]	$ 1,061	[2]
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	6	2		(3)
Actuarial gain (loss) relating to pension and other postretirement benefits	(12)	(1)		65
Foreign currency translation adjustment	0	(1)		(1)
Change in other comprehensive income (loss) from unconsolidated affiliates	1	4		(1)
Other comprehensive income (loss), net of tax, total	(5)	4		60
Comprehensive income	2,361	4		1,121
Less: Comprehensive income (loss) attributable to noncontrolling interest	1,407	(991)		(68)
Comprehensive income attributable to partners	$ 954	$ 995		$ 1,189

[1] * As adjusted. See Note 2 and Note 3.

[2] * As adjusted. See Note 2.

XML

Consolidated Statement Of Equity - USD ($) $ in Millions		Total		General Partner [Member]	Limited Partner [Member]	Class D Units [Member]	Series A Convertible Preferred Units [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]	PennTex Acquisition [Member]	PennTex Acquisition [Member] General Partner [Member]	PennTex Acquisition [Member] Limited Partner [Member]	PennTex Acquisition [Member] Class D Units [Member]	PennTex Acquisition [Member] Series A Convertible Preferred Units [Member]	PennTex Acquisition [Member] Accumulated Other Comprehensive Income (Loss) [Member]	PennTex Acquisition [Member] Noncontrolling Interest [Member]	Sale of Bakken Pipeline interest [Member]	Sale of Bakken Pipeline interest [Member] General Partner [Member]	Sale of Bakken Pipeline interest [Member] Limited Partner [Member]	Sale of Bakken Pipeline interest [Member] Class D Units [Member]	Sale of Bakken Pipeline interest [Member] Series A Convertible Preferred Units [Member]	Sale of Bakken Pipeline interest [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Sale of Bakken Pipeline interest [Member] Noncontrolling Interest [Member]	Sale of Rover Pipeline interest [Member]	Sale of Rover Pipeline interest [Member] General Partner [Member]	Sale of Rover Pipeline interest [Member] Limited Partner [Member]	Sale of Rover Pipeline interest [Member] Class D Units [Member]	Sale of Rover Pipeline interest [Member] Series A Convertible Preferred Units [Member]	Sale of Rover Pipeline interest [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Sale of Rover Pipeline interest [Member] Noncontrolling Interest [Member]	Subsidiary units issued for cash [Member]	Subsidiary units issued for cash [Member] General Partner [Member]	Subsidiary units issued for cash [Member] Limited Partner [Member]	Subsidiary units issued for cash [Member] Class D Units [Member]	Subsidiary units issued for cash [Member] Series A Convertible Preferred Units [Member]	Subsidiary units issued for cash [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Subsidiary units issued for cash [Member] Noncontrolling Interest [Member]	Subsidiary units issued in certain acquisitions [Member]	Subsidiary units issued in certain acquisitions [Member] General Partner [Member]	Subsidiary units issued in certain acquisitions [Member] Limited Partner [Member]	Subsidiary units issued in certain acquisitions [Member] Class D Units [Member]	Subsidiary units issued in certain acquisitions [Member] Series A Convertible Preferred Units [Member]	Subsidiary units issued in certain acquisitions [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Subsidiary units issued in certain acquisitions [Member] Noncontrolling Interest [Member]
Balance at Dec. 31, 2014	[1]	$ 22,301		$ (1)	$ 648	$ 22	$ 0	$ (5)	$ 21,637
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners		(1,090)		(3)	(1,084)	(3)	0	0	0
Distributions to noncontrolling interest		(2,335)		0	0	0	0	0	(2,335)
Subsidiary unit transactions		3,889		1	(524)	(1)	0	0	4,415
Capital contributions received from noncontrolling interest		875		0	0	0	0	0	875
Non-cash compensation expense, net of units tendered by employees for tax withholdings		70		0	0	8	0	0	62
Other, net		(149)		0	(118)	0	0	0	(31)
Units repurchased under buyback program		(1,064)		0	(1,064)	0	0	0	0
Issuance of common units		0		0	7	(7)	0	0	0
Acquisition and disposition of noncontrolling interest		(65)		0	0	0	0	0	(65)
Partners' Capital Account, Acquisitions										$ 0
Other comprehensive income, net of tax		60		0	0	0	0	5	55
Net income		1,061	[1]	3	1,183	3	0	0	(128)
Balance at Dec. 31, 2015	[1]	23,553		(2)	(952)	22	0	0	24,485
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners		(1,022)		(3)	(1,019)	0	0	0	0
Distributions to noncontrolling interest		(2,795)		0	0	0	0	0	(2,795)
Distributions reinvested		0		0	(173)	0	173	0	0
Subsidiary unit transactions																															$ 2,559	$ 0	$ 0	$ 0	$ 0	$ 0	$ 2,559	$ 307	$ 0	$ 0	$ 0	$ 0	$ 0	$ 307
Capital contributions received from noncontrolling interest		236		0	0	0	0	0	236
Non-cash compensation expense, net of units tendered by employees for tax withholdings		52		0	0	(22)	0	0	74
Other, net		43		(1)	30	0	0	0	14
Issuance of common units		37		0	39		(2)	0	0
Acquisition and disposition of noncontrolling interest		(779)		0	(779)	0	0	0	0
Partners' Capital Account, Acquisitions		(236)		0	0	0	0	0	236	(307)
Other comprehensive income, net of tax		4		0	0	0	0	0	4
Net income		0	[1],[2]	3	983	0	9	0	(995)
Balance at Dec. 31, 2016	[1]	22,431		(3)	(1,871)	0	180	0	24,125
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners		(1,010)		(2)	(1,008)	0	0	0	0
Distributions to noncontrolling interest		(2,999)		0	0	0	0	0	(2,999)
Distributions reinvested		0		0	234	0	(234)	0	0
Partners' Capital Account, Sale of Units		568		0	568	0	0	0	0
Subsidiary unit transactions		3,235		0	(55)	0	(1)	0	3,291
Capital contributions received from noncontrolling interest		2,202		0	0	0	0	0	2,202
Non-cash compensation expense, net of units tendered by employees for tax withholdings		86		0	0	0	0	0	86
Other, net		(92)		0	0	0	0	0	(92)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests										$ (280)	$ 0	$ (2)	$ 0	$ 0	$ 0	$ (278)
Acquisition and disposition of noncontrolling interest																	$ (2,000)	$ 0	$ (42)	$ 0	$ 0	$ 0	$ (1,958)	$ (1,478)	$ 0	$ (2)	$ 0	$ 0	$ 0	$ (1,476)
Partners' Capital Account, Acquisitions												$ 0
Other comprehensive income, net of tax		(5)		0	0	0	0	0	(5)
Net income		2,366		2	915	0	37	0	1,412
Balance at Dec. 31, 2017		$ 29,980		$ (3)	$ (1,643)	$ 0	$ 450	$ 0	$ 31,176

[1] * As adjusted. See Note 2.

[2] * As adjusted. See Note 2 and Note 3.

XML

Consolidated Statements Of Cash Flows - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$ 2,366	$ 0	[1],[2]	$ 1,061	[2]
Reconciliation of net income to net cash provided by operating activities:
Income (loss) from discontinued operations, net of income taxes		177	462	[2]	(38)	[2]
Depreciation, depletion and amortization		2,554	2,216	[2]	1,951	[2]
Deferred income taxes		(1,871)	(177)	[2]	239	[2]
Amortization included in interest expense		24	3	[2]	(21)	[2]
Unit-based compensation expense		99	70	[2]	91	[2]
Impairment losses		1,039	1,040	[2]	339	[2]
Gains on acquisitions		0	(83)	[2]	0	[2]
Losses on extinguishments of debt		89	0	[2]	43	[2]
Impairment of investments in unconsolidated affiliates		313	308	[2]	0	[2]
Losses on disposal of assets		0	0	[2]	(6)	[2]
Equity in earnings of unconsolidated affiliates		(144)	(270)	[2]	(276)	[2]
Distributions from unconsolidated affiliates		297	268	[2]	409	[2]
Inventory valuation adjustments		(24)	(97)	[2]	67	[2]
Other non-cash		(298)	(239)	[2]	(8)	[2]
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations		(192)	(179)	[2]	(872)	[2]
Net cash provided by operating activities		4,429	3,322	[2]	2,979	[2]
INVESTING ACTIVITIES:
Proceeds from sale of noncontrolling interest		0	0	[2]	64	[2]
Cash paid for acquisitions, net of cash received		(303)	(1,398)	[2]	(777)	[2]
Cash paid for acquisition of a noncontrolling interest		0	0	[2]	(129)	[2]
Capital expenditures, excluding allowance for equity funds used during construction		(8,444)	(7,771)	[2]	(9,073)	[2]
Contributions in aid of construction costs		31	71	[2]	80	[2]
Contributions to unconsolidated affiliates		(268)	(68)	[2]	(45)	[2]
Distributions from unconsolidated affiliates in excess of cumulative earnings		135	135	[2]	128	[2]
Proceeds from the sale of other assets		48	35	[2]	14	[2]
Change in restricted cash		0	14	[2]	19	[2]
Other		(3)	0	[2]	(16)	[2]
Net cash used in investing activities		(5,606)	(8,982)	[2]	(9,735)	[2]
FINANCING ACTIVITIES:
Proceeds from borrowings		31,608	25,785	[2]	26,455	[2]
Repayments of long-term debt		(31,268)	(19,076)	[2]	(19,828)	[2]
Cash received from affiliate notes		0	5,317	[2]	0	[2]
Cash paid on affiliate notes		(255)	(5,051)	[2]	0	[2]
Proceeds from Issuance of Common Limited Partners Units		568	0	[2]	0	[2]
Subsidiary units issued for cash		3,235	2,559	[2]	3,889	[2]
Distributions to partners		(1,010)	(1,022)	[2]	(1,090)	[2]
Distributions to noncontrolling interests		(2,961)	(2,766)	[2]	(2,335)	[2]
Debt issuance costs		(131)	(52)	[2]	(75)	[2]
Capital contributions from noncontrolling interest		(988)	0		(34)
Capital contributions from noncontrolling interest		1,214	236	[2]	841	[2]
Units repurchased under buyback program		0	0	[2]	1,064	[2]
Other, net		6	(3)	[2]	(8)	[2]
Net cash provided by financing activities		953	5,927	[2]	6,785	[2]
Cash Provided by (Used in) Operating Activities, Discontinued Operations		136	93	[2]	90	[2]
Cash Provided by (Used in) Investing Activities, Discontinued Operations		(38)	(483)	[2]	(360)	[2]
Increase (Decrease) in Assets Held-for-sale		(5)	5	[2]	(13)	[2]
Net increase (decrease) in cash and cash equivalents of discontinued operations		93	(385)	[2]	(283)	[2]
Decrease in cash and cash equivalents		(131)	(118)	[2]	(254)	[2]
Cash and cash equivalents, beginning of period	[2]	467	585		839
Cash and cash equivalents, end of period		336	467	[2]	585	[2]
Bakken Pipeline [Member]
INVESTING ACTIVITIES:
Proceeds from Divestiture of Interest in Joint Venture		2,000	0	[2]	0	[2]
Rover Pipeline LLC [Member]
INVESTING ACTIVITIES:
Proceeds from Divestiture of Interest in Joint Venture		1,478	0	[2]	0	[2]
PennTex [Member]
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received		280	0	[2]	0	[2]
ETP Series A Preferred Units [Member]
FINANCING ACTIVITIES:
Units repurchased under buyback program		$ (53)	$ 0	[2]	$ 0	[2]

[1] * As adjusted. See Note 2 and Note 3.

[2] * As adjusted. See Note 2.

XML

Operations And Organization

12 Months Ended

Dec. 31, 2017

Operations And Organization [Abstract]

Operations And Organization

OPERATIONS AND ORGANIZATION:

Financial Statement Presentation

The consolidated financial statements of Energy Transfer Equity, L.P. (the “Partnership,” “we” or “ETE”) presented herein for the years ended December 31, 2017, 2016, and 2015, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle, Sunoco LP and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

The consolidated financial statements of ETE presented herein include the results of operations of:

• the Parent Company;

• our controlled subsidiaries, ETP and Sunoco LP;

• consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDR interests in ETP and Sunoco LP; and

• our wholly-owned subsidiary, Lake Charles LNG.

Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

At January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.

As discussed in Note 8, in July 2015, the Partnership completed a two-for-one split of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effects of the unit split for all periods presented.

In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled.

In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. For purposes of maintaining clarity, the following references are used herein:

• References to “ETLP” refer to the entity named Energy Transfer, LP subsequent to the close of the merger;

• References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and

• References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.

The historical common units for ETP 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 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. Additionally, for prior periods herein, certain balances have been reclassified to assets and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity.

Business Operations

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our financial statements reflect the following reportable business segments:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the following:

• activities of the Parent Company; and

• the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

ETP is a publicly traded partnership whose operations comprise the following:

• the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales;

• intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia;

• interstate pipelines that are owned and operated, either directly or through equity method investments, that transport natural gas to various markets in the United States; and

• controlling interest in 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.

Sunoco LP is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites.

Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.

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Estimates, Significant Accounting Policies and Balance Sheet Detail

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Estimates, Significant Accounting Policies and Balance Sheet Detail

ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Change in Accounting Policy

During the fourth quarter of 2017, ETP 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 product and NGL associated with the legacy Sunoco Logistics business. ETP’s management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

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

	Year Ended December 31, 2016									Year Ended December 31, 2015
	As Originally Reported*			Effect of Change			As Adjusted			As Originally Reported*			Effect of Change			As Adjusted
Consolidated Statement of Operations and Comprehensive Income:
Cost of products sold	$	23,652		$	41		$	23,693		$	28,636		$	32		$	28,668
Operating income	1,884			(41		)	1,843			2,319			(32		)	2,287
Income from continuing operations before income tax benefit	245			(41		)	204			932			(32		)	900
Net income	41			(41		)	—			1,093			(32		)	1,061
Net income (loss) attributable to noncontrolling interest	(954		)	(41		)	(995		)	(96		)	(32		)	(128		)
Comprehensive income	45			(41		)	4			1,153			(32		)	1,121
Consolidated Statements of Cash Flows:
Net income	41			(41		)	—			1,093			(32		)	1,061
Inventory valuation adjustments	(267		)	170			(97		)	229			(162		)	67
Net change in operating assets and liabilities (change in inventories)	(50		)	(129		)	(179		)	(1,066		)	194			(872		)
Consolidated Balance Sheets (at period end):
Inventories	2,141			(86		)	2,055			1,498			(45		)	1,453
Noncontrolling interest	24,211			(86		)	24,125			24,530			(45		)	24,485

* Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 3.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Recent Accounting Pronouncements

ASU 2014-09

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. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.

For future periods, ETP expects that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of its midstream agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.

We have determined that the timing and/or amount of revenue that we recognize on certain contracts associated with Sunoco LP’s operations will be impacted by the adoption of the new standard. We currently estimate the cumulative catch-up effect to Sunoco LP’s retained earnings as of January 1, 2018 to be approximately $54 million. These adjustments are primarily related to the change in recognition of dealer incentives and rebates.

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. The Partnership expects to adopt ASU 2016-02 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 2016-16

On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.

ASU 2017-04

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

ASU 2017-12

In August 2017, the FASB issued ASU 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.

Revenue Recognition

Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.

Investment in ETP

Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.

The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.

ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead.

In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which ETP operate, competitive factors in the energy industry, and other issues.

Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and segment margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.

ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.

In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.

ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

Investment in Sunoco LP

Revenues from Sunoco LP’s two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Sunoco LP may sell motor fuel to wholesale customers on a commission agent basis, in which Sunoco LP retains title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. Sunoco LP derives other income from rental income, propane and lubricating oils and other ancillary product and service offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals and other ancillary product and service offerings. Sunoco LP records revenue on a net commission basis when the product is sold and/or services are rendered. Rental income from operating leases is recognized on a straight line basis over the term of the lease.

Investment in Lake Charles LNG

Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal.

Regulatory Accounting – Regulatory Assets and Liabilities

ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of ETP’s regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, ETP ceases to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the NGA and NGPA, it does not currently apply regulatory accounting policies in accounting for its operations.  Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which 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, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:

	Years Ended December 31,
	2017			2016			2015
Accounts receivable	$	(948	)	$	(1,126	)	$	856
Accounts receivable from related companies	24			42			(5		)
Inventories	58			(480		)	(212		)
Other current assets	38			165			(225		)
Other non-current assets, net	84			(148		)	247
Accounts payable	712			1,170			(1,070		)
Accounts payable to related companies	(178		)	(64		)	400
Accrued and other current liabilities	(97		)	89			(697		)
Other non-current liabilities	106			106			(241		)
Derivative assets and liabilities, net	9			67			75
Net change in operating assets and liabilities, net of effects of acquisitions	$	(192	)	$	(179	)	$	(872	)

Non-cash investing and financing activities and supplemental cash flow information were as follows:

	Years Ended December 31,
	2017			2016			2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,060		$	848		$	910
Net gains (losses) from subsidiary common unit transactions	(56		)	16			(526		)
NON-CASH FINANCING ACTIVITIES:
Issuance of Common Units in connection with the PennTex Acquisition	$	—		$	307		$	—
Contribution of assets from noncontrolling interest	988			—			34
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	1,914		$	1,922		$	1,800
Cash paid for (refund of) income taxes	50			(229		)	72

Accounts Receivable

Our subsidiaries assess the credit risk of their customers and take steps to mitigate risk as necessary. Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and identification of specific customers with payment issues.

Inventories

As discussed under “Change in Accounting Policy” in Note 2, ETP changed its accounting policy for certain inventory in the fourth quarter of 2017.

Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Inventories consisted of the following:

	December 31,
	2017		2016
Natural gas, NGLs, and refined products	$	1,120	$	1,141
Crude oil	551		651
Spare parts and other	351		263
Total inventories	$	2,022	$	2,055

ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

Other Current Assets

Other current assets consisted of the following:

	December 31,
	2017		2016
Deposits paid to vendors	$	64	$	74
Prepaid expenses and other	231		373
Total other current assets	$	295	$	447

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.

Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.

In 2017, ETP recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, ETP recorded a $133 million fixed asset impairment related to its interstate transportation and storage operations primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in its midstream operations. In 2015, ETP recorded a $110 million fixed asset impairment related to its NGL and refined products transportation and services operations primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for its reporting units during the periods presented.

Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:

	December 31,
	2017			2016
Land and improvements	$	2,222		$	1,189
Buildings and improvements (1 to 45 years)	2,786			2,247
Pipelines and equipment (5 to 83 years)	44,673			36,570
Natural gas and NGL storage facilities (5 to 46 years)	1,681			1,451
Bulk storage, equipment and facilities (2 to 83 years)	3,883			3,701
Vehicles (1 to 25 years)	126			217
Right of way (20 to 83 years)	3,432			3,349
Natural resources	434			434
Other (1 to 40 years)	1,029			2,285
Construction work-in-process	10,911			10,119
	71,177			61,562
Less – Accumulated depreciation and depletion	(10,089		)	(7,984		)
Property, plant and equipment, net	$	61,088		$	53,578

We recognized the following amounts for the periods presented:

	Years Ended December 31,
	2017		2016		2015
Depreciation and depletion expense	$	2,204	$	1,952	$	1,661
Capitalized interest	286		201		164

Advances to and Investments in Affiliates

Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.

Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:

	December 31,
	2017		2016
Regulatory assets	85		86
Deferred charges	210		217
Restricted funds	192		190
Other	399		322
Total other non-current assets, net	$	886	$	815

Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.

Intangible Assets

Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.

Components and useful lives of intangible assets were as follows:

	December 31, 2017					December 31, 2016
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	6,979	$	(1,277	)	$	6,050	$	(971	)
Trade names (20 years)	66		(25		)	66		(22		)
Patents (10 years)	48		(26		)	48		(21		)
Other (5 to 20 years)	28		(14		)	25		(10		)
Total amortizable intangible assets	7,121		(1,342		)	6,189		(1,024		)
Non-amortizable intangible assets:
Trademarks	295		—			288		—
Other	42		—			59		—
Total intangible assets	$	7,458	$	(1,342	)	$	6,536	$	(1,024	)

Aggregate amortization expense of intangibles assets was as follows:

	Years Ended December 31,
	2017		2016		2015
Reported in depreciation, depletion and amortization	$	344	$	264	$	290

Estimated aggregate amortization expense of intangible assets for the next five years was as follows:

Years Ending December 31:
2018	$	341
2019	338
2020	336
2021	319
2022	287

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

Sunoco LP performed impairment tests on their indefinite-lived intangible assets during the fourth quarter of 2017 and recognized $13 million and $4 million impairment charge on their contractual rights and liquor licenses, included in Other in the table above, primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded.

In 2015, ETP recorded $24 million of intangible asset impairments related to its NGL and retail products transportation and services operations primarily due to an expected decrease in future cash flows.

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

Changes in the carrying amount of goodwill were as follows:

	Investment in ETP			Investment in Sunoco LP			Investment in Lake Charles LNG		Corporate, Other and Eliminations			Total
Balance, December 31, 2015	$	5,428		$	1,694		$	184	$	(1,250	)	$	6,056
Goodwill acquired	428			81			—		—			509
Sunoco LP Exchange	(1,289		)	—			—		1,289			—
Goodwill impairment	(670		)	(227		)	—		—			(897		)
Other	—			2			—		—			2
Balance, December 31, 2016	3,897			1,550			184		39			5,670
Goodwill acquired	12			—			—		—			12
Goodwill impairment	(793		)	(102		)	—		—			(895		)
Other	(1		)	(18		)	—		—			(19		)
Balance, December 31, 2017	$	3,115		$	1,430		$	184	$	39		$	4,768

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.

During the fourth quarter of 2017, ETP recognized goodwill impairments of $262 million in its interstate transportation and storage operations, $79 million in its NGL and refined products transportation and services operations and $452 million in its all other operations primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. Sunoco LP recognized goodwill impairments of $387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.

During the fourth quarter of 2016, ETP recognized goodwill impairments of $638 million in its interstate transportation and storage operations and $32 million in its midstream operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. Sunoco LP recognized goodwill impairments of $641 million, of which $227 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.

During the fourth quarter of 2015, ETP recognized goodwill impairments of $99 million in its interstate transportation and storage operations and $106 million in its NGL and refined products transportation and services operations primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.

The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

Asset Retirement Obligations

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.

Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as ofDecember 31, 2017and2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

As of December 31, 2017 and 2016, other non-current liabilities in ETP’s consolidated balance sheets included AROs of $165 million and $170 million, respectively.

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

Long-lived assets related to AROs aggregated to $2 million and $14 million, and were reflected as property, plant and equipment on our consolidated balance sheets as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.

All amounts recorded in our consolidated balance sheets as of December 31, 2017 and 2016 are attributable to the obligations of ETP.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	December 31,
	2017		2016
Interest payable	$	552	$	545
Customer advances and deposits	59		72
Accrued capital expenditures	1,006		769
Accrued wages and benefits	280		254
Taxes payable other than income taxes	108		201
Income taxes payable	180		—
Exchanges payable	154		208
Other	243		318
Total accrued and other current liabilities	$	2,582	$	2,367

Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests

The noncontrolling interest holders in one of ETP’s consolidated subsidiaries have the option to sell their interests to ETP.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheet.

Environmental Remediation

We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

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 December 31, 2017 was $45.62 billion and $44.08 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations was $45.05 billion and $43.80 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, interest rate derivatives and embedded derivatives in the ETP Convertible Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2017 and 2016, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2017 and 2016 based on inputs used to derive their fair values:

				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			—
Refined Products – Futures	1			1			—
Crude – Futures	2			2			—
Total commodity derivatives	321			277			44
Other non-current assets	21			14			7
Total assets	$	342		$	291		$	51
Liabilities:
Interest rate derivatives	$	(219	)	$	—		$	(219	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(24		)	(24		)	—
Swing Swaps IFERC	(15		)	(1		)	(14		)
Fixed Swaps/Futures	(57		)	(57		)	—
Forward Physical Swaps	(2		)	—			(2		)
Power — Forwards	(22		)	—			(22		)
Natural Gas Liquids — Forwards/Swaps	(192		)	(192		)
Refined Products – Futures	(28		)	(28		)	—
Crude — Futures	(1		)	(1		)	—
Total commodity derivatives	(341		)	(303		)	(38		)
Total liabilities	$	(560	)	$	(303	)	$	(257	)

				Fair Value Measurements at
				December 31, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	14		$	14		$	—		$	—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	96			96			—			—
Forward Physical Contracts	1			—			1			—
Power:
Forwards	4			—			4			—
Futures	1			1			—			—
Options — Calls	1			1			—			—
Natural Gas Liquids — Forwards/Swaps	233			233			—			—
Refined Products – Futures	2			2			—			—
Crude – Futures	9			9			—			—
Total commodity derivatives	363			356			7			—
Other non-current assets	13			8			5			—
Total assets	$	376		$	364		$	12		$	—
Liabilities:
Interest rate derivatives	$	(193	)	$	—		$	(193	)	$	—
Embedded derivatives in the ETP Convertible Preferred Units	(1		)	—			—			(1		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(11		)	(11		)	—			—
Swing Swaps IFERC	(3		)	—			(3		)	—
Fixed Swaps/Futures	(149		)	(149		)	—			—
Power:
Forwards	(5		)				(5		)	—
Futures	(1		)	(1		)	—			—
Natural Gas Liquids — Forwards/Swaps	(273		)	(273		)	—			—
Refined Products – Futures	(23		)	(23		)	—			—
Crude — Futures	(13		)	(13		)	—			—
Total commodity derivatives	(478		)	(470		)	(8		)	—
Total liabilities	$	(672	)	$	(470	)	$	(201	)	$	(1	)

Contributions in Aid of Construction Cost

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.

Shipping and Handling Costs

Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

Costs and Expenses

Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by Sunoco LP’s retail locations where Sunoco LP holds the inventory were $234 million, $243 million and $231 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiaries’ issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.

Income Taxes

ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).

As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, and 2015, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.

Unit-Based Compensation

For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.

Pensions and Other Postretirement Benefit Plans

ETP recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.  Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.

Allocation of Income

For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

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Acquisitions and Related Transactions

12 Months Ended

Dec. 31, 2017

Acquisitions and Dispositions [Abstract]

Acquisitions and Related Transactions

ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

2018 Transactions

CDM Contribution Agreement

In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP 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)19,191,351common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately$335 million, (ii)6,397,965units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately$112 millionand (iii) an amount in cash equal to$1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions.

In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii)12,466,912USAC Common Units for cash consideration equal to$250 million.

Sunoco LP Convenience Store and Real Estate Sale

On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”) and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven (“SEI Fuel” and together with 7-Eleven, referred to herein collectively as “Buyers”). Under the agreement, Sunoco LP sold a portfolio of approximately 1,030 company-operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of $3.3 billion.

Sunoco LP has signed definitive agreements with a commission agent to operate the approximately 207 retail sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the previously announced transaction with 7-Eleven, Inc. Conversion of these sites to the commission agent is expected to occur in the first quarter of 2018.

On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which will be operated by a commission agent.

The assets under the asset purchase agreement and the real estate assets subject to the portfolio optimization plan comprise the retail divestment presented as discontinued operations (“Retail Divestment”).

The Partnership has concluded that it meets the accounting requirements for reporting results of operations and cash flows of Sunoco LP’s continental United States retail convenience stores as discontinued operations and the related assets and liabilities as held for sale.

The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet:

	December 31, 2017		December 31, 2016
Carrying amount of assets included as part of discontinued operations:
Accounts receivable, net	$	21	$	16
Inventories	149		150
Other current assets	16		11
Property and equipment, net	1,851		1,860
Goodwill	796		1,068
Intangible assets, net	477		480
Other noncurrent assets	3		3
Total assets classified as held for sale in the Consolidated Balance Sheet	$	3,313	$	3,588
Carrying amount of liabilities included as part of discontinued operations:
Other current and noncurrent liabilities	$	75	$	48
Total liabilities classified as held for sale in the Consolidated Balance Sheet	$	75	$	48

The results of operations associated with discontinued operations are presented in the following table:

	Years Ended December 31,
	2017			2016			2015
REVENUES	$	6,964		$	5,712		$	6,030
COSTS AND EXPENSES
Cost of products sold	5,806			4,649			5,026
Operating expenses	763			744			705
Depreciation, depletion and amortization	34			143			128
Selling, general and administrative	168			114			91
Impairment losses	285			447			—
Total costs and expenses	7,056			6,097			5,950
OPERATING INCOME	(92		)	(385		)	80
Interest expense, net	36			28			21
Other, net	1			8			(2		)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE	(129		)	(421		)	61
Income tax expense	48			41			23
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(177	)	$	(462	)	$	38
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE	$	(6	)	$	(12	)	$	1

In connection with the classification of those assets as held-for-sale, the related goodwill was tested for impairment based on the assumed proceeds from the sale of those assets, resulting in goodwill impairment charges of $285 million recognized in 2017.

2017 Transactions

Rover Contribution Agreement

In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a49.9%interest in the holding company that owns65%of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.

ETP and Sunoco Logistics Merger

As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the Sunoco Logistics Merger.

Permian Express Partners

In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.

In July 2017, the Partnership contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in the Partnership’s ownership interest in PEP to approximately 88%. The Partnership maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a100%membership interest, sold a49%interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for$2.00 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access and ETCO. The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

2016 Transactions

WMB Merger

On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in ETE’s filings in the Delaware lawsuit referenced above. WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court.

PennTex Acquisition

On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately$627 millionin ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, ETP purchased PennTex’s remaining outstanding common units in June 2017.

Summary of Assets Acquired and Liabilities Assumed

We accounted for the PennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.

The total purchase price was allocated as follows:

	At November 1, 2016
Total current assets	$	34
Property, plant and equipment	393
Goodwill(1)	177
Intangible assets	446
	1,050
Total current liabilities	6
Long-term debt, less current maturities	164
Other non-current liabilities	17
Noncontrolling interest	236
	423
Total consideration	627
Cash received	21
Total consideration, net of cash received	$	606

⁽¹⁾  None of the goodwill is expected to be deductible for tax purposes.

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

Sunoco Logistics’ Vitol Acquisition

In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for$760 millionplus working capital. The acquisition provides Sunoco Logistics with an approximately2 millionbarrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a50%interest in SunVit Pipeline LLC (“SunVit”), which increased Sunoco Logistics’ overall ownership of SunVit to100%. The$769 millionpurchase price, net of cash received, consisted primarily of net working capital of$13 millionlargely attributable to inventory and receivables; property, plant and equipment of$286 millionprimarily related to pipeline and terminalling assets; intangible assets of$313 millionattributable to customer relationships; and goodwill of$251 million.

Bakken Financing

In August 2016, ETP and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billioncredit facility provided substantially all of the remaining capital necessary to complete the projects. As ofDecember 31, 2017, $2.50 billionwas outstanding under this credit facility.

Bayou Bridge

In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a30%interest in the entity and Sunoco Logistics is the operator of the system.

Sunoco Retail to Sunoco LP

In March 2016, ETP contributed to Sunoco LP its remaining68.42%interest in Sunoco, LLC and100%interest in the legacy Sunoco, Inc. retail business for$2.23 billion. Sunoco LP paid$2.20 billionin cash, including a working capital adjustment and issued5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016.

Sunoco LP Acquisitions

In August 2016, Sunoco LP acquired the fuels business from Emerge Energy Services LP for $171 million, including tax deductible goodwill of $53 million and intangible assets of $56 million. Additionally, during 2016, Sunoco LP made other acquisitions primarily consisting of convenience stores, totaling $114 million plus the value of inventory on hand at closing and increasing goodwill by $61 million.

In October 2016, Sunoco LP completed the acquisition of a convenience store, wholesale motor fuel distribution, and commercial fuels distribution business for approximately $55 million plus inventory on hand at closing, subject to closing adjustments.

2015 Transactions

Sunoco LP

In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons of motor fuel per year to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million in Sunoco LP common units to Retail Holdings, based on the five-day volume-weighted average price of Sunoco LP’s common units as of March 20, 2015.

In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries.

Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015.

Bakken Pipeline

In March 2015, ETE transferred 46.2 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017.

In October 2015, Sunoco Logistics completed the acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access and ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction.

Regency Merger

On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency surviving as a wholly-owned subsidiary of ETP (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 common units of ETP. ETP issued 258.3 million ETP common units to Regency unitholders, including 23.3 million units issued to ETP subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding new ETP Series A Convertible Preferred Units on a one-for-one basis.

In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.

ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.

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Advances to and Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2017

Investment In Affiliates [Abstract]

Investments In Affiliates

ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

Citrus

ETP owns CrossCountry, which owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.

FEP

ETP has a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. ETP evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. ETP recorded an impairment of its investment in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor.

MEP

ETP owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. ETP evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016.

HPC

ETP owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. ETP evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. During the year ended December 31, 2017, ETP recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.

The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2017 and 2016, were as follows:

	December 31,
	2017		2016
Citrus	$	1,754	$	1,729
FEP	121		101
MEP	242		318
HPC	28		382
Others	560		510
Total	$	2,705	$	3,040

The following table presents equity in earnings (losses) of unconsolidated affiliates:

	December 31,
Equity in earnings (losses) of unconsolidated affiliates:	2017			2016		2015
Citrus	$	144		$	102	$	97
FEP	53			51		55
MEP	38			40		45
HPC(1)	(168		)	31		32
Others	77			46		47
Total	$	144		$	270	$	276

⁽¹⁾  For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented:

	December 31,
	2017		2016
Current assets	$	206	$	214
Property, plant and equipment, net	8,336		8,726
Other assets	43		181
Total assets	$	8,585	$	9,121
Current liabilities	$	861	$	816
Non-current liabilities	4,492		4,940
Equity	3,232		3,365
Total liabilities and equity	$	8,585	$	9,121

	Years Ended December 31,
	2017		2016		2015
Revenue	$	1,358	$	1,164	$	1,385
Operating income	407		714		800
Net income	145		384		470

In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant to our consolidated financial statements.

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Net Income Per Limited Partner Unit

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Net Income Per Limited Partner Unit

NET INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of the ETE Series A Convertible Preferred Units, as discussed in Note 8. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP or Sunoco LP that would have resulted assuming the incremental units related to ETP’s or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.

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

	Years Ended December 31,
	2017			2016			2015
Income from continuing operations	$	2,543		$	462		$	1,023
Less: Income (loss) from continuing operations attributable to noncontrolling interest	1,583			(545		)	(165		)
Income from continuing operations, net of noncontrolling interest	960			1,007			1,188
Less: General Partner’s interest in income from continuing operations	2			3			3
Less: Convertible Unitholders’ interest in net income from continuing operations	38			8			—
Less: Class D Unitholder’s interest in income from continuing operations	—			—			3
Income from continuing operations available to Limited Partners	$	920		$	996		$	1,182
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,078.2			1,045.5			1,062.8
Basic income from continuing operations per Limited Partner unit	$	0.86		$	0.95		$	1.11
Basic income (loss) from discontinued operations per Limited Partner unit	$	(0.01	)	$	(0.01	)	$	—
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	920		$	996		$	1,182
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units	38			8			3
Diluted income from continuing operations available to Limited Partners	958			1,004			1,185
Weighted average limited partner units	1,078.2			1,045.5			1,062.8
Dilutive effect of unconverted unit awards and Convertible Units	72.6			33.1			1.6
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	1,150.8			1,078.6			1,064.4
Diluted income from continuing operations per Limited Partner unit	$	0.84		$	0.93		$	1.11
Diluted income (loss) from discontinued operations per Limited Partner unit	$	(0.01	)	$	(0.01	)	$	—

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Debt Obligations

12 Months Ended

Dec. 31, 2017

Debt Obligations [Abstract]

Debt Disclosure [Text Block]

DEBT OBLIGATIONS:

Our debt obligations consist of the following:

	December 31,
	2017			2016
Parent Company Indebtedness:
7.50% Senior Notes due October 15, 2020	$	1,187		$	1,187
5.875% Senior Notes due January 15, 2024	1,150			1,150
5.50% Senior Notes due June 1, 2027	1,000			1,000
4.25% Senior Notes due March 15, 2023	1,000			—
ETE Senior Secured Term Loan due December 2, 2019	—			2,190
ETE Senior Secured Term Loan due February 2, 2024	1,220			—
ETE Senior Secured Revolving Credit Facility due December 18, 2018	—			875
ETE Senior Secured Revolving Credit Facility due March 24, 2022	1,188			—
Unamortized premiums, discounts and fair value adjustments, net	(11		)	(15		)
Deferred debt issuance costs	(34		)	(30		)
	6,700			6,357
Subsidiary Indebtedness:
ETP Debt
6.125% Senior Notes due February 15, 2017	—			400
2.50% Senior Notes due June 15, 2018 (1)	650			650
6.70% Senior Notes due July 1, 2018 (1)	600			600
9.70% Senior Notes due March 15, 2019	400			400
9.00% Senior Notes due April 15, 2019	450			450
5.50% Senior Notes due February 15, 2020	250			250
5.75% Senior Notes due September 1, 2020	400			400
4.15% Senior Notes due October 1, 2020	1,050			1,050
4.40% Senior Notes due April 1, 2021	600			600
6.50% Senior Notes due July 15, 2021	—			500
4.65% Senior Notes due June 1, 2021	800			800
5.20% Senior Notes due February 1, 2022	1,000			1,000
4.65% Senior Notes due February 15, 2022	300			300
5.875% Senior Notes due March 1, 2022	900			900
5.00% Senior Notes due October 1, 2022	700			700
3.45% Senior Notes due January 15, 2023	350			350
3.60% Senior Notes due February 1, 2023	800			800
5.50% Senior Notes due April 15, 2023	—			700
4.50% Senior Notes due November 1, 2023	600			600
4.90% Senior Notes due February 1, 2024	350			350
7.60% Senior Notes due February 1, 2024	277			277
4.25% Senior Notes due April 1, 2024	500			500
9.00% Debentures due November 1, 2024	65			65
4.05% Senior Notes due March 15, 2025	1,000			1,000
5.95% Senior Notes due December 1, 2025	400			400
4.75% Senior Notes due January 15, 2026	1,000			1,000
3.90% Senior Notes due July 15, 2026	550			550
4.20% Senior Notes due April 15, 2027	600			—
4.00% Senior Notes due October 1, 2027	750			—
8.25% Senior Notes due November 15, 2029	267			267
4.90% Senior Notes due March 15, 2035	500			500
6.625% Senior Notes due October 15, 2036	400			400
7.50% Senior Notes due July 1, 2038	550			550
6.85% Senior Notes due February 15, 2040	250			250
6.05% Senior Notes due June 1, 2041	700			700
6.50% Senior Notes due February 1, 2042	1,000			1,000
6.10% Senior Notes due February 15, 2042	300			300

4.95% Senior Notes due January 15, 2043	350		350
5.15% Senior Notes due February 1, 2043	450		450
5.95% Senior Notes due October 1, 2043	450		450
5.30% Senior Notes due April 1, 2044	700		700
5.15% Senior Notes due March 15, 2045	1,000		1,000
5.35% Senior Notes due May 15, 2045	800		800
6.125% Senior Notes due December 15, 2045	1,000		1,000
5.30% Senior Notes due April 15, 2047	900		—
5.40% Senior Notes due October 1, 2047	1,500		—
Floating Rate Junior Subordinated Notes due November 1, 2066	546		546
ETP $4.0 billion Revolving Credit Facility due December 2022	2,292		—
ETP $1.0 billion 364-Day Credit Facility due November 2018 (2)	50		—
ETLP $3.75 billion Revolving Credit Facility due November 2019	—		2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020	—		1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017	—		630
Unamortized premiums, discounts and fair value adjustments, net	33		66
Deferred debt issuance costs	(170	)	(166	)
	29,210		29,454
Transwestern Debt
5.64% Senior Notes due May 24, 2017	—		82
5.36% Senior Notes due December 9, 2020	175		175
5.89% Senior Notes due May 24, 2022	150		150
5.66% Senior Notes due December 9, 2024	175		175
6.16% Senior Notes due May 24, 2037	75		75
Deferred debt issuance costs	(1	)	(1	)
	574		656
Panhandle Debt
6.20% Senior Notes due November 1, 2017	—		300
7.00% Senior Notes due June 15, 2018	400		400
8.125% Senior Notes due June 1, 2019	150		150
7.60% Senior Notes due February 1, 2024	82		82
7.00% Senior Notes due July 15, 2029	66		66
8.25% Senior Notes due November 14, 2029	33		33
Floating Rate Junior Subordinated Notes due November 1, 2066	54		54
Unamortized premiums, discounts and fair value adjustments, net	28		50
	813		1,135
Sunoco, Inc. Debt
5.75% Senior Notes due January 15, 2017	—		400
Bakken Project Debt
Bakken Project $2.50 billion Credit Facility due August 2019	2,500		1,100
Deferred debt issuance costs	(8	)	(13	)
	2,492		1,087
PennTex Debt
PennTex $275 million Revolving Credit Facility due December 2019	—		168
Sunoco LP Debt
5.50% Senior Notes due August 1, 2020	600		600
6.375% Senior Notes due April 1, 2023	800		800
6.25% Senior Notes due April 15, 2021	800		800
Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019	765		1,000
Sunoco LP Term Loan due October 1, 2019	1,243		1,243
Lease-related obligations	113		118
Deferred debt issuance costs	(34	)	(47	)
	4,287		4,514

Other	8		31
Total debt	44,084		43,802
Less: current maturities of long-term debt	413		1,194
Long-term debt, less current maturities	$	43,671	$	42,608

⁽¹⁾  As of December 31, 2017 ETP’s management had the intent and ability to refinance the$650 million2.50%senior notes due June 15, 2018 and the$600 million6.70%senior notes due July 1, 2018, and therefore neither was classified as current.

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

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $197 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net:

2018	$	1,705
2019	5,512
2020	3,667
2021	2,205
2022	6,540
Thereafter	24,652
Total	$	44,281

Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.

Notes and Debentures

ETE Senior Notes Offering

In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes.

The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The balance is payable upon maturity. Interest on the senior notes is paid semi-annually.

ETE Senior Notes

The ETE Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ETE Senior Notes are secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ETE Term Loan Facility, by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries.

The covenants related to the ETE Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Parent Company’s assets.

As discussed above, the Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP are required under Rule 3-16 to be included in the Partnership’s Annual Report on Form 10-K and have been included herein.

The Parent Company’s interests in ETP GP also constitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of ETP GP would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. ETP GP does not have substantive operations of its own; rather, ETP GP only owns 100% of the general partner interest in ETP. ETP GP does not own limited partner interests in ETP; therefore, the limited partner interests in ETP, which had a carrying value of $28.02 billion and $18.41 billion as of December 31, 2017 and 2016, respectively, would be reflected as noncontrolling interests on ETP GP’s balance sheets. Likewise, ETP’s income (loss) attributable to limited partners (including common unitholders, Class H unitholders, Class I unitholders and ETP Preferred Units) of $1.08 billion, $(660) million and $325 million for the years ended December 31, 2017, 2016 and 2015, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations.

ETP’s general partner interest is reflected separately in ETP’s financial statements. As a result, the financial statements of ETP GP would substantially duplicate information that is available in the financial statements of ETP. Therefore, the financial statements of ETP GP have been excluded from the Partnership’s Annual Report on Form 10-K.

ETP Senior Notes

The ETP senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually.

The ETP senior notes are unsecured obligations of ETP and as a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

Transwestern Senior Notes

The Transwestern senior notes are redeemable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is payable semi-annually.

Panhandle Junior Subordinated Notes

The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 4.39% at December 31, 2017.

Sunoco LP Private Offering of Senior Notes

On January 23, 2018, Sunoco LP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in aggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the closing of the asset purchase agreement with 7-Eleven to: 1) redeem in full its existing senior notes as of December 31, 2017, comprised of $800 million in aggregate principal amount of 6.250%senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023; 2) repay in full and terminate the Sunoco LP Term Loan; 3) pay all closing costs and taxes in connection with the 7-Eleven transaction; 4) redeem the outstanding Sunoco LP Series A Preferred Units as mentioned above; and 5) repurchase 17,286,859 common units owned by ETP as mentioned above.

Sunoco LP Senior Notes

In April 2016, Sunoco LP issued $800 million aggregate principal amount of 6.25% Senior Notes due 2021. The net proceeds of $789 million were used to repay a portion of the borrowings under its term loan facility.

The 6.25% Senior Notes due 2021 were redeemed on January 23, 2018. See Sunoco LP Private Offering of Senior Notes above.

Term Loans, Credit Facilities and Commercial Paper

ETE Term Loan Facility

On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof. In connection with the Parent Company’s entry into the Senior Secured Term Loan Agreement on February 2, 2017, the Parent Company terminated its previous term loan agreements.

Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP , and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP, and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.

Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.

On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.

In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.

ETE Revolving Credit Facility

The Parent Company had a revolver credit agreement which had a scheduled maturity date of December 2, 2018, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The agreement was terminated in connection with entry into the Revolver Credit Agreement, discussed below.

On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $1.50 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 millionsublimit. Under the Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of December 31, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $312 million.

ETP Credit Facilities

On December 1, 2017 ETP entered into a five-year, $4.0 billionunsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a$1.0 billion364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitments may be increased up to$6.0 billionunder certain conditions. ETP uses the ETP Credit Facilities to provide temporary financing for its growth projects, as well as for general partnership purposes.

As ofDecember 31, 2017, the ETP Five-Year Facility had$2.29 billion outstanding, of which$2.01 billionwas commercial paper. The amount available for future borrowings was$1.56 billionafter taking into account letters of credit of$150 million. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was2.48%.

As ofDecember 31, 2017, the ETP 364-Day Facility had$50 millionoutstanding, and the amount available for future borrowings was$950 million. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was5.00%.

ETLP Credit Facility

The ETLP Credit Facility allowed for borrowings of up to$3.75 billionand was used to provide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.

Sunoco Logistics Credit Facilities

ETP maintained a$2.50 billionunsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.

In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of$1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017.

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 billioncredit 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 ofDecember 31, 2017, the Bakken Credit Facility had $2.50 billionof outstanding borrowings. The weighted average interest rate on the total amount outstanding as ofDecember 31, 2017was3.00%.

PennTex Revolving Credit Facility

PennTex previously maintained a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

Sunoco LP Term Loan

Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As ofDecember 31, 2017, the balance on the term loan was $1.24 billion.

The Sunoco LP term loan was repaid in full and terminated on January 23, 2018. See Sunoco LP Private Offering of Senior Notes above.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billionand matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the revolving credit facility. As of December 31, 2017, the Sunoco LP credit facility had $9 million in standby letters of credit. The amount available for future borrowings on the revolver at December 31, 2017 was $726 million.

On October 16, 2017, Sunoco LP entered into the Fifth Amendment to the Credit Agreement with the lenders party thereto and Bank of America, N.A., in its capacity as a letter of credit issuer, as swing line lender, and as administrative agent. The Fifth Amendment amended the agreement to (i) permit the dispositions contemplated by the Retail Divestment, (ii) extend the interest coverage ratio covenant of 2.25x through maturity, (iii) modify the definition of consolidated EBITDA to include the pro forma effect of the divestitures and the new fuel supply contracts, and (iv) modify the leverage ratio covenant.

Covenants Related to Our Credit Agreements

Covenants Related to the Parent Company

The Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements.

The Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows:

• Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company to Consolidated EBITDA (as defined therein) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 7 to 1 during a specified acquisition period following the close of a specified acquisition; and

• Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1.

Covenants Related to ETP

The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

The ETP Credit Facilities contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:

• incur indebtedness;

• grant liens;

• enter into mergers;

• dispose of assets;

• make certain investments;

• make Distributions (as defined in the ETP Credit Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit Facilities);

• engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

• engage in transactions with affiliates; and

• enter into restrictive agreements.

The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt.The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from1.125% to 2.000%and the applicable margin for base rate loans ranges from0.125%to1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from0.125%to0.300%.  The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from1.125%to1.750%and the applicable margin for base rate loans ranges from0.250%to0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from0.125%to0.225%.

The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0to1, which can generally be increased to5.5to1during a Specified Acquisition Period. Our Leverage Ratio was 3.96to1atDecember 31, 2017, as calculated in accordance with the credit agreements.

The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.

Covenants Related to Panhandle

Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.

In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.

Covenants Related to Bakken Credit Facility

The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:

• prohibition of certain incremental secured indebtedness;

• prohibition of certain liens / negative pledge;

• limitations on uses of loan proceeds;

• limitations on asset sales and purchases;

• limitations on permitted business activities;

• limitations on mergers and acquisitions;

• limitations on investments;

• limitations on transactions with affiliates; and

• maintenance of commercially reasonable insurance coverage.

A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than1.20to1(the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.

Covenants Related to Sunoco LP

The Sunoco LP Credit Facilities contain various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. The Sunoco LP Credit Facilities  require Sunoco LP to maintain a leverage ratio (as defined therein) of not more than (a) as of the last day of each fiscal quarter through December 31, 2017, 6.75 to 1.0, (b) as of March 31, 2018, 6.5 to 1.0, (c) as of June 30, 2018, 6.25 to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (in the case of the quarter ending March 31, 2019 and thereafter, subject to increases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of $50 million, as permitted under the Credit Facilities.  Indebtedness under the Credit Facilities is secured by a security interest in, among other things, all of Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Credit Facilities will be released.

Compliance With Our Covenants

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.

We and our subsidiaries are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017.

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Redeemable Preferred Units

12 Months Ended

Dec. 31, 2017

Preferred Units, Preferred Partners' Capital Account [Abstract]

Redeemable Preferred Units

ETP CONVERTIBLE PREFERRED UNITS:

The ETP Convertible Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and are reflected as long-term liabilities in our consolidated balance sheets. The ETP Convertible Preferred Units are entitled to a preferential quarterly cash distribution of $0.445 per ETP Preferred Unit if outstanding on the record dates of ETP’s common unit distributions. In January 2017, ETP repurchased all of its1.9 million outstanding ETP Convertible Preferred Units for cash in the aggregate amount of $53 million.

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Equity

12 Months Ended

Dec. 31, 2017

Partners' Capital Notes [Abstract]

Equity

EQUITY:

Limited Partner Units

Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.”

As of December 31, 2017, there were issued and outstanding 1.08 billion Common Units representing an aggregate 94.38% limited partner interest in the Partnership.

Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.

Common Units

The change in ETE Common Units during the years ended December 31, 2017, 2016 and 2015 was as follows:

	Years Ended December 31,
	2017	2016	2015
Number of Common Units, beginning of period	1,046.9	1,044.8	1,077.5
Conversion of Class D Units to ETE Common Units	—	—	0.9
Repurchase of common units under buyback program	—	—	(33.6	)
Issuance of common units	32.2	2.1	—
Number of Common Units, end of period	1,079.1	1,046.9	1,044.8

ETE Equity Distribution Agreement

In March 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the year ended December 31, 2017.

ETE Series A Convertible Preferred Units

	Years Ended December 31,
	2017	2016	2015
Number of Series A Convertible Preferred Units, beginning of period	329.3	—	—
Issuance of Series A Convertible Preferred Units	—	329.3	—
Number of Series A Convertible Preferred Units, end of period	329.3	329.3	—

On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.

The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $450 million carrying value as of December 31, 2017.

ETE issued 329,295,770 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates.

ETE January 2017 Private Placement and ETP Unit Purchase

In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units for approximately $568 million.

Common Unit Split

On July 27, 2015, ETE completed a two-for-one split of the Partnership’s outstanding common units by a distribution of one ETE common unit for each common unit outstanding and held by unitholders of record at the close of business on July 15, 2015.

Repurchase Program

In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 33.6 million ETE Common Units under this program in 2015. No units were repurchased under this program in 2017 or 2016, and there was $936 million available to use under the program as of December 31, 2017.

Class D Units

In 2013, the Partnership issued 3,080,000 Class D Units of ETE pursuant to an agreement with a former executive. The Class D Units were convertible to ETE Common Units, subject to certain vesting requirements which were not met prior to the former executive’s termination in 2016.

Sale of Common Units by Subsidiaries

The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented.

Sale of Common Units by ETP

ETP’s Equity Distribution Program

From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, ETP entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion.

During the year ended December 31, 2017, ETP issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $752 million of ETP’s Common Units remained available to be issued under ETP’s currently effective equity distribution agreement.

ETP’s Equity Incentive Plan Activity

ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by ETP to satisfy tax-withholding obligations.

ETP’s Distribution Reinvestment Program

ETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan.

During the years ended December 31, 2017, 2016 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units.

As of December 31, 2017, a total of 20.8 million Common Units remain available to be issued under the existing registration statement.

August 2017 Units Offering

In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

ETP Class E Units

There are currently 8.9 million ETP Class E Units outstanding, all of which are currently owned by HHI. The ETP Class E Units generally do not have any voting rights. The ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the Class E Unitholders, up to $1.41per unit per year. As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in ETP’s consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the ETP Class E Units at a future date.

ETP Class G Units

There are currently 90.7 million ETP Class G Units outstanding, all of which are held by wholly-owned subsidiaries of ETP. The ETP Class G Units generally do not have any voting rights. The ETP Class G Units are entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and its subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per ETP Class G Unit per year. Allocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are reflected as treasury units in the consolidated financial statements.

ETP Class H Units

Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017.

ETP Class I Units

In connection with the Bakken Pipeline Transaction discussed in Note 3, in March 2015, ETP issued 100 ETP Class I Units. The ETP Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the ETP Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the ETP Class I Units and (ii) after making cash distributions to ETP Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in ETP’s Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a100%membership interest, sold a49%interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for$2.00 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access and ETCO. The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

Class K Units

On December 29, 2016, ETP issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in ETP, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. If ETP is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5%per annum until paid. As of December 31, 2017, a total of101.5 millionClass K Units were held by wholly-owned subsidiaries of ETP.

Sales of Common Units by Sunoco Logistics

Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.

In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.

In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.

In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In connection with the Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated.

ETP Series A and Series Preferred Units

In November 2017, ETP issued950,000of its6.250%Series A Preferred Units at a price of$1,000per unit, and550,000of its6.625%Series B Preferred Units at a price of$1,000per unit.

Distributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETP Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETP Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per ETP Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Distributions on the ETP Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETP Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETP Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per ETP Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

PennTex Tender Offer and Limited Call Right Exercise

In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.

Sales of Common Units by Sunoco LP

In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased17,286,859Sunoco 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 October 2016, Sunoco LP entered into an equity distribution agreement pursuant to which Sunoco LP may sell from time to time common units having aggregate offering prices of up to $400 million. Through December 31, 2016, Sunoco LP received net proceeds of $71 million from the issuance of 2.8 million Sunoco LP common units pursuant to such equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes. From January 1, 2017 through December 31, 2017, Sunoco LP issued additional 1.3 million units with total net proceeds of $33 million, net of commissions of $0.3 million. As of December 31, 2017, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.

In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP.

On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership.

In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha Petroleum, Ltd as consideration for the contribution by Aloha to an indirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries.

In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $213 million. The net proceeds from the offering were used to repay outstanding balances under the Sunoco LP revolving credit facility.

Sunoco LP Series A Preferred Units

On March 30, 2017, the Partnership purchased 12.0 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units is10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference.

In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.

Contributions to Subsidiaries

The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP has the right, but not the obligation, to contribute a proportionate amount of capital to ETP to maintain its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest.

Parent Company Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Sunoco LP related to limited and general partner interests, including IDRs, as well as cash generated from our investment in Lake Charles LNG.

Our distributions declared and paid with respect to our common units for the periods presented were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 6, 2015	February 19, 2015	0.2250
March 31, 2015	May 8, 2015	May 19, 2015	0.2450
June 30, 2015	August 6, 2015	August 19, 2015	0.2650
September 30, 2015	November 5, 2015	November 19, 2015	0.2850
December 31, 2015	February 4, 2016	February 19, 2016	0.2850
March 31, 2016 (1)	May 6, 2016	May 19, 2016	0.2850
June 30, 2016 (1)	August 8, 2016	August 19, 2016	0.2850
September 30, 2016 (1)	November 7, 2016	November 18, 2016	0.2850
December 31, 2016 (1)	February 7, 2017	February 21, 2017	0.2850
March 31, 2017 (1)	May 10, 2017	May 19, 2017	0.2850
June 30, 2017 (1)	August 7, 2017	August 21, 2017	0.2850
September 30, 2017 (1)	November 7, 2017	November 20, 2017	0.2950
December 31, 2017 (1)	February 8, 2018	February 20, 2018	0.3050

⁽¹⁾  Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See additional information below.

Our distributions declared and paid with respect to our Convertible Unit during the years ended December 31, 2016 and 2017 were as follows:

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2016	May 6, 2016	May 19, 2016	$	0.1100
June 30, 2016	August 8, 2016	August 19, 2016	0.1100
September 30, 2016	November 7, 2016	November 18, 2016	0.1100
December 31, 2016	February 7, 2017	February 21, 2017	0.1100
March 31, 2017	May 10, 2017	May 19, 2017	0.1100
June 30, 2017	August 7, 2017	August 21, 2017	0.1100
September 30, 2017	November 7, 2017	November 20, 2017	0.1100
December 31, 2017	February 8, 2018	February 20, 2018	0.1100

ETP’s Quarterly Distributions of Available Cash

Under ETP’s limited partnership agreement, within 45 days after the end of each quarter, ETP 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 ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP’s business. ETP 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.

If cash distributions exceed$0.0833per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”

As the holder of Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	IDRs	Partners (1)
Minimum Quarterly Distribution	$0.0750	—%	100%
First Target Distribution	up to $0.0833	—%	100%
Second Target Distribution	above $0.0833 up to $0.0958	13%	87%
Third Target Distribution	above $0.0958 up to $0.2638	35%	65%
Thereafter	above $0.2638	48%	52%

⁽¹⁾Includes general partner and limited partner interests, based on the proportionate ownership of each.

The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:

Quarter Ended	ETP		Sunoco Logistics
December 31, 2014	$	0.6633	$	0.4000
March 31, 2015	0.6767		0.4190
June 30, 2015	0.6900		0.4380
September 30, 2015	0.7033		0.4580
December 31, 2015	0.7033		0.4790
March 31, 2016	0.7033		0.4890
June 30, 2016	0.7033		0.5000
September 30, 2016	0.7033		0.5100
December 31, 2016	0.7033		0.5200

Distributions on common units declared and paid by Post-Merger ETP were as follows:

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 16, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 15, 2017	0.5500
September 30, 2017	November 7, 2017	November 14, 2017	0.5650
December 31, 2017	February 8, 2018	February 14, 2018	0.5650

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

	Total Year
2018	$	153
2019	128
Each year beyond 2019	33

Distributions declared and paid by ETP to the Series A and Series B preferred unitholders 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

Sunoco LP Quarterly Distributions of Available Cash

The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Effective July 1, 2015, ETE exchanged 21 million ETP common units, owned by ETE, the owner of ETP’s general partner interest, for 100% of the general partner interest and all of the IDRs of Sunoco LP. ETP had previously owned our IDRs since September 2014, prior to that date the IDRs were owned by Susser.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Common Unitholders	Holder of IDRs
Minimum Quarterly Distribution	$0.4375	100%	—%
First Target Distribution	$0.4375 to $0.503125	100%	—%
Second Target Distribution	$0.503125 to $0.546875	85%	15%
Third Target Distribution	$0.546875 to $0.656250	75%	25%
Thereafter	Above $0.656250	50%	50%

Distributions declared and paid by Sunoco LP for the periods presented were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 17, 2015	February 27, 2015	0.6000
March 31, 2015	May 19, 2015	May 29, 2015	0.6450
June 30, 2015	August 18, 2015	August 28, 2015	0.6934
September 30, 2015	November 17, 2015	November 27, 2015	0.7454
December 31, 2015	February 5, 2016	February 16, 2016	0.8013
March 31, 2016	May 6, 2016	May 16, 2016	0.8173
June 30, 2016	August 5, 2016	August 15, 2016	0.8255
September 30, 2016	November 7, 2016	November 15, 2016	0.8255
December 31, 2016	February 13, 2017	February 21, 2017	0.8255
March 31, 2017	May 9, 2017	May 16, 2017	0.8255
June 30, 2017	August 7, 2017	August 15, 2017	0.8255
September 30, 2017	November 7, 2017	November 14, 2017	0.8255
December 31, 2017	February 06, 2018	February 14, 2018	0.8255

Accumulated Other Comprehensive Income (Loss)

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

	December 31,
	2017			2016
Available-for-sale securities	$	8		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain (loss) related to pensions and other postretirement benefits	(5		)	7
Investments in unconsolidated affiliates, net	5			4
Subtotal	3			8
Amounts attributable to noncontrolling interest	(3		)	(8		)
Total AOCI included in partners’ capital, net of tax	$	—		$	—

The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss):

	December 31,
	2017			2016
Available-for-sale securities	$	(2	)	$	(2	)
Foreign currency translation adjustment	3			3
Actuarial loss relating to pension and other postretirement benefits	3			—
Total	$	4		$	1

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Unit-Based Compensation Plans

12 Months Ended

Dec. 31, 2017

Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]

Unit-Based Compensation Plans

UNIT-BASED COMPENSATION PLANS:

We, ETP and Sunoco LP have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards.

ETE Long-Term Incentive Plan

The Board of Directors or the Compensation Committee of the board of directors of our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 12.0 million units. As of December 31, 2017, 10.8 million units remain available to be awarded under the plan.

During the year ended December 31, 2017, 1.2 million ETE unit awards were granted to ETE employees and certain employees of ETP and 15,648 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest 60% in three years and 40% in five years and do not entitle the holders to receive distributions during the vesting period.

During the year ended December 31, 2017 and 2016, a total of 2,018 and 28,648 ETE Common Units vested, with a total fair value of $39 thousand and $205 thousand, respectively, as of the vesting date. As of December 31, 2017, a total of 1,251,002 restricted units remain outstanding, for which we expect to recognize a total of $21 million in compensation over a weighted average period of 3.5 years.

Subsidiary Unit-Based Compensation Plans

Each of ETP and Sunoco LP has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards” to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a five-year period, and vesting The Subsidiary Unit Awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding.

The following table summarizes the activity of the Subsidiary Unit Awards:

	ETP				Sunoco LP
	Number of Units		Weighted  Average Grant-Date Fair Value Per Unit		Number of Units		Weighted  Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 2016	9.4		$	27.68	2.0		$	34.43
Legacy Sunoco Logistics unvested awards as of December 31, 2016	3.2		28.57		—		—
Awards granted	4.9		17.69		0.2		28.31
Awards vested	(2.3	)	34.22		(0.3	)	45.48
Awards forfeited	(1.1	)	25.03		(0.2	)	34.71
Unvested awards as of December 31, 2017	14.1		23.18		1.7		31.89

Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31:
2017	$	17.69	$	28.31
2016	23.82		26.95
2015	23.47		40.63

The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2017, 2016, and 2015 was $40 million, $40 million, and $57 million, respectively, based on the market price of the respective subsidiaries’ common units as of the vesting date. As of December 31, 2017, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $216 million, and the weighted average period over which this cost is expected to be recognized in expense is 2.8 years.

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Income Taxes Income Taxes (Notes)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES:

As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:

	Years Ended December 31,
	2017			2016			2015
Current expense (benefit):
Federal	$	54		$	(47	)	$	(308	)
State	(16		)	(34		)	(54		)
Total	38			(81		)	(362		)
Deferred expense (benefit):
Federal	(2,055		)	(189		)	268
State	184			12			(29		)
Total	(1,871		)	(177		)	239
Total income tax expense (benefit) from continuing operations	$	(1,833	)	$	(258	)	$	(123	)

Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense (benefit) at the United States statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2017, 2016 and 2015 is as follows:

	2017			2016			2015
Income tax expense (benefit) at United States statutory rate of 35 percent	$	248		$	71		$	316
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(477		)	(576		)	(355		)
Goodwill impairment	207			278			—
State tax, net of federal tax benefit	124			(10		)	(29		)
Dividend received deduction	(14		)	(15		)	(22		)
Federal rate change	(1,812		)	—			—
Audit settlement	—			—			(7		)
Change in tax status of subsidiary	(124		)	—			—
Other	15			(6		)	(26		)
Income tax expense (benefit) from continuing operations	$	(1,833	)	$	(258	)	$	(123	)

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:

	December 31,
	2017			2016
Deferred income tax assets:
Net operating losses and alternative minimum tax credit	$	683		$	472
Pension and other postretirement benefits	21			30
Long-term debt	14			32
Other	191			182
Total deferred income tax assets	909			716
Valuation allowance	(189		)	(118		)
Net deferred income tax assets	720			598
Deferred income tax liabilities:
Property, plant and equipment	(1,036		)	(1,633		)
Investments in unconsolidated affiliates	(2,726		)	(3,789		)
Trademarks	(173		)	(273		)
Other	(100		)	(15		)
Total deferred income tax liabilities	(4,035		)	(5,710		)
Net deferred income taxes	$	(3,315	)	$	(5,112	)

The table below provides a rollforward of the net deferred income tax liability as follows:

	December 31,
	2017			2016
Net deferred income tax liability, beginning of year	$	(5,112	)	$	(4,590	)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)	—			(460		)
Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3)	—			(243		)
Tax provision, including provision from discontinued operations	1,825			201
Other	(28		)	(20		)
Net deferred income tax liability	$	(3,315	)	$	(5,112	)

ETP Holdco and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $403 million, all of which will expire in 2031 through 2037. Our corporate subsidiaries have $62 million of federal alternative minimum tax credits at December 31, 2017, of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have net operating loss carryforward benefits of $274 million, $217 million net of federal tax, which expire between January 1, 2018 and 2037. A valuation allowance of $186 million is applicable to the state net operating loss carryforward benefits applicable to significant restriction on their use in the Commonwealth of Pennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit.

The following table sets forth the changes in unrecognized tax benefits:

	Years Ended December 31,
	2017			2016			2015
Balance at beginning of year	$	615		$	610		$	440
Additions attributable to tax positions taken in the current year	—			8			178
Additions attributable to tax positions taken in prior years	28			18			—
Reduction attributable to tax positions taken in prior years	(25		)	(20		)	—
Lapse of statute	(9		)	(1		)	(8		)
Balance at end of year	$	609		$	615		$	610

As of December 31, 2017, we have $605 million ($576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.

Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $9 million, net of tax.

Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in its litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the consolidated balance sheet as of December 31, 2017.

In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety.  In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact.  Nextel has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court.  Sunoco, Inc. has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter.  However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 million after federal income tax benefits) against the receivable.

In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007.

Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments.

ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.

Income Tax Benefit.On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from35% to21%for taxable years beginning afterDecember 31, 2017. As a result, the Partnership recognized a deferred tax benefit of$1.81 billionin December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

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Derivative Assets And Liabilities

12 Months Ended

Dec. 31, 2017

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Derivative Assets And Liabilities

DERIVATIVE ASSETS AND LIABILITIES:

Commodity Price Risk

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

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

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

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

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

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing operations. These contracts are not designated as hedges for accounting purposes.

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

The following table details our outstanding commodity-related derivatives:

	December 31, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	1,078		2018	(683	)	2017
Basis Swaps IFERC/NYMEX (1)	48,510		2018-2020	2,243		2017
Options – Puts	13,000		2018	—		—
Power (Megawatt):
Forwards	435,960		2018-2019	391,880		2017 - 2018
Futures	(25,760	)	2018	109,564		2017 - 2018
Options — Puts	(153,600	)	2018	(50,400	)	2017
Options — Calls	137,600		2018	186,400		2017
Crude (MBbls) – Futures	—		—	(617	)	2017
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	4,650		2018-2020	10,750		2017 - 2018
Swing Swaps IFERC	87,253		2018-2019	(5,663	)	2017
Fixed Swaps/Futures	(4,390	)	2018-2019	(52,653	)	2017 - 2019
Forward Physical Contracts	(145,105	)	2018-2020	(22,492	)	2017
Natural Gas Liquid (MBbls) – Forwards/Swaps	6,744		2018-2019	(5,787	)	2017
Refined Products (MBbls) – Futures	(3,901	)	2018-2019	(3,144	)	2017
Corn (Bushels) – Futures	1,870,000		2018	1,580,000		2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(39,770	)	2018	(36,370	)	2017
Fixed Swaps/Futures	(39,770	)	2018	(36,370	)	2017
Hedged Item — Inventory	39,770		2018	36,370		2017

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

Interest Rate Risk

We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

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

			Notional Amount Outstanding
Entity	Term	Type(1)	December 31, 2017		December 31, 2016
ETP	July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
ETP	July 2018(2)	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
ETP	July 2019(2)	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
ETP	July 2020(2)	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
ETP	December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
ETP	March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300

⁽¹⁾  Floating rates are based on 3-month LIBOR.

⁽²⁾  Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

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

The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	December 31, 2017		December 31, 2016		December 31, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	14	$	—	$	(2	)	$	(4	)
	14		—		(2		)	(4		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	262		338		(281		)	(416		)
Commodity derivatives	45		25		(58		)	(58		)
Interest rate derivatives	—		—		(219		)	(193		)
Embedded derivatives in ETP Convertible Preferred Units	—		—		—			(1		)
	307		363		(558		)	(668		)
Total derivatives	$	321	$	363	$	(560	)	$	(672	)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	December 31, 2017			December 31, 2016			December 31, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(219	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	45			25			(58		)	(58		)
Broker cleared derivative contracts	Other current assets (liabilities)	276			338			(283		)	(420		)
		321			363			(560		)	(672		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(21		)	(4		)	21			4
Counterparty netting	Other current assets (liabilities)	(263		)	(338		)	263			338
Total net derivatives		$	37		$	21		$	(276	)	$	(330	)

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

The following tables summarize the amounts recognized 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
		Years Ended December 31,
		2017		2016		2015
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	26	$	14	$	21
Total		$	26	$	14	$	21

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2017			2016			2015
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	31		$	(35	)	$	(11	)
Commodity derivatives – Non-trading	Cost of products sold	5			(177		)	15
Interest rate derivatives	Losses on interest rate derivatives	(37		)	(12		)	(18		)
Embedded derivatives	Other, net	1			4			12
Total		$	—		$	(220	)	$	(2	)

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

12 Months Ended

Dec. 31, 2017

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Contingent Residual Support Agreement – AmeriGas

In connection with the closing of the contribution of its propane operations in January 2012, ETP previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.

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 millionprincipal amount of6.375%senior notes due 2023 issued by Sunoco LP, (ii)$800 millionprincipal amount of6.25%senior notes due 2021 issued by Sunoco LP and (iii)$2.035 billionaggregate 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 billionaggregate principal amount of4.875%, senior notes due 2023;

• $800 millionaggregate principal amount of5.50%senior notes due 2026; and

• $400 millionaggregate principal amount of5.875%senior notes due 2028.

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

FERC Audit

In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.

Commitments

In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

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

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Years Ended December 31,
	2017			2016			2015
Rental expense(1)	$	196		$	187		$	281
Less: Sublease rental income	(25		)	(26		)	(26		)
Rental expense, net	$	171		$	161		$	255

⁽¹⁾  Includes contingent rentals totaling $16 million, $18 million and $20 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Future minimum lease commitments for such leases are:

Years Ending December 31:
2018	$	113
2019	100
2020	96
2021	83
2022	71
Thereafter	606
Future minimum lease commitments	1,069
Less: Sublease rental income	(152		)
Net future minimum lease commitments	$	917

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 consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways 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 is pending. Dakota Access intervened in the case. The SRST soon added a request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot.

After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.

The SRST appealed the denial of the preliminary injunction to the United States Court of Appeals for the D.C. Circuit and filed an emergency motion in the United States District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. 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 December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and TRO to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the Tribe. The District Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.

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 rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any 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. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018.

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 auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. 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 is required to file the revised plan with the Court by April 1, 2018. 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 report was filed with the court on December 29, 2017.

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. Briefing on YST’s motion is ongoing.

While we believe that the pending lawsuits are unlikely to halt or suspend the operation of the pipeline, we cannot assure this outcome. We 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) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As ofDecember 31, 2017, Sunoco, Inc. is a defendant insevencases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Fourof these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland.

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. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to 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, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, 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 (the “Regency Litigation 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 the Regency Litigation 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. The Regency Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC.

The Regency Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency 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. Enterprise’s response is due February 26, 2018.

Sunoco Logistics Merger Litigation

Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the Motion to Dismiss, the ETP Unitholder Plaintiffs chose to voluntarily dismiss their claims without prejudice in November 2017.

The ETP-SXL Defendants cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what the outcome of any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger.

Litigation Filed By or Against Williams

On April 6, 2016, Williams filed a complaint, The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG, against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.

On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions.

ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.

After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.

Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Defendants breached an additional representation and warranty in the Merger Agreement.

Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016.

On March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and Order on the June 2016 trial and denied Williams’ motion for reargument on April 5, 2017. As a result of the Delaware Supreme Court’s affirmance, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.

Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.

Unitholder Litigation Relating to the Issuance

In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware (the “Issuance Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016.

The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.

The Issuance Defendants and the Issuance Plaintiffs filed cross-motions for partial summary judgment. On February 28, 2017, the Court denied both motions for partial summary judgment. A trial in the Issuance Litigation is currently set for February 19-21, 2018.

The Issuance Defendants cannot predict the outcome of the Issuance Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendants predict the amount of time and expense that will be required to resolve the Issuance Litigation. The Issuance Defendants believe the Issuance Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Issuance.

Litigation filed by BP Products

On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately$62 million, a figure that BP reduced in subsequent filings to approximately$41 million.

SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.

On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s$13 millionalternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.

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 December 31, 2017 and 2016, accruals of approximately $33 million and $77 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.

No amounts have been recorded in our December 31, 2017 or 2016 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 this year, 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, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief.In short, the DOJ and EPA proposed federal penalties totaling$7 millionfor the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately$1 millionto resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.

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 ofDecember 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 43 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.

	December 31,
	2017		2016
Current	$	35	$	26
Non-current	337		318
Total environmental liabilities	$	372	$	344

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 years ended December 31, 2017 and 2016, the Partnership recorded $32 million and $43 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, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an 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 and 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 its 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.

In January 2012, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. ETP also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of$100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas.  The proposed penalties are in excess of$100,000. The case went to hearing in November 2016 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows, or financial position.

In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of$100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, Occupational Safety and Health 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.

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Retirement Benefits

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

Retirement Benefits

RETIREMENT BENEFITS:

Savings and Profit Sharing Plans

We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETP, Sunoco LP and Lake Charles LNG. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries have made matching contributions of $38 million, $44 million and $40 million to the 401(k) savings plan for the years ended December 31, 2017, 2016, and 2015, respectively.

Pension and Other Postretirement Benefit Plans

Panhandle

Postretirement benefits expense for the years ended December 31, 2017, 2016, and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.

Sunoco, Inc.

Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.

Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.

Obligations and Funded Status

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.

The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:

	December 31, 2017									December 31, 2016
	Pension Benefits									Pension Benefits
	Funded Plans			Unfunded Plans			Other Postretirement Benefits			Funded Plans			Unfunded Plans			Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$	18		$	51		$	166		$	20		$	57		$	181
Interest cost	1			1			4			1			2			4
Amendments	—			—			7			—			—			—
Benefits paid, net	(2		)	(6		)	(20		)	(1		)	(7		)	(21		)
Actuarial (gain) loss and other	2			1			(1		)	(2		)	(1		)	2
Settlements	(18		)	—			—			—			—			—
Benefit obligation at end of period	$	1		$	47		$	156		$	18		$	51		$	166
Change in plan assets:
Fair value of plan assets at beginning of period	$	12		$	—		$	256		$	15		$	—		$	261
Return on plan assets and other	3			—			11			(2		)	—			6
Employer contributions	6			—			10			—			—			10
Benefits paid, net	(2		)	—			(20		)	(1		)	—			(21		)
Settlements	(18		)	—			—			—			—			—
Fair value of plan assets at end of period	$	1		$	—		$	257		$	12		$	—		$	256
Amount underfunded (overfunded) at end of period	$	—		$	47		$	(101	)	$	6		$	51		$	(90	)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$	—		$	—		$	127		$	—		$	—		$	114
Current liabilities	—			(8		)	(2		)	—			(7		)	(2		)
Non-current liabilities	—			(39		)	(24		)	(6		)	(44		)	(23		)
	$	—		$	(47	)	$	101		$	(6	)	$	(51	)	$	89
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Net actuarial gain	$	—		$	5		$	(18	)	$	—		$	—		$	(13	)
Prior service cost	—			—			21			—			—			15
	$	—		$	5		$	3		$	—		$	—		$	2

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:

	December 31, 2017						December 31, 2016
	Pension Benefits						Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits		Funded Plans		Unfunded Plans		Other Postretirement Benefits
Projected benefit obligation	$	1	$	47	N/A		$	18	$	51	N/A
Accumulated benefit obligation	1		47		$	156	18		51		$	166
Fair value of plan assets	1		—		257		12		—		256

Components of Net Periodic Benefit Cost

	December 31, 2017					December 31, 2016
	Pension Benefits		Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Interest cost	$	2	$	4		$	3		$	4
Expected return on plan assets	—		(9		)	(1		)	(8		)
Prior service cost amortization	—		2			—			1
Net periodic benefit cost	$	2	$	(3	)	$	2		$	(3	)

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:

	December 31, 2017				December 31, 2016
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	3.27	%	2.34	%	3.65	%	2.34	%
Rate of compensation increase	N/A		N/A		N/A		N/A

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:

	December 31, 2017				December 31, 2016
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	3.52	%	3.10	%	3.60	%	3.06	%
Expected return on assets:
Tax exempt accounts	3.50	%	7.00	%	3.50	%	7.00	%
Taxable accounts	N/A		4.50	%	N/A		4.50	%
Rate of compensation increase	N/A		N/A		N/A		N/A

The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.

The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:

	December 31,
	2017		2016
Health care cost trend rate	7.20	%	6.73	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.99	%	4.96	%
Year that the rate reaches the ultimate trend rate	2023		2021

Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.

Plan Assets

For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%. 

The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.

The fair value of the pension plan assets by asset category at the dates indicated is as follows:

			Fair Value Measurements at December 31, 2017
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Mutual funds (1)	$	1	$	1	$	—	$	—
Total	$	1	$	1	$	—	$	—

⁽¹⁾ Comprised of 100% equities as of December 31, 2017.

			Fair Value Measurements at December 31, 2016
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Mutual funds (1)	$	12	$	12	$	—	$	—
Total	$	12	$	12	$	—	$	—

⁽¹⁾  Comprised of 100% equities as of December 31, 2016.

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:

			Fair Value Measurements at December 31, 2017
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	33	$	33	$	—	$	—
Mutual funds (1)	154		154		—		—
Fixed income securities	70		—		70		—
Total	$	257	$	187	$	70	$	—

⁽¹⁾ Primarily comprised of approximately 38% equities, 61% fixed income securities and 2% cash as of December 31, 2017.

			Fair Value Measurements at December 31, 2016
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	23	$	23	$	—	$	—
Mutual funds (1)	142		142		—		—
Fixed income securities	91		—		91		—
Total	$	256	$	165	$	91	$	—

⁽¹⁾  Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016.

The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  

Contributions

We expect to contribute $8 million to pension plans and $10 million to other postretirement plans in 2018.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

Benefit Payments

Panhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:

Years	Pension Benefits - Unfunded Plans (1)		Other Postretirement Benefits (Gross, Before Medicare Part D)
2018	$	8	$	24
2019	6		23
2020	6		21
2021	5		19
2022	4		17
2023 – 2027	15		37

⁽¹⁾     Expected benefit payments of funded pension plans are less than $1 million for the next ten years.

The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

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Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS:

In June 2017, ETP acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8.

ETE previously paid ETP to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016.

In addition, subsidiaries of ETE recorded sales with affiliates of $303 million, $221 million and $290 million during the years ended December 31, 2017, 2016 and 2015, respectively.

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Reportable Segments

12 Months Ended

Dec. 31, 2017

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS:

Subsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the following:

• activities of the Parent Company; and

• the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.

The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.

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 (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.

Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

Eliminations in the tables below include the following:

• MACS, Sunoco LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP, as discussed above.

	Years Ended December 31,
	2017			2016			2015
Revenues:
Investment in ETP:
Revenues from external customers	$	28,613		$	21,618		$	34,156
Intersegment revenues	441			209			136
	29,054			21,827			34,292
Investment in Sunoco LP:
Revenues from external customers	11,713			9,977			12,419
Intersegment revenues	10			9			11
	11,723			9,986			12,430
Investment in Lake Charles LNG:
Revenues from external customers	197			197			216
Adjustments and Eliminations:	(451		)	(218		)	(10,842		)
Total revenues	$	40,523		$	31,792		$	36,096
Costs of products sold:
Investment in ETP	$	20,801		$	15,080		$	26,714
Investment in Sunoco LP	10,615			8,830			11,450
Adjustments and Eliminations	(450		)	(217		)	(9,496		)
Total costs of products sold	$	30,966		$	23,693		$	28,668
Depreciation, depletion and amortization:
Investment in ETP	$	2,332		$	1,986		$	1,929
Investment in Sunoco LP	169			176			150
Investment in Lake Charles LNG	39			39			39
Corporate and Other	14			15			17
Adjustments and Eliminations	—			—			(184		)
Total depreciation, depletion and amortization	$	2,554		$	2,216		$	1,951

	Years Ended December 31,
	2017			2016		2015
Equity in earnings of unconsolidated affiliates:
Investment in ETP	$	156		$	59	$	469
Adjustments and Eliminations	(12		)	211		(193		)
Total equity in earnings of unconsolidated affiliates	$	144		$	270	$	276

	Years Ended December 31,
	2017			2016			2015
Segment Adjusted EBITDA:
Investment in ETP	$	6,712		$	5,733		$	5,517
Investment in Sunoco LP	732			665			719
Investment in Lake Charles LNG	175			179			196
Corporate and Other	(31		)	(170		)	(104		)
Adjustments and Eliminations	(268		)	(272		)	(590		)
Total Segment Adjusted EBITDA	7,320			6,135			5,738
Depreciation, depletion and amortization	(2,554		)	(2,216		)	(1,951		)
Interest expense, net of interest capitalized	(1,922		)	(1,804		)	(1,622		)
Gains on acquisitions	—			83			—
Impairment of investments in unconsolidated affiliates	(313		)	(308		)	—
Impairment losses	(1,039		)	(1,040		)	(339		)
Losses on interest rate derivatives	(37		)	(12		)	(18		)
Non-cash unit-based compensation expense	(99		)	(70		)	(91		)
Unrealized gains (losses) on commodity risk management activities	59			(136		)	(65		)
Losses on extinguishments of debt	(89		)	—			(43		)
Inventory valuation adjustments	24			97			(67		)
Adjusted EBITDA related to discontinued operations	(223		)	(199		)	(228		)
Adjusted EBITDA related to unconsolidated affiliates	(716		)	(675		)	(713		)
Equity in earnings of unconsolidated affiliates	144			270			276
Other, net	155			79			23
Income from continuing operations before income tax benefit	$	710		$	204		$	900
Income tax benefit from continuing operations	(1,833		)	(258		)	(123		)
Income from continuing operations	2,543			462			1,023
Income (loss) from discontinued operations, net of tax	(177		)	(462		)	38
Net income	$	2,366		$	—		$	1,061

	December 31,
	2017			2016			2015
Total assets:
Investment in ETP	$	77,965		$	70,105		$	65,128
Investment in Sunoco LP	8,344			8,701			8,842
Investment in Lake Charles LNG	1,646			1,508			1,369
Corporate and Other	598			711			638
Adjustments and Eliminations	(2,307		)	(2,100		)	(4,833		)
Total	$	86,246		$	78,925		$	71,144

	Years Ended December 31,
	2017		2016		2015
Additions to property, plant and equipment, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):
Investment in ETP	$	5,901	$	5,810	$	8,167
Investment in Sunoco LP	103		119		178
Investment in Lake Charles LNG	2		—		1
Adjustments and Eliminations	—		—		(123		)
Total	$	6,006	$	5,929	$	8,223

	December 31,
	2017			2016			2015
Advances to and investments in affiliates:
Investment in ETP	$	3,816		$	4,280		$	5,003
Adjustments and Eliminations	(1,111		)	(1,240		)	(1,541		)
Total	$	2,705		$	3,040		$	3,462

The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP.

Investment in ETP

	Years Ended December 31,
	2017		2016		2015
Intrastate Transportation and Storage	$	2,891	$	2,155	$	1,912
Interstate Transportation and Storage	915		946		1,008
Midstream	2,510		2,342		2,607
NGL and refined products transportation and services	8,326		5,973		4,569
Crude oil transportation and services	11,672		7,539		8,980
All Other	2,740		2,872		15,216
Total revenues	29,054		21,827		34,292
Less: Intersegment revenues	441		209		136
Revenues from external customers	$	28,613	$	21,618	$	34,156

Investment in Sunoco LP

	Years Ended December 31,
	2017		2016		2015
Retail operations	$	2,263	$	1,991	$	2,226
Wholesale operations	9,460		7,995		10,204
Total revenues	11,723		9,986		12,430
Less: Intersegment revenues	10		9		11
Revenues from external customers	$	11,713	$	9,977	$	12,419

Investment in Lake Charles LNG

Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 2015, respectively, were related to LNG terminalling.

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Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year.

	Quarters Ended
	March 31*		June 30*		September 30*		December 31		Total Year
2017:
Revenues	$	9,660	$	9,427	$	9,984	$	11,452	$	40,523
Operating income (loss)	758		746		924		285		2,713
Net income (loss)	319		121		758		1,168		2,366
Limited Partners’ interest in net income	232		204		240		239		915
Basic net income per limited partner unit	$	0.22	$	0.18	$	0.22	$	0.22	$	0.85
Diluted net income per limited partner unit	$	0.21	$	0.18	$	0.22	$	0.22	$	0.83

	Quarters Ended
	March 31*		June 30*		September 30*			December 31*			Total Year*
2016:
Revenues	$	6,447	$	7,866	$	8,156		$	9,323		$	31,792
Operating income	680		814		624			(275		)	1,843
Net income (loss)	320		417		(3		)	(734		)	—
Limited Partners’ interest in net income	311		239		207			226			983
Basic net income per limited partner unit	$	0.30	$	0.23	$	0.20		$	0.22		$	0.94
Diluted net income per limited partner unit	$	0.30	$	0.23	$	0.19		$	0.21		$	0.92

* As adjusted. See Note 2 and Note 3. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.

The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $1.04 billion, respectively. Impairment losses in 2017 were primarily related to ETP’s interstate transportation and storage operations, NGL and refined products operations and other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its interstate transportation and storage operations.

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Supplemental Financial Statement Information

12 Months Ended

Dec. 31, 2017

Supplemental Financial Statement Information

Supplemental Financial Statement Information

SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

BALANCE SHEETS

	December 31,
	2017			2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1		$	2
Accounts receivable from related companies	65			55
Other current assets	1			—
Total current assets	67			57
PROPERTY, PLANT AND EQUIPMENT, net	27			36
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	6,082			5,088
INTANGIBLE ASSETS, net	—			1
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	8			10
Total assets	$	6,193		$	5,201
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	—		$	1
Accounts payable to related companies	—			22
Interest payable	66			66
Accrued and other current liabilities	4			3
Total current liabilities	70			92
LONG-TERM DEBT, less current maturities	6,700			6,358
NOTE PAYABLE TO AFFILIATE	617			443
OTHER NON-CURRENT LIABILITIES	2			2
COMMITMENTS AND CONTINGENCIES
PARTNERS’ DEFICIT:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)	(1,643		)	(1,871		)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)	450			180
Total partners’ deficit	(1,196		)	(1,694		)
Total liabilities and partners’ deficit	$	6,193		$	5,201

STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2017			2016			2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(31	)	$	(185	)	$	(112	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(347		)	(327		)	(294		)
Equity in earnings of unconsolidated affiliates	1,381			1,511			1,601
Loss on extinguishment of debt	(47		)	—			—
Other, net	(2		)	(4		)	(5		)
INCOME BEFORE INCOME TAXES	954			995			1,190
Income tax expense	—			—			1
NET INCOME	954			995			1,189
General Partner’s interest in net income	2			3			3
Convertible Unitholders’ interest in income	37			9			—
Class D Unitholder’s interest in net income	—			—			3
Limited Partners’ interest in net income	$	915		$	983		$	1,183

STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2017			2016			2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	831		$	918		$	1,103
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Bakken Pipeline Transaction	—			—			(817		)
Contributions to unconsolidated affiliates	(861		)	(70		)	—
Capital expenditures	(1		)	(16		)	(19		)
Contributions in aid of construction costs	7			—			—
Net cash used in investing activities	(855		)	(86		)	(836		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,219			225			3,672
Principal payments on debt	(1,881		)	(210		)	(1,985		)
Distributions to partners	(1,010		)	(1,022		)	(1,090		)
Proceeds from affiliate	174			176			210
Common Units issued for cash	568			—			—
Units repurchased under buyback program	—			—			(1,064		)
Debt issuance costs	(47		)	—			(11		)
Net cash provided by (used in) financing activities	23			(831		)	(268		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(1		)	1			(1		)
CASH AND CASH EQUIVALENTS, beginning of period	2			1			2
CASH AND CASH EQUIVALENTS, end of period	$	1		$	2		$	1

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Estimates, Significant Accounting Policies and Balance Sheet Detail (Policy)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Accounting Changes and Error Corrections [Text Block]

Change in Accounting Policy

During the fourth quarter of 2017, ETP 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 product and NGL associated with the legacy Sunoco Logistics business. ETP’s 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.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

New Accounting Pronouncements, Policy [Policy Text Block]

Recent Accounting Pronouncements

ASU 2014-09

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. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.

For future periods, ETP expects that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of its midstream agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.

We have determined that the timing and/or amount of revenue that we recognize on certain contracts associated with Sunoco LP’s operations will be impacted by the adoption of the new standard. We currently estimate the cumulative catch-up effect to Sunoco LP’s retained earnings as of January 1, 2018 to be approximately $54 million. These adjustments are primarily related to the change in recognition of dealer incentives and rebates.

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. The Partnership expects to adopt ASU 2016-02 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 2016-16

On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.

ASU 2017-04

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

ASU 2017-12

In August 2017, the FASB issued ASU 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.

Revenue Recognition

Revenue Recognition

Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.

Investment in ETP

Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.

The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.

ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead.

In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which ETP operate, competitive factors in the energy industry, and other issues.

Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and segment margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.

ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.

In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.

ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

Investment in Sunoco LP

Revenues from Sunoco LP’s two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Sunoco LP may sell motor fuel to wholesale customers on a commission agent basis, in which Sunoco LP retains title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. Sunoco LP derives other income from rental income, propane and lubricating oils and other ancillary product and service offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals and other ancillary product and service offerings. Sunoco LP records revenue on a net commission basis when the product is sold and/or services are rendered. Rental income from operating leases is recognized on a straight line basis over the term of the lease.

Investment in Lake Charles LNG

Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal.

Regulatory Accounting - Regulatory Assets and Liabilities

Regulatory Accounting – Regulatory Assets and Liabilities

ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of ETP’s regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, ETP ceases to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the NGA and NGPA, it does not currently apply regulatory accounting policies in accounting for its operations.  Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash, Cash Equivalents and Supplemental Cash Flow Information

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

Accounts Receivable

Accounts Receivable

Our subsidiaries assess the credit risk of their customers and take steps to mitigate risk as necessary. Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and identification of specific customers with payment issues.

Inventories

Inventories

As discussed under “Change in Accounting Policy” in Note 2, ETP changed its accounting policy for certain inventory in the fourth quarter of 2017.

Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Inventories consisted of the following:

	December 31,
	2017		2016
Natural gas, NGLs, and refined products	$	1,120	$	1,141
Crude oil	551		651
Spare parts and other	351		263
Total inventories	$	2,022	$	2,055

ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.

Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.

In 2017, ETP recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, ETP recorded a $133 million fixed asset impairment related to its interstate transportation and storage operations primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in its midstream operations. In 2015, ETP recorded a $110 million fixed asset impairment related to its NGL and refined products transportation and services operations primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for its reporting units during the periods presented.

Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Equity and Cost Method Investments, Policy [Policy Text Block]

Advances to and Investments in Affiliates

Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies.

Other Non-Current Assets, net

Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization.

Intangible Assets

Intangible Assets

Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.

Components and useful lives of intangible assets were as follows:

	December 31, 2017					December 31, 2016
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	6,979	$	(1,277	)	$	6,050	$	(971	)
Trade names (20 years)	66		(25		)	66		(22		)
Patents (10 years)	48		(26		)	48		(21		)
Other (5 to 20 years)	28		(14		)	25		(10		)
Total amortizable intangible assets	7,121		(1,342		)	6,189		(1,024		)
Non-amortizable intangible assets:
Trademarks	295		—			288		—
Other	42		—			59		—
Total intangible assets	$	7,458	$	(1,342	)	$	6,536	$	(1,024	)

Aggregate amortization expense of intangibles assets was as follows:

	Years Ended December 31,
	2017		2016		2015
Reported in depreciation, depletion and amortization	$	344	$	264	$	290

Estimated aggregate amortization expense of intangible assets for the next five years was as follows:

Years Ending December 31:
2018	$	341
2019	338
2020	336
2021	319
2022	287

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

Sunoco LP performed impairment tests on their indefinite-lived intangible assets during the fourth quarter of 2017 and recognized $13 million and $4 million impairment charge on their contractual rights and liquor licenses, included in Other in the table above, primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded.

In 2015, ETP recorded $24 million of intangible asset impairments related to its NGL and retail products transportation and services operations primarily due to an expected decrease in future cash flows.

Goodwill

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

Changes in the carrying amount of goodwill were as follows:

	Investment in ETP			Investment in Sunoco LP			Investment in Lake Charles LNG		Corporate, Other and Eliminations			Total
Balance, December 31, 2015	$	5,428		$	1,694		$	184	$	(1,250	)	$	6,056
Goodwill acquired	428			81			—		—			509
Sunoco LP Exchange	(1,289		)	—			—		1,289			—
Goodwill impairment	(670		)	(227		)	—		—			(897		)
Other	—			2			—		—			2
Balance, December 31, 2016	3,897			1,550			184		39			5,670
Goodwill acquired	12			—			—		—			12
Goodwill impairment	(793		)	(102		)	—		—			(895		)
Other	(1		)	(18		)	—		—			(19		)
Balance, December 31, 2017	$	3,115		$	1,430		$	184	$	39		$	4,768

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.

During the fourth quarter of 2017, ETP recognized goodwill impairments of $262 million in its interstate transportation and storage operations, $79 million in its NGL and refined products transportation and services operations and $452 million in its all other operations primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. Sunoco LP recognized goodwill impairments of $387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.

During the fourth quarter of 2016, ETP recognized goodwill impairments of $638 million in its interstate transportation and storage operations and $32 million in its midstream operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. Sunoco LP recognized goodwill impairments of $641 million, of which $227 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.

During the fourth quarter of 2015, ETP recognized goodwill impairments of $99 million in its interstate transportation and storage operations and $106 million in its NGL and refined products transportation and services operations primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.

The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

Asset Retirement Obligations

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.

Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as ofDecember 31, 2017and2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

As of December 31, 2017 and 2016, other non-current liabilities in ETP’s consolidated balance sheets included AROs of $165 million and $170 million, respectively.

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

Long-lived assets related to AROs aggregated to $2 million and $14 million, and were reflected as property, plant and equipment on our consolidated balance sheets as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.

All amounts recorded in our consolidated balance sheets as of December 31, 2017 and 2016 are attributab

Asset Retirement Obligation

Asset Retirement Obligations

We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.

Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as ofDecember 31, 2017and2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

As of December 31, 2017 and 2016, other non-current liabilities in ETP’s consolidated balance sheets included AROs of $165 million and $170 million, respectively.

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.

Accrued and Other Current Liabilities Policy [Text Block]

Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interest [Text Block]

Redeemable Noncontrolling Interests

The noncontrolling interest holders in one of ETP’s consolidated subsidiaries have the option to sell their interests to ETP.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheet.

Environmental Costs, Policy [Policy Text Block]

Environmental Remediation

We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.

Fair Value of Financial Instruments

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.

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 December 31, 2017 was $45.62 billion and $44.08 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations was $45.05 billion and $43.80 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

Contributions In Aid Of Construction Costs Policy Text Block

Contributions in Aid of Construction Cost

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.

Shipping and Handling Costs

Shipping and Handling Costs

Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

Costs and Expenses

Costs and Expenses

Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by Sunoco LP’s retail locations where Sunoco LP holds the inventory were $234 million, $243 million and $231 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Issuances of Subsidiary Units

Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiaries’ issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.

Income Taxes

Income Taxes

ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).

As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, and 2015, our qualifying income met the statutory requirement.

The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.

The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.

Accounting for Derivative Instruments and Hedging Activities

Accounting for Derivative Instruments and Hedging Activities

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

Unit-Based Compensation

For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.

Pension and Other Postretirement Plans, Policy [Policy Text Block]

Pensions and Other Postretirement Benefit Plans

ETP recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.  Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.

Allocation of Income (Loss)

Allocation of Income

For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

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Estimates, Significant Accounting Policies and Balance Sheet Detail (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Schedule of Change in Accounting Estimate [Table Text Block]

Change in Accounting Policy

During the fourth quarter of 2017, ETP 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 product and NGL associated with the legacy Sunoco Logistics business. ETP’s management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

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

	Year Ended December 31, 2016									Year Ended December 31, 2015
	As Originally Reported*			Effect of Change			As Adjusted			As Originally Reported*			Effect of Change			As Adjusted
Consolidated Statement of Operations and Comprehensive Income:
Cost of products sold	$	23,652		$	41		$	23,693		$	28,636		$	32		$	28,668
Operating income	1,884			(41		)	1,843			2,319			(32		)	2,287
Income from continuing operations before income tax benefit	245			(41		)	204			932			(32		)	900
Net income	41			(41		)	—			1,093			(32		)	1,061
Net income (loss) attributable to noncontrolling interest	(954		)	(41		)	(995		)	(96		)	(32		)	(128		)
Comprehensive income	45			(41		)	4			1,153			(32		)	1,121
Consolidated Statements of Cash Flows:
Net income	41			(41		)	—			1,093			(32		)	1,061
Inventory valuation adjustments	(267		)	170			(97		)	229			(162		)	67
Net change in operating assets and liabilities (change in inventories)	(50		)	(129		)	(179		)	(1,066		)	194			(872		)
Consolidated Balance Sheets (at period end):
Inventories	2,141			(86		)	2,055			1,498			(45		)	1,453
Noncontrolling interest	24,211			(86		)	24,125			24,530			(45		)	24,485

Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities

The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:

	Years Ended December 31,
	2017			2016			2015
Accounts receivable	$	(948	)	$	(1,126	)	$	856
Accounts receivable from related companies	24			42			(5		)
Inventories	58			(480		)	(212		)
Other current assets	38			165			(225		)
Other non-current assets, net	84			(148		)	247
Accounts payable	712			1,170			(1,070		)
Accounts payable to related companies	(178		)	(64		)	400
Accrued and other current liabilities	(97		)	89			(697		)
Other non-current liabilities	106			106			(241		)
Derivative assets and liabilities, net	9			67			75
Net change in operating assets and liabilities, net of effects of acquisitions	$	(192	)	$	(179	)	$	(872	)

Schedule Of Non-Cash Investing And Financing Activities

Non-cash investing and financing activities and supplemental cash flow information were as follows:

	Years Ended December 31,
	2017			2016			2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,060		$	848		$	910
Net gains (losses) from subsidiary common unit transactions	(56		)	16			(526		)
NON-CASH FINANCING ACTIVITIES:
Issuance of Common Units in connection with the PennTex Acquisition	$	—		$	307		$	—
Contribution of assets from noncontrolling interest	988			—			34
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	1,914		$	1,922		$	1,800
Cash paid for (refund of) income taxes	50			(229		)	72

Schedule of Inventory

Inventories consisted of the following:

	December 31,
	2017		2016
Natural gas, NGLs, and refined products	$	1,120	$	1,141
Crude oil	551		651
Spare parts and other	351		263
Total inventories	$	2,022	$	2,055

Other Current Assets

Other current assets consisted of the following:

	December 31,
	2017		2016
Deposits paid to vendors	$	64	$	74
Prepaid expenses and other	231		373
Total other current assets	$	295	$	447

Property, Plant and Equipment

Components and useful lives of property, plant and equipment were as follows:

	December 31,
	2017			2016
Land and improvements	$	2,222		$	1,189
Buildings and improvements (1 to 45 years)	2,786			2,247
Pipelines and equipment (5 to 83 years)	44,673			36,570
Natural gas and NGL storage facilities (5 to 46 years)	1,681			1,451
Bulk storage, equipment and facilities (2 to 83 years)	3,883			3,701
Vehicles (1 to 25 years)	126			217
Right of way (20 to 83 years)	3,432			3,349
Natural resources	434			434
Other (1 to 40 years)	1,029			2,285
Construction work-in-process	10,911			10,119
	71,177			61,562
Less – Accumulated depreciation and depletion	(10,089		)	(7,984		)
Property, plant and equipment, net	$	61,088		$	53,578

Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense

We recognized the following amounts for the periods presented:

	Years Ended December 31,
	2017		2016		2015
Depreciation and depletion expense	$	2,204	$	1,952	$	1,661
Capitalized interest	286		201		164

Schedule of Other Non-Current Assets, net

Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:

	December 31,
	2017		2016
Regulatory assets	85		86
Deferred charges	210		217
Restricted funds	192		190
Other	399		322
Total other non-current assets, net	$	886	$	815

Components And Useful Lives Of Intangibles And Other Assets

Components and useful lives of intangible assets were as follows:

	December 31, 2017					December 31, 2016
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	6,979	$	(1,277	)	$	6,050	$	(971	)
Trade names (20 years)	66		(25		)	66		(22		)
Patents (10 years)	48		(26		)	48		(21		)
Other (5 to 20 years)	28		(14		)	25		(10		)
Total amortizable intangible assets	7,121		(1,342		)	6,189		(1,024		)
Non-amortizable intangible assets:
Trademarks	295		—			288		—
Other	42		—			59		—
Total intangible assets	$	7,458	$	(1,342	)	$	6,536	$	(1,024	)

Aggregate Amortization Expense Of Intangibles And Other Assets

Aggregate amortization expense of intangibles assets was as follows:

	Years Ended December 31,
	2017		2016		2015
Reported in depreciation, depletion and amortization	$	344	$	264	$	290

Estimated Aggregate Amortization Expense

Estimated aggregate amortization expense of intangible assets for the next five years was as follows:

Years Ending December 31:
2018	$	341
2019	338
2020	336
2021	319
2022	287

Schedule of Goodwill

Changes in the carrying amount of goodwill were as follows:

	Investment in ETP			Investment in Sunoco LP			Investment in Lake Charles LNG		Corporate, Other and Eliminations			Total
Balance, December 31, 2015	$	5,428		$	1,694		$	184	$	(1,250	)	$	6,056
Goodwill acquired	428			81			—		—			509
Sunoco LP Exchange	(1,289		)	—			—		1,289			—
Goodwill impairment	(670		)	(227		)	—		—			(897		)
Other	—			2			—		—			2
Balance, December 31, 2016	3,897			1,550			184		39			5,670
Goodwill acquired	12			—			—		—			12
Goodwill impairment	(793		)	(102		)	—		—			(895		)
Other	(1		)	(18		)	—		—			(19		)
Balance, December 31, 2017	$	3,115		$	1,430		$	184	$	39		$	4,768

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	December 31,
	2017		2016
Interest payable	$	552	$	545
Customer advances and deposits	59		72
Accrued capital expenditures	1,006		769
Accrued wages and benefits	280		254
Taxes payable other than income taxes	108		201
Income taxes payable	180		—
Exchanges payable	154		208
Other	243		318
Total accrued and other current liabilities	$	2,582	$	2,367

Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2017 and 2016 based on inputs used to derive their fair values:

				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			—
Refined Products – Futures	1			1			—
Crude – Futures	2			2			—
Total commodity derivatives	321			277			44
Other non-current assets	21			14			7
Total assets	$	342		$	291		$	51
Liabilities:
Interest rate derivatives	$	(219	)	$	—		$	(219	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(24		)	(24		)	—
Swing Swaps IFERC	(15		)	(1		)	(14		)
Fixed Swaps/Futures	(57		)	(57		)	—
Forward Physical Swaps	(2		)	—			(2		)
Power — Forwards	(22		)	—			(22		)
Natural Gas Liquids — Forwards/Swaps	(192		)	(192		)
Refined Products – Futures	(28		)	(28		)	—
Crude — Futures	(1		)	(1		)	—
Total commodity derivatives	(341		)	(303		)	(38		)
Total liabilities	$	(560	)	$	(303	)	$	(257	)

				Fair Value Measurements at
				December 31, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	14		$	14		$	—		$	—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	96			96			—			—
Forward Physical Contracts	1			—			1			—
Power:
Forwards	4			—			4			—
Futures	1			1			—			—
Options — Calls	1			1			—			—
Natural Gas Liquids — Forwards/Swaps	233			233			—			—
Refined Products – Futures	2			2			—			—
Crude – Futures	9			9			—			—
Total commodity derivatives	363			356			7			—
Other non-current assets	13			8			5			—
Total assets	$	376		$	364		$	12		$	—
Liabilities:
Interest rate derivatives	$	(193	)	$	—		$	(193	)	$	—
Embedded derivatives in the ETP Convertible Preferred Units	(1		)	—			—			(1		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(11		)	(11		)	—			—
Swing Swaps IFERC	(3		)	—			(3		)	—
Fixed Swaps/Futures	(149		)	(149		)	—			—
Power:
Forwards	(5		)				(5		)	—
Futures	(1		)	(1		)	—			—
Natural Gas Liquids — Forwards/Swaps	(273		)	(273		)	—			—
Refined Products – Futures	(23		)	(23		)	—			—
Crude — Futures	(13		)	(13		)	—			—
Total commodity derivatives	(478		)	(470		)	(8		)	—
Total liabilities	$	(672	)	$	(470	)	$	(201	)	$	(1	)

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Acquisitions and Related Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Disposal Groups, Including Discontinued Operations [Table Text Block]

The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet:

	December 31, 2017		December 31, 2016
Carrying amount of assets included as part of discontinued operations:
Accounts receivable, net	$	21	$	16
Inventories	149		150
Other current assets	16		11
Property and equipment, net	1,851		1,860
Goodwill	796		1,068
Intangible assets, net	477		480
Other noncurrent assets	3		3
Total assets classified as held for sale in the Consolidated Balance Sheet	$	3,313	$	3,588
Carrying amount of liabilities included as part of discontinued operations:
Other current and noncurrent liabilities	$	75	$	48
Total liabilities classified as held for sale in the Consolidated Balance Sheet	$	75	$	48

The results of operations associated with discontinued operations are presented in the following table:

	Years Ended December 31,
	2017			2016			2015
REVENUES	$	6,964		$	5,712		$	6,030
COSTS AND EXPENSES
Cost of products sold	5,806			4,649			5,026
Operating expenses	763			744			705
Depreciation, depletion and amortization	34			143			128
Selling, general and administrative	168			114			91
Impairment losses	285			447			—
Total costs and expenses	7,056			6,097			5,950
OPERATING INCOME	(92		)	(385		)	80
Interest expense, net	36			28			21
Other, net	1			8			(2		)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE	(129		)	(421		)	61
Income tax expense	48			41			23
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(177	)	$	(462	)	$	38
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE	$	(6	)	$	(12	)	$	1

PennTex [Member]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The total purchase price was allocated as follows:

	At November 1, 2016
Total current assets	$	34
Property, plant and equipment	393
Goodwill(1)	177
Intangible assets	446
	1,050
Total current liabilities	6
Long-term debt, less current maturities	164
Other non-current liabilities	17
Noncontrolling interest	236
	423
Total consideration	627
Cash received	21
Total consideration, net of cash received	$	606

⁽¹⁾  None of the goodwill is expected to be deductible for tax purposes.

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Advances to and Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2017

Investment In Affiliates [Abstract]

Schedule Of Aggregated Selected Balance Sheet And Income Statement Data For Our Unconsolidated Affiliates

The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2017 and 2016, were as follows:

	December 31,
	2017		2016
Citrus	$	1,754	$	1,729
FEP	121		101
MEP	242		318
HPC	28		382
Others	560		510
Total	$	2,705	$	3,040

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented:

	December 31,
	2017		2016
Current assets	$	206	$	214
Property, plant and equipment, net	8,336		8,726
Other assets	43		181
Total assets	$	8,585	$	9,121
Current liabilities	$	861	$	816
Non-current liabilities	4,492		4,940
Equity	3,232		3,365
Total liabilities and equity	$	8,585	$	9,121

	Years Ended December 31,
	2017		2016		2015
Revenue	$	1,358	$	1,164	$	1,385
Operating income	407		714		800
Net income	145		384		470

In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant to our consolidated financial statements.

Schedule of Investments in and Advances to Affiliates, Schedule of Investments [Table Text Block]

The following table presents equity in earnings (losses) of unconsolidated affiliates:

	December 31,
Equity in earnings (losses) of unconsolidated affiliates:	2017			2016		2015
Citrus	$	144		$	102	$	97
FEP	53			51		55
MEP	38			40		45
HPC(1)	(168		)	31		32
Others	77			46		47
Total	$	144		$	270	$	276

⁽¹⁾  For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.

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Net Income Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Reconciliation Of Net Income (Loss) And Weighted Average Units

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

	Years Ended December 31,
	2017			2016			2015
Income from continuing operations	$	2,543		$	462		$	1,023
Less: Income (loss) from continuing operations attributable to noncontrolling interest	1,583			(545		)	(165		)
Income from continuing operations, net of noncontrolling interest	960			1,007			1,188
Less: General Partner’s interest in income from continuing operations	2			3			3
Less: Convertible Unitholders’ interest in net income from continuing operations	38			8			—
Less: Class D Unitholder’s interest in income from continuing operations	—			—			3
Income from continuing operations available to Limited Partners	$	920		$	996		$	1,182
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,078.2			1,045.5			1,062.8
Basic income from continuing operations per Limited Partner unit	$	0.86		$	0.95		$	1.11
Basic income (loss) from discontinued operations per Limited Partner unit	$	(0.01	)	$	(0.01	)	$	—
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	920		$	996		$	1,182
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units	38			8			3
Diluted income from continuing operations available to Limited Partners	958			1,004			1,185
Weighted average limited partner units	1,078.2			1,045.5			1,062.8
Dilutive effect of unconverted unit awards and Convertible Units	72.6			33.1			1.6
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	1,150.8			1,078.6			1,064.4
Diluted income from continuing operations per Limited Partner unit	$	0.84		$	0.93		$	1.11
Diluted income (loss) from discontinued operations per Limited Partner unit	$	(0.01	)	$	(0.01	)	$	—

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Debt Obligations Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Debt Obligations [Abstract]

Schedule of debt obligations

Our debt obligations consist of the following:

	December 31,
	2017			2016
Parent Company Indebtedness:
7.50% Senior Notes due October 15, 2020	$	1,187		$	1,187
5.875% Senior Notes due January 15, 2024	1,150			1,150
5.50% Senior Notes due June 1, 2027	1,000			1,000
4.25% Senior Notes due March 15, 2023	1,000			—
ETE Senior Secured Term Loan due December 2, 2019	—			2,190
ETE Senior Secured Term Loan due February 2, 2024	1,220			—
ETE Senior Secured Revolving Credit Facility due December 18, 2018	—			875
ETE Senior Secured Revolving Credit Facility due March 24, 2022	1,188			—
Unamortized premiums, discounts and fair value adjustments, net	(11		)	(15		)
Deferred debt issuance costs	(34		)	(30		)
	6,700			6,357
Subsidiary Indebtedness:
ETP Debt
6.125% Senior Notes due February 15, 2017	—			400
2.50% Senior Notes due June 15, 2018 (1)	650			650
6.70% Senior Notes due July 1, 2018 (1)	600			600
9.70% Senior Notes due March 15, 2019	400			400
9.00% Senior Notes due April 15, 2019	450			450
5.50% Senior Notes due February 15, 2020	250			250
5.75% Senior Notes due September 1, 2020	400			400
4.15% Senior Notes due October 1, 2020	1,050			1,050
4.40% Senior Notes due April 1, 2021	600			600
6.50% Senior Notes due July 15, 2021	—			500
4.65% Senior Notes due June 1, 2021	800			800
5.20% Senior Notes due February 1, 2022	1,000			1,000
4.65% Senior Notes due February 15, 2022	300			300
5.875% Senior Notes due March 1, 2022	900			900
5.00% Senior Notes due October 1, 2022	700			700
3.45% Senior Notes due January 15, 2023	350			350
3.60% Senior Notes due February 1, 2023	800			800
5.50% Senior Notes due April 15, 2023	—			700
4.50% Senior Notes due November 1, 2023	600			600
4.90% Senior Notes due February 1, 2024	350			350
7.60% Senior Notes due February 1, 2024	277			277
4.25% Senior Notes due April 1, 2024	500			500
9.00% Debentures due November 1, 2024	65			65
4.05% Senior Notes due March 15, 2025	1,000			1,000
5.95% Senior Notes due December 1, 2025	400			400
4.75% Senior Notes due January 15, 2026	1,000			1,000
3.90% Senior Notes due July 15, 2026	550			550
4.20% Senior Notes due April 15, 2027	600			—
4.00% Senior Notes due October 1, 2027	750			—
8.25% Senior Notes due November 15, 2029	267			267
4.90% Senior Notes due March 15, 2035	500			500
6.625% Senior Notes due October 15, 2036	400			400
7.50% Senior Notes due July 1, 2038	550			550
6.85% Senior Notes due February 15, 2040	250			250
6.05% Senior Notes due June 1, 2041	700			700
6.50% Senior Notes due February 1, 2042	1,000			1,000
6.10% Senior Notes due February 15, 2042	300			300

4.95% Senior Notes due January 15, 2043	350		350
5.15% Senior Notes due February 1, 2043	450		450
5.95% Senior Notes due October 1, 2043	450		450
5.30% Senior Notes due April 1, 2044	700		700
5.15% Senior Notes due March 15, 2045	1,000		1,000
5.35% Senior Notes due May 15, 2045	800		800
6.125% Senior Notes due December 15, 2045	1,000		1,000
5.30% Senior Notes due April 15, 2047	900		—
5.40% Senior Notes due October 1, 2047	1,500		—
Floating Rate Junior Subordinated Notes due November 1, 2066	546		546
ETP $4.0 billion Revolving Credit Facility due December 2022	2,292		—
ETP $1.0 billion 364-Day Credit Facility due November 2018 (2)	50		—
ETLP $3.75 billion Revolving Credit Facility due November 2019	—		2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020	—		1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017	—		630
Unamortized premiums, discounts and fair value adjustments, net	33		66
Deferred debt issuance costs	(170	)	(166	)
	29,210		29,454
Transwestern Debt
5.64% Senior Notes due May 24, 2017	—		82
5.36% Senior Notes due December 9, 2020	175		175
5.89% Senior Notes due May 24, 2022	150		150
5.66% Senior Notes due December 9, 2024	175		175
6.16% Senior Notes due May 24, 2037	75		75
Deferred debt issuance costs	(1	)	(1	)
	574		656
Panhandle Debt
6.20% Senior Notes due November 1, 2017	—		300
7.00% Senior Notes due June 15, 2018	400		400
8.125% Senior Notes due June 1, 2019	150		150
7.60% Senior Notes due February 1, 2024	82		82
7.00% Senior Notes due July 15, 2029	66		66
8.25% Senior Notes due November 14, 2029	33		33
Floating Rate Junior Subordinated Notes due November 1, 2066	54		54
Unamortized premiums, discounts and fair value adjustments, net	28		50
	813		1,135
Sunoco, Inc. Debt
5.75% Senior Notes due January 15, 2017	—		400
Bakken Project Debt
Bakken Project $2.50 billion Credit Facility due August 2019	2,500		1,100
Deferred debt issuance costs	(8	)	(13	)
	2,492		1,087
PennTex Debt
PennTex $275 million Revolving Credit Facility due December 2019	—		168
Sunoco LP Debt
5.50% Senior Notes due August 1, 2020	600		600
6.375% Senior Notes due April 1, 2023	800		800
6.25% Senior Notes due April 15, 2021	800		800
Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019	765		1,000
Sunoco LP Term Loan due October 1, 2019	1,243		1,243
Lease-related obligations	113		118
Deferred debt issuance costs	(34	)	(47	)
	4,287		4,514

Other	8		31
Total debt	44,084		43,802
Less: current maturities of long-term debt	413		1,194
Long-term debt, less current maturities	$	43,671	$	42,608

⁽¹⁾  As of December 31, 2017 ETP’s management had the intent and ability to refinance the$650 million2.50%senior notes due June 15, 2018 and the$600 million6.70%senior notes due July 1, 2018, and therefore neither was classified as current.

Future maturities of long-term debt

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $197 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net:

2018	$	1,705
2019	5,512
2020	3,667
2021	2,205
2022	6,540
Thereafter	24,652
Total	$	44,281

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Equity (Tables)

12 Months Ended

Dec. 31, 2017

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

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

	Total Year
2018	$	153
2019	128
Each year beyond 2019	33

Change In ETE Common Units

The change in ETE Common Units during the years ended December 31, 2017, 2016 and 2015 was as follows:

	Years Ended December 31,
	2017	2016	2015
Number of Common Units, beginning of period	1,046.9	1,044.8	1,077.5
Conversion of Class D Units to ETE Common Units	—	—	0.9
Repurchase of common units under buyback program	—	—	(33.6	)
Issuance of common units	32.2	2.1	—
Number of Common Units, end of period	1,079.1	1,046.9	1,044.8

ETE Equity Distribution Agreement

In March 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the year ended December 31, 2017.

ETE Series A Convertible Preferred Units

	Years Ended December 31,
	2017	2016	2015
Number of Series A Convertible Preferred Units, beginning of period	329.3	—	—
Issuance of Series A Convertible Preferred Units	—	329.3	—
Number of Series A Convertible Preferred Units, end of period	329.3	329.3	—

Accumulated Other Comprehensive Income (Loss)

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

	December 31,
	2017			2016
Available-for-sale securities	$	8		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain (loss) related to pensions and other postretirement benefits	(5		)	7
Investments in unconsolidated affiliates, net	5			4
Subtotal	3			8
Amounts attributable to noncontrolling interest	(3		)	(8		)
Total AOCI included in partners’ capital, net of tax	$	—		$	—

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss):

	December 31,
	2017			2016
Available-for-sale securities	$	(2	)	$	(2	)
Foreign currency translation adjustment	3			3
Actuarial loss relating to pension and other postretirement benefits	3			—
Total	$	4		$	1

Parent Company [Member]

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

Our distributions declared and paid with respect to our common units for the periods presented were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 6, 2015	February 19, 2015	0.2250
March 31, 2015	May 8, 2015	May 19, 2015	0.2450
June 30, 2015	August 6, 2015	August 19, 2015	0.2650
September 30, 2015	November 5, 2015	November 19, 2015	0.2850
December 31, 2015	February 4, 2016	February 19, 2016	0.2850
March 31, 2016 (1)	May 6, 2016	May 19, 2016	0.2850
June 30, 2016 (1)	August 8, 2016	August 19, 2016	0.2850
September 30, 2016 (1)	November 7, 2016	November 18, 2016	0.2850
December 31, 2016 (1)	February 7, 2017	February 21, 2017	0.2850
March 31, 2017 (1)	May 10, 2017	May 19, 2017	0.2850
June 30, 2017 (1)	August 7, 2017	August 21, 2017	0.2850
September 30, 2017 (1)	November 7, 2017	November 20, 2017	0.2950
December 31, 2017 (1)	February 8, 2018	February 20, 2018	0.3050

ETP [Member]

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

Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:

Quarter Ended	ETP		Sunoco Logistics
December 31, 2014	$	0.6633	$	0.4000
March 31, 2015	0.6767		0.4190
June 30, 2015	0.6900		0.4380
September 30, 2015	0.7033		0.4580
December 31, 2015	0.7033		0.4790
March 31, 2016	0.7033		0.4890
June 30, 2016	0.7033		0.5000
September 30, 2016	0.7033		0.5100
December 31, 2016	0.7033		0.5200

Distributions on common units declared and paid by Post-Merger ETP were as follows:

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 16, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 15, 2017	0.5500
September 30, 2017	November 7, 2017	November 14, 2017	0.5650
December 31, 2017	February 8, 2018	February 14, 2018	0.5650

Distributions declared and paid by ETP to the Series A and Series B preferred unitholders 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

Schedule of Distributions Made To General and Limited Partners [Table Text Block]

As the holder of Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	IDRs	Partners (1)
Minimum Quarterly Distribution	$0.0750	—%	100%
First Target Distribution	up to $0.0833	—%	100%
Second Target Distribution	above $0.0833 up to $0.0958	13%	87%
Third Target Distribution	above $0.0958 up to $0.2638	35%	65%
Thereafter	above $0.2638	48%	52%

⁽¹⁾Includes general partner and limited partner interests, based on the proportionate ownership of each.

Sunoco LP [Member]

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

Sunoco LP Quarterly Distributions of Available Cash

The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Effective July 1, 2015, ETE exchanged 21 million ETP common units, owned by ETE, the owner of ETP’s general partner interest, for 100% of the general partner interest and all of the IDRs of Sunoco LP. ETP had previously owned our IDRs since September 2014, prior to that date the IDRs were owned by Susser.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Common Unitholders	Holder of IDRs
Minimum Quarterly Distribution	$0.4375	100%	—%
First Target Distribution	$0.4375 to $0.503125	100%	—%
Second Target Distribution	$0.503125 to $0.546875	85%	15%
Third Target Distribution	$0.546875 to $0.656250	75%	25%
Thereafter	Above $0.656250	50%	50%

Distributions declared and paid by Sunoco LP for the periods presented were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 17, 2015	February 27, 2015	0.6000
March 31, 2015	May 19, 2015	May 29, 2015	0.6450
June 30, 2015	August 18, 2015	August 28, 2015	0.6934
September 30, 2015	November 17, 2015	November 27, 2015	0.7454
December 31, 2015	February 5, 2016	February 16, 2016	0.8013
March 31, 2016	May 6, 2016	May 16, 2016	0.8173
June 30, 2016	August 5, 2016	August 15, 2016	0.8255
September 30, 2016	November 7, 2016	November 15, 2016	0.8255
December 31, 2016	February 13, 2017	February 21, 2017	0.8255
March 31, 2017	May 9, 2017	May 16, 2017	0.8255
June 30, 2017	August 7, 2017	August 15, 2017	0.8255
September 30, 2017	November 7, 2017	November 14, 2017	0.8255
December 31, 2017	February 06, 2018	February 14, 2018	0.8255

Schedule of Distributions Made To General and Limited Partners [Table Text Block]

Sunoco LP Quarterly Distributions of Available Cash

The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Effective July 1, 2015, ETE exchanged 21 million ETP common units, owned by ETE, the owner of ETP’s general partner interest, for 100% of the general partner interest and all of the IDRs of Sunoco LP. ETP had previously owned our IDRs since September 2014, prior to that date the IDRs were owned by Susser.

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	Common Unitholders	Holder of IDRs
Minimum Quarterly Distribution	$0.4375	100%	—%
First Target Distribution	$0.4375 to $0.503125	100%	—%
Second Target Distribution	$0.503125 to $0.546875	85%	15%
Third Target Distribution	$0.546875 to $0.656250	75%	25%
Thereafter	Above $0.656250	50%	50%

Series A Convertible Preferred Units [Member] | Parent Company [Member]

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

Our distributions declared and paid with respect to our Convertible Unit during the years ended December 31, 2016 and 2017 were as follows:

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2016	May 6, 2016	May 19, 2016	$	0.1100
June 30, 2016	August 8, 2016	August 19, 2016	0.1100
September 30, 2016	November 7, 2016	November 18, 2016	0.1100
December 31, 2016	February 7, 2017	February 21, 2017	0.1100
March 31, 2017	May 10, 2017	May 19, 2017	0.1100
June 30, 2017	August 7, 2017	August 21, 2017	0.1100
September 30, 2017	November 7, 2017	November 20, 2017	0.1100
December 31, 2017	February 8, 2018	February 20, 2018	0.1100

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Unit-Based Compensation Plans Unit-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2017

Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]

Schedule Of ETP Awards Granted To Employees And Non-Employee Directos

The following table summarizes the activity of the Subsidiary Unit Awards:

	ETP				Sunoco LP
	Number of Units		Weighted  Average Grant-Date Fair Value Per Unit		Number of Units		Weighted  Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 2016	9.4		$	27.68	2.0		$	34.43
Legacy Sunoco Logistics unvested awards as of December 31, 2016	3.2		28.57		—		—
Awards granted	4.9		17.69		0.2		28.31
Awards vested	(2.3	)	34.22		(0.3	)	45.48
Awards forfeited	(1.1	)	25.03		(0.2	)	34.71
Unvested awards as of December 31, 2017	14.1		23.18		1.7		31.89

XML

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Federal and State Income Taxes [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:

	Years Ended December 31,
	2017			2016			2015
Current expense (benefit):
Federal	$	54		$	(47	)	$	(308	)
State	(16		)	(34		)	(54		)
Total	38			(81		)	(362		)
Deferred expense (benefit):
Federal	(2,055		)	(189		)	268
State	184			12			(29		)
Total	(1,871		)	(177		)	239
Total income tax expense (benefit) from continuing operations	$	(1,833	)	$	(258	)	$	(123	)

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense (benefit) at the United States statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2017, 2016 and 2015 is as follows:

	2017			2016			2015
Income tax expense (benefit) at United States statutory rate of 35 percent	$	248		$	71		$	316
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax	(477		)	(576		)	(355		)
Goodwill impairment	207			278			—
State tax, net of federal tax benefit	124			(10		)	(29		)
Dividend received deduction	(14		)	(15		)	(22		)
Federal rate change	(1,812		)	—			—
Audit settlement	—			—			(7		)
Change in tax status of subsidiary	(124		)	—			—
Other	15			(6		)	(26		)
Income tax expense (benefit) from continuing operations	$	(1,833	)	$	(258	)	$	(123	)

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:

	December 31,
	2017			2016
Deferred income tax assets:
Net operating losses and alternative minimum tax credit	$	683		$	472
Pension and other postretirement benefits	21			30
Long-term debt	14			32
Other	191			182
Total deferred income tax assets	909			716
Valuation allowance	(189		)	(118		)
Net deferred income tax assets	720			598
Deferred income tax liabilities:
Property, plant and equipment	(1,036		)	(1,633		)
Investments in unconsolidated affiliates	(2,726		)	(3,789		)
Trademarks	(173		)	(273		)
Other	(100		)	(15		)
Total deferred income tax liabilities	(4,035		)	(5,710		)
Net deferred income taxes	$	(3,315	)	$	(5,112	)

ScheduleOfUnrecognizedTaxBenefits [Table Text Block]

The following table sets forth the changes in unrecognized tax benefits:

	Years Ended December 31,
	2017			2016			2015
Balance at beginning of year	$	615		$	610		$	440
Additions attributable to tax positions taken in the current year	—			8			178
Additions attributable to tax positions taken in prior years	28			18			—
Reduction attributable to tax positions taken in prior years	(25		)	(20		)	—
Lapse of statute	(9		)	(1		)	(8		)
Balance at end of year	$	609		$	615		$	610

Summary of Deferred Tax Liability Not Recognized [Table Text Block]

The table below provides a rollforward of the net deferred income tax liability as follows:

	December 31,
	2017			2016
Net deferred income tax liability, beginning of year	$	(5,112	)	$	(4,590	)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)	—			(460		)
Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3)	—			(243		)
Tax provision, including provision from discontinued operations	1,825			201
Other	(28		)	(20		)
Net deferred income tax liability	$	(3,315	)	$	(5,112	)

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Derivative Assets And Liabilities (Tables)

12 Months Ended

Dec. 31, 2017

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Offsetting Assets [Table Text Block]

he following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	December 31, 2017			December 31, 2016			December 31, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(219	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	45			25			(58		)	(58		)
Broker cleared derivative contracts	Other current assets (liabilities)	276			338			(283		)	(420		)
		321			363			(560		)	(672		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(21		)	(4		)	21			4
Counterparty netting	Other current assets (liabilities)	(263		)	(338		)	263			338
Total net derivatives		$	37		$	21		$	(276	)	$	(330	)

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:

	December 31, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	1,078		2018	(683	)	2017
Basis Swaps IFERC/NYMEX (1)	48,510		2018-2020	2,243		2017
Options – Puts	13,000		2018	—		—
Power (Megawatt):
Forwards	435,960		2018-2019	391,880		2017 - 2018
Futures	(25,760	)	2018	109,564		2017 - 2018
Options — Puts	(153,600	)	2018	(50,400	)	2017
Options — Calls	137,600		2018	186,400		2017
Crude (MBbls) – Futures	—		—	(617	)	2017
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	4,650		2018-2020	10,750		2017 - 2018
Swing Swaps IFERC	87,253		2018-2019	(5,663	)	2017
Fixed Swaps/Futures	(4,390	)	2018-2019	(52,653	)	2017 - 2019
Forward Physical Contracts	(145,105	)	2018-2020	(22,492	)	2017
Natural Gas Liquid (MBbls) – Forwards/Swaps	6,744		2018-2019	(5,787	)	2017
Refined Products (MBbls) – Futures	(3,901	)	2018-2019	(3,144	)	2017
Corn (Bushels) – Futures	1,870,000		2018	1,580,000		2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(39,770	)	2018	(36,370	)	2017
Fixed Swaps/Futures	(39,770	)	2018	(36,370	)	2017
Hedged Item — Inventory	39,770		2018	36,370		2017

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

Interest Rate Swaps Outstanding

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

			Notional Amount Outstanding
Entity	Term	Type(1)	December 31, 2017		December 31, 2016
ETP	July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
ETP	July 2018(2)	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
ETP	July 2019(2)	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
ETP	July 2020(2)	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
ETP	December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
ETP	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.

Fair Value Of Derivative Instruments

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	December 31, 2017		December 31, 2016		December 31, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	14	$	—	$	(2	)	$	(4	)
	14		—		(2		)	(4		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	262		338		(281		)	(416		)
Commodity derivatives	45		25		(58		)	(58		)
Interest rate derivatives	—		—		(219		)	(193		)
Embedded derivatives in ETP Convertible Preferred Units	—		—		—			(1		)
	307		363		(558		)	(668		)
Total derivatives	$	321	$	363	$	(560	)	$	(672	)

Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives

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

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Years Ended December 31,
		2017		2016		2015
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	26	$	14	$	21
Total		$	26	$	14	$	21

Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized

	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
		Years Ended December 31,
		2017		2016		2015
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	26	$	14	$	21
Total		$	26	$	14	$	21

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2017			2016			2015
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	31		$	(35	)	$	(11	)
Commodity derivatives – Non-trading	Cost of products sold	5			(177		)	15
Interest rate derivatives	Losses on interest rate derivatives	(37		)	(12		)	(18		)
Embedded derivatives	Other, net	1			4			12
Total		$	—		$	(220	)	$	(2	)

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

12 Months Ended

Dec. 31, 2017

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

Schedule of Rent Expense [Table Text Block]

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Years Ended December 31,
	2017			2016			2015
Rental expense(1)	$	196		$	187		$	281
Less: Sublease rental income	(25		)	(26		)	(26		)
Rental expense, net	$	171		$	161		$	255

⁽¹⁾  Includes contingent rentals totaling $16 million, $18 million and $20 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Environmental Exit Costs by Cost [Table Text Block]

	December 31,
	2017		2016
Current	$	35	$	26
Non-current	337		318
Total environmental liabilities	$	372	$	344

Schedule of Future Minimum Rental Payments for Operating Leases

Future minimum lease commitments for such leases are:

Years Ending December 31:
2018	$	113
2019	100
2020	96
2021	83
2022	71
Thereafter	606
Future minimum lease commitments	1,069
Less: Sublease rental income	(152		)
Net future minimum lease commitments	$	917

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Retirement Benefits Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

Obligations and Funded Status

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.

The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:

	December 31, 2017									December 31, 2016
	Pension Benefits									Pension Benefits
	Funded Plans			Unfunded Plans			Other Postretirement Benefits			Funded Plans			Unfunded Plans			Other Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$	18		$	51		$	166		$	20		$	57		$	181
Interest cost	1			1			4			1			2			4
Amendments	—			—			7			—			—			—
Benefits paid, net	(2		)	(6		)	(20		)	(1		)	(7		)	(21		)
Actuarial (gain) loss and other	2			1			(1		)	(2		)	(1		)	2
Settlements	(18		)	—			—			—			—			—
Benefit obligation at end of period	$	1		$	47		$	156		$	18		$	51		$	166
Change in plan assets:
Fair value of plan assets at beginning of period	$	12		$	—		$	256		$	15		$	—		$	261
Return on plan assets and other	3			—			11			(2		)	—			6
Employer contributions	6			—			10			—			—			10
Benefits paid, net	(2		)	—			(20		)	(1		)	—			(21		)
Settlements	(18		)	—			—			—			—			—
Fair value of plan assets at end of period	$	1		$	—		$	257		$	12		$	—		$	256
Amount underfunded (overfunded) at end of period	$	—		$	47		$	(101	)	$	6		$	51		$	(90	)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets	$	—		$	—		$	127		$	—		$	—		$	114
Current liabilities	—			(8		)	(2		)	—			(7		)	(2		)
Non-current liabilities	—			(39		)	(24		)	(6		)	(44		)	(23		)
	$	—		$	(47	)	$	101		$	(6	)	$	(51	)	$	89
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Net actuarial gain	$	—		$	5		$	(18	)	$	—		$	—		$	(13	)
Prior service cost	—			—			21			—			—			15
	$	—		$	5		$	3		$	—		$	—		$	2

Schedule of Accumulated and Projected Benefit Obligations [Table Text Block]

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:

	December 31, 2017						December 31, 2016
	Pension Benefits						Pension Benefits
	Funded Plans		Unfunded Plans		Other Postretirement Benefits		Funded Plans		Unfunded Plans		Other Postretirement Benefits
Projected benefit obligation	$	1	$	47	N/A		$	18	$	51	N/A
Accumulated benefit obligation	1		47		$	156	18		51		$	166
Fair value of plan assets	1		—		257		12		—		256

Schedule of Benefit Obligations Assumptions [Table Text Block]

Assumptions

The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:

	December 31, 2017				December 31, 2016
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	3.27	%	2.34	%	3.65	%	2.34	%
Rate of compensation increase	N/A		N/A		N/A		N/A

Schedule or Description of Weighted Average Discount Rate [Table Text Block]

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:

	December 31, 2017				December 31, 2016
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
Discount rate	3.52	%	3.10	%	3.60	%	3.06	%
Expected return on assets:
Tax exempt accounts	3.50	%	7.00	%	3.50	%	7.00	%
Taxable accounts	N/A		4.50	%	N/A		4.50	%
Rate of compensation increase	N/A		N/A		N/A		N/A

Schedule of Health Care Cost Trend Rates [Table Text Block]

The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:

	December 31,
	2017		2016
Health care cost trend rate	7.20	%	6.73	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.99	%	4.96	%
Year that the rate reaches the ultimate trend rate	2023		2021

Fair Value of Plan Assets [Table Text Block]

The fair value of the pension plan assets by asset category at the dates indicated is as follows:

			Fair Value Measurements at December 31, 2017
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Mutual funds (1)	$	1	$	1	$	—	$	—
Total	$	1	$	1	$	—	$	—

⁽¹⁾ Comprised of 100% equities as of December 31, 2017.

			Fair Value Measurements at December 31, 2016
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Mutual funds (1)	$	12	$	12	$	—	$	—
Total	$	12	$	12	$	—	$	—

⁽¹⁾  Comprised of 100% equities as of December 31, 2016.

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:

			Fair Value Measurements at December 31, 2017
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	33	$	33	$	—	$	—
Mutual funds (1)	154		154		—		—
Fixed income securities	70		—		70		—
Total	$	257	$	187	$	70	$	—

⁽¹⁾ Primarily comprised of approximately 38% equities, 61% fixed income securities and 2% cash as of December 31, 2017.

			Fair Value Measurements at December 31, 2016
	Fair Value Total		Level 1		Level 2		Level 3
Asset Category:
Cash and Cash Equivalents	$	23	$	23	$	—	$	—
Mutual funds (1)	142		142		—		—
Fixed income securities	91		—		91		—
Total	$	256	$	165	$	91	$	—

⁽¹⁾  Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016.

The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  

Schedule of Expected Benefit Payments [Table Text Block]

Benefit Payments

Panhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:

Years	Pension Benefits - Unfunded Plans (1)		Other Postretirement Benefits (Gross, Before Medicare Part D)
2018	$	8	$	24
2019	6		23
2020	6		21
2021	5		19
2022	4		17
2023 – 2027	15		37

Schedule of Net Benefit Costs [Table Text Block]

Components of Net Periodic Benefit Cost

	December 31, 2017					December 31, 2016
	Pension Benefits		Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Interest cost	$	2	$	4		$	3		$	4
Expected return on plan assets	—		(9		)	(1		)	(8		)
Prior service cost amortization	—		2			—			1
Net periodic benefit cost	$	2	$	(3	)	$	2		$	(3	)

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Reportable Segments (Tables)

12 Months Ended

Dec. 31, 2017

Financial Information By Segment

	Years Ended December 31,
	2017			2016			2015
Revenues:
Investment in ETP:
Revenues from external customers	$	28,613		$	21,618		$	34,156
Intersegment revenues	441			209			136
	29,054			21,827			34,292
Investment in Sunoco LP:
Revenues from external customers	11,713			9,977			12,419
Intersegment revenues	10			9			11
	11,723			9,986			12,430
Investment in Lake Charles LNG:
Revenues from external customers	197			197			216
Adjustments and Eliminations:	(451		)	(218		)	(10,842		)
Total revenues	$	40,523		$	31,792		$	36,096
Costs of products sold:
Investment in ETP	$	20,801		$	15,080		$	26,714
Investment in Sunoco LP	10,615			8,830			11,450
Adjustments and Eliminations	(450		)	(217		)	(9,496		)
Total costs of products sold	$	30,966		$	23,693		$	28,668
Depreciation, depletion and amortization:
Investment in ETP	$	2,332		$	1,986		$	1,929
Investment in Sunoco LP	169			176			150
Investment in Lake Charles LNG	39			39			39
Corporate and Other	14			15			17
Adjustments and Eliminations	—			—			(184		)
Total depreciation, depletion and amortization	$	2,554		$	2,216		$	1,951

	Years Ended December 31,
	2017			2016		2015
Equity in earnings of unconsolidated affiliates:
Investment in ETP	$	156		$	59	$	469
Adjustments and Eliminations	(12		)	211		(193		)
Total equity in earnings of unconsolidated affiliates	$	144		$	270	$	276

	Years Ended December 31,
	2017			2016			2015
Segment Adjusted EBITDA:
Investment in ETP	$	6,712		$	5,733		$	5,517
Investment in Sunoco LP	732			665			719
Investment in Lake Charles LNG	175			179			196
Corporate and Other	(31		)	(170		)	(104		)
Adjustments and Eliminations	(268		)	(272		)	(590		)
Total Segment Adjusted EBITDA	7,320			6,135			5,738
Depreciation, depletion and amortization	(2,554		)	(2,216		)	(1,951		)
Interest expense, net of interest capitalized	(1,922		)	(1,804		)	(1,622		)
Gains on acquisitions	—			83			—
Impairment of investments in unconsolidated affiliates	(313		)	(308		)	—
Impairment losses	(1,039		)	(1,040		)	(339		)
Losses on interest rate derivatives	(37		)	(12		)	(18		)
Non-cash unit-based compensation expense	(99		)	(70		)	(91		)
Unrealized gains (losses) on commodity risk management activities	59			(136		)	(65		)
Losses on extinguishments of debt	(89		)	—			(43		)
Inventory valuation adjustments	24			97			(67		)
Adjusted EBITDA related to discontinued operations	(223		)	(199		)	(228		)
Adjusted EBITDA related to unconsolidated affiliates	(716		)	(675		)	(713		)
Equity in earnings of unconsolidated affiliates	144			270			276
Other, net	155			79			23
Income from continuing operations before income tax benefit	$	710		$	204		$	900
Income tax benefit from continuing operations	(1,833		)	(258		)	(123		)
Income from continuing operations	2,543			462			1,023
Income (loss) from discontinued operations, net of tax	(177		)	(462		)	38
Net income	$	2,366		$	—		$	1,061

	December 31,
	2017			2016			2015
Total assets:
Investment in ETP	$	77,965		$	70,105		$	65,128
Investment in Sunoco LP	8,344			8,701			8,842
Investment in Lake Charles LNG	1,646			1,508			1,369
Corporate and Other	598			711			638
Adjustments and Eliminations	(2,307		)	(2,100		)	(4,833		)
Total	$	86,246		$	78,925		$	71,144

	Years Ended December 31,
	2017		2016		2015
Additions to property, plant and equipment, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):
Investment in ETP	$	5,901	$	5,810	$	8,167
Investment in Sunoco LP	103		119		178
Investment in Lake Charles LNG	2		—		1
Adjustments and Eliminations	—		—		(123		)
Total	$	6,006	$	5,929	$	8,223

	December 31,
	2017			2016			2015
Advances to and investments in affiliates:
Investment in ETP	$	3,816		$	4,280		$	5,003
Adjustments and Eliminations	(1,111		)	(1,240		)	(1,541		)
Total	$	2,705		$	3,040		$	3,462

The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP.

Investment in ETP

	Years Ended December 31,
	2017		2016		2015
Intrastate Transportation and Storage	$	2,891	$	2,155	$	1,912
Interstate Transportation and Storage	915		946		1,008
Midstream	2,510		2,342		2,607
NGL and refined products transportation and services	8,326		5,973		4,569
Crude oil transportation and services	11,672		7,539		8,980
All Other	2,740		2,872		15,216
Total revenues	29,054		21,827		34,292
Less: Intersegment revenues	441		209		136
Revenues from external customers	$	28,613	$	21,618	$	34,156

Investment in Sunoco LP

	Years Ended December 31,
	2017		2016		2015
Retail operations	$	2,263	$	1,991	$	2,226
Wholesale operations	9,460		7,995		10,204
Total revenues	11,723		9,986		12,430
Less: Intersegment revenues	10		9		11
Revenues from external customers	$	11,713	$	9,977	$	12,419

Investment in Lake Charles LNG

Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 2015, respectively, were related to LNG terminalling.

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

	Quarters Ended
	March 31*		June 30*		September 30*		December 31		Total Year
2017:
Revenues	$	9,660	$	9,427	$	9,984	$	11,452	$	40,523
Operating income (loss)	758		746		924		285		2,713
Net income (loss)	319		121		758		1,168		2,366
Limited Partners’ interest in net income	232		204		240		239		915
Basic net income per limited partner unit	$	0.22	$	0.18	$	0.22	$	0.22	$	0.85
Diluted net income per limited partner unit	$	0.21	$	0.18	$	0.22	$	0.22	$	0.83

	Quarters Ended
	March 31*		June 30*		September 30*			December 31*			Total Year*
2016:
Revenues	$	6,447	$	7,866	$	8,156		$	9,323		$	31,792
Operating income	680		814		624			(275		)	1,843
Net income (loss)	320		417		(3		)	(734		)	—
Limited Partners’ interest in net income	311		239		207			226			983
Basic net income per limited partner unit	$	0.30	$	0.23	$	0.20		$	0.22		$	0.94
Diluted net income per limited partner unit	$	0.30	$	0.23	$	0.19		$	0.21		$	0.92

* As adjusted. See Note 2 and Note 3. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.

The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $1.04 billion, respectively. Impairment losses in 2017 were primarily related to ETP’s interstate transportation and storage operations, NGL and refined products operations and other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its interstate transportation and storage operations.

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Supplemental Financial Statement Information (Tables) - Parent Company [Member]

12 Months Ended

Dec. 31, 2017

Schedule Of Balance Sheets

BALANCE SHEETS

	December 31,
	2017			2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1		$	2
Accounts receivable from related companies	65			55
Other current assets	1			—
Total current assets	67			57
PROPERTY, PLANT AND EQUIPMENT, net	27			36
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	6,082			5,088
INTANGIBLE ASSETS, net	—			1
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	8			10
Total assets	$	6,193		$	5,201
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	—		$	1
Accounts payable to related companies	—			22
Interest payable	66			66
Accrued and other current liabilities	4			3
Total current liabilities	70			92
LONG-TERM DEBT, less current maturities	6,700			6,358
NOTE PAYABLE TO AFFILIATE	617			443
OTHER NON-CURRENT LIABILITIES	2			2
COMMITMENTS AND CONTINGENCIES
PARTNERS’ DEFICIT:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)	(1,643		)	(1,871		)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)	450			180
Total partners’ deficit	(1,196		)	(1,694		)
Total liabilities and partners’ deficit	$	6,193		$	5,201

Schedule Of Statements Of Operations

STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2017			2016			2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(31	)	$	(185	)	$	(112	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(347		)	(327		)	(294		)
Equity in earnings of unconsolidated affiliates	1,381			1,511			1,601
Loss on extinguishment of debt	(47		)	—			—
Other, net	(2		)	(4		)	(5		)
INCOME BEFORE INCOME TAXES	954			995			1,190
Income tax expense	—			—			1
NET INCOME	954			995			1,189
General Partner’s interest in net income	2			3			3
Convertible Unitholders’ interest in income	37			9			—
Class D Unitholder’s interest in net income	—			—			3
Limited Partners’ interest in net income	$	915		$	983		$	1,183

Schedule Of Statements Of Cash Flows

STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2017			2016			2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	831		$	918		$	1,103
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Bakken Pipeline Transaction	—			—			(817		)
Contributions to unconsolidated affiliates	(861		)	(70		)	—
Capital expenditures	(1		)	(16		)	(19		)
Contributions in aid of construction costs	7			—			—
Net cash used in investing activities	(855		)	(86		)	(836		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,219			225			3,672
Principal payments on debt	(1,881		)	(210		)	(1,985		)
Distributions to partners	(1,010		)	(1,022		)	(1,090		)
Proceeds from affiliate	174			176			210
Common Units issued for cash	568			—			—
Units repurchased under buyback program	—			—			(1,064		)
Debt issuance costs	(47		)	—			(11		)
Net cash provided by (used in) financing activities	23			(831		)	(268		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(1		)	1			(1		)
CASH AND CASH EQUIVALENTS, beginning of period	2			1			2
CASH AND CASH EQUIVALENTS, end of period	$	1		$	2		$	1

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Operations And Organization (Narrative) (Details) $ in Millions	1 Months Ended						12 Months Ended
	Feb. 28, 2018 shares	Jan. 31, 2018 shares	Apr. 30, 2017	Oct. 31, 2015 USD ($)	Jul. 31, 2015 shares	Apr. 30, 2015 USD ($) shares	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) shares	Dec. 31, 2015 USD ($)
LNG Storage Capacity										9.0
Payments to Acquire Businesses, Gross | $				$ 382
Citrus [Member]
Interest ownership										50.00%
ETP [Member]
Incentive Distribution Rights										100.00%
ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.										27,500,000
SXL and ETP Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio			1.5
Dropdown of Sunoco LLC Interest [Member]
Payments to Acquire Businesses, Gross | $						$ 775
Sunoco LP Exchange [Member]
Stock Repurchased During Period, Shares					31,500,000
Sunoco LP Exchange [Member] | Sunoco GP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					100.00%
Regency Merger [Member]
Business Acquisition, Number Of Share Received In Exchange Of Each Share						0.6186
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares						258,300,000
Relinquishment of Incentive Distributions | $										$ 60	$ 80
Class I Units [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.										100
ETP Subsidiaries [Member] | Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares						23,300,000
ETP Series A Preferred Units [Member] | Regency Merger [Member]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares						1,900,000
Subsequent Event [Member]
Relinquishment of Incentive Distributions | $							$ 33	$ 128	$ 153
Subsequent Event [Member] | Sunoco LP [Member]
Stock Repurchased During Period, Shares	17,286,859
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		2,300,000
Subsequent Event [Member] | Regency Merger [Member]
Relinquishment of Incentive Distributions | $							$ 320
Subsequent Event [Member] | Series A Preferred Units [Member] | Sunoco LP [Member]
Stock Repurchased and Retired During Period, Shares		12,000,000

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Estimates, Significant Accounting Policies and Balance Sheet Detail (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Asset Retirement Obligation	$ 165	$ 170
Tangible Asset Impairment Charges	127	133		$ 110
ARO Underlying Asset	2	14
Impairment of Intangible Assets, Finite-lived				24
Asset Retirement Obligation, Legally Restricted Assets, Fair Value	21	13
Deferred Tax Liabilities, Gross	4,035	5,710
Long-term Debt, Fair Value	45,620	45,050
Impairment losses	895	897
Goodwill acquired	12	509
Goodwill	4,768	5,670	[1]	6,056
Long-term Debt	44,084	43,802
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	0
Investment In Sunoco LP [Member]
Impairment losses	102
Goodwill, Impaired, Accumulated Impairment Loss		641
Goodwill acquired	0	81
Goodwill	1,430	1,550		1,694
Other Segments [Member]
Impairment losses	(452)
NGL and refined products transportation and services [Member]
Impairment losses	(79)
Midstream [Member]
Tangible Asset Impairment Charges		10
Impairment losses		(32)
Investment In ETP [Member]
Impairment losses	793	670
Goodwill acquired	12	428
Goodwill	3,115	3,897		5,428
Interstate Transportation and Storage [Member]
Impairment losses	(262)	(638)
Retail Marketing [Member]
Excise Taxes Collected	$ 234	243		$ 231
Continuing Operations [Member] | Investment In Sunoco LP [Member]
Impairment losses		$ 227

[1] * As adjusted. See Note 2.

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Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Accounting Change) (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended																12 Months Ended
		Dec. 31, 2016		Sep. 30, 2016	[2]	Jun. 30, 2016	[2]	Mar. 31, 2016	[2]	Dec. 31, 2015		Sep. 30, 2015	[2]	Jun. 30, 2015	[2]	Mar. 31, 2015	[2]	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cost of products sold																		$ 30,966	$ 23,693	[1]	$ 28,668	[1]
Operating income (loss)		$ 285		$ 924		$ 746		$ 758		$ (275)	[2]	$ 624		$ 814		$ 680		2,713	1,843	[1],[2]	2,287	[1]
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest																		710	204	[1]	900	[1]
Net income		$ 1,168		$ 758		$ 121		$ 319		$ (734)	[2]	$ (3)		$ 417		$ 320		2,366	0	[1],[2]	1,061	[1]
Inventory valuation adjustments																		(24)	(97)	[1]	67	[1]
Income tax benefit from continuing operations																		(1,833)	(258)	[1]	(123)	[1]
Net Income (Loss) Attributable to Parent																		954	995	[1]	1,189	[1]
Less: Net income (loss) attributable to noncontrolling interest																		$ 1,412	$ (995)	[1]	$ (128)	[1]
Basic		$ 0.22		$ 0.22		$ 0.18		$ 0.22		$ 0.22	[2]	$ 0.20		$ 0.23		$ 0.30		$ 0.85	$ 0.94	[1],[2]	$ 1.11	[1]
Diluted		$ 0.22		$ 0.22		$ 0.18		$ 0.21		$ 0.21	[2]	$ 0.19		$ 0.23		$ 0.30		$ 0.83	$ 0.92	[1],[2]	$ 1.11	[1]
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest																		$ 2,361	$ 4		$ 1,121
Comprehensive Income (Loss), Net of Tax, Attributable to Parent																		954	995		1,189
Deferred income taxes																		(1,871)	(177)	[1]	239	[1]
Increase (Decrease) in Operating Capital																		(192)	(179)	[1]	(872)	[1]
Inventories		$ 2,055	[1]							$ 1,453								2,022	2,055	[1]	1,453
Deferred income taxes		5,112	[1]															3,315	5,112	[1]
Total partners’ deficit		(1,694)	[1]							24,485								(1,196)	(1,694)	[1]	24,485
Noncontrolling interest		24,125	[1]															$ 31,176	24,125	[1]
Scenario, Previously Reported [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cost of products sold	[3]																		23,652		28,636
Operating income (loss)	[3]																		1,884		2,319
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	[3]																		245		932
Net income	[3]																		41		1,093
Inventory valuation adjustments	[3]																		(267)		229
Net Income (Loss) Attributable to Parent																			(954)	[3]	(96)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	[3]																		45		1,153
Increase (Decrease) in Operating Capital	[3]																		50		1,066
Inventories	[3]	2,141								1,498									2,141		1,498
Total partners’ deficit		24,211	[3]							24,530									24,211	[3]	24,530
Restatement Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cost of products sold																			41		32
Operating income (loss)																			(41)		(32)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest																			(41)		(32)
Net income																			(41)		(32)
Inventory valuation adjustments																			170		(162)
Net Income (Loss) Attributable to Parent																			(41)		(32)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest																			(41)		(32)
Increase (Decrease) in Operating Capital																			129		(194)
Inventories		(86)								(45)									(86)		(45)
Total partners’ deficit		$ (86)								$ (45)									$ (86)		$ (45)

[1] * As adjusted. See Note 2.

[2] * As adjusted. See Note 2 and Note 3.

[3] * Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 3.

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Estimates (Schedule Of Net Changes In Operating Assets And Liabilities Included Cash Flows From Operating Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Accounting Policies [Abstract]
Accounts receivable	$ (948)	$ (1,126)		$ 856
Accounts receivable from related companies	24	42		(5)
Inventories	58	(480)		(212)
Other current assets	(38)	(165)		225
Other non-current assets, net	84	(148)		247
Accounts payable	712	1,170		(1,070)
Accounts payable to related companies	(178)	(64)		400
Accrued and other current liabilities	(97)	89		(697)
Other non-current liabilities	106	106		(241)
Derivative assets and liabilities, net	9	67		75
Net change in operating assets and liabilities, net of effects of acquisitions	$ (192)	$ (179)	[1]	$ (872)	[1]

[1] * As adjusted. See Note 2.

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Estimates (Schedule Of Non-Cash Investing And Financing Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 1,060	$ 848	$ 910
Contribution of assets from noncontrolling interest	988	0	34
Net gains (losses) from subsidiary common unit transactions	(56)	16	(526)
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger		236
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	1,914	1,922	1,800
Cash paid for (refund of) income taxes	50		72
Proceeds from Income Tax Refunds		(229)
PennTex Acquisition [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger		307	$ 0
Limited Partner [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger		$ 0
Limited Partner [Member] | PennTex Acquisition [Member]
NON-CASH FINANCING ACTIVITIES:
Units issued in Merger	$ 0

XML

Estimates (Schedule of Inventory) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Inventory, Net [Abstract]
Natural gas, NGLs, and refined products	$ 1,120	$ 1,141
Crude oil	551	651
Spare parts and other	351	263
Total inventories	$ 2,022	$ 2,055	[1]	$ 1,453

[1] * As adjusted. See Note 2.

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Estimates (Other Current Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Information [Abstract]
Deposits paid to vendors	$ 64	$ 74
Prepaid expenses and other	231	373
Total other current assets	$ 295	$ 447	[1]

[1] * As adjusted. See Note 2.

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Estimates (Property, Plant and Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 71,177	$ 61,562	[1]
Less - Accumulated depreciation	(10,089)	(7,984)	[1]
Property, Plant and Equipment, Net	61,088	53,578	[1]
Land and Land Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	2,222	1,189
Building and Building Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	2,786	2,247
Pipelines [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	44,673	36,570
Natural gas and NGL storage facilities (5 to 46 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,681	1,451
Bulk storage, equipment and facilities (2 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	3,883	3,701
Vehicles [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	126	217
Right of way (20 to 83 years)
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	3,432	3,349
Natural resources
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	434	434
Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	1,029	2,285
Construction Work-In-Process [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 10,911	$ 10,119

[1] * As adjusted. See Note 2.

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Estimates (Schedule Of Property, Plant And Equipment Depreciation And Capitalized Interest Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Depreciation and depletion expense	$ 2,204	$ 1,952	$ 1,661
Capitalized interest	$ 286	$ 201	$ 164

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Estimates (Schedule of Other Non-Current Assets, net) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Regulatory assets	$ 85	$ 86
Deferred charges	210	217
Restricted funds	192	190
Other	399	322
Total other non-current assets, net	$ 886	$ 815	[1]

[1] * As adjusted. See Note 2.

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Estimates (Components Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Gross Carrying Amount	$ 7,458	$ 6,536
Accumulated Amortization	(1,342)	(1,024)
Customer relationships, contracts and agreements (3 to 46 years)
Gross Carrying Amount	6,979	6,050
Accumulated Amortization	(1,277)	(971)
Trade names (20 years)
Gross Carrying Amount	48	48
Accumulated Amortization	(26)	(21)
Patents (10 years)
Gross Carrying Amount	66	66
Accumulated Amortization	(25)	(22)
Total Amortizable Intangible Assets [Member]
Gross Carrying Amount	7,121	6,189
Accumulated Amortization	(1,342)	(1,024)
Trademarks [Member]
Gross Carrying Amount	295	288
Accumulated Amortization	0	0
Other Amortizable Intangible Assets [Member]
Gross Carrying Amount	28	25
Accumulated Amortization	(14)	(10)
Contractual Rights [Member]
Gross Carrying Amount	42	59
Accumulated Amortization	$ 0	$ 0

XML

Estimates, Significant Accounting Policies and Balance Sheet Detail Estimates (Schedule of Useful Lives) (Details) (Details)	12 Months Ended
	Dec. 31, 2017
Minimum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Intangible assets, useful life, minimum (years)	3 years
Minimum [Member] | Other (5 to 20 years)
Intangible assets, useful life, minimum (years)	1 year
Maximum [Member] | Customer relationships, contracts and agreements (3 to 46 years)
Intangible assets, useful life, minimum (years)	46 years
Maximum [Member] | Trade names (20 years)
Intangible assets, useful life, minimum (years)	15 years
Maximum [Member] | Patents (10 years)
Intangible assets, useful life, minimum (years)	9 years
Maximum [Member] | Other (5 to 20 years)
Intangible assets, useful life, minimum (years)	15 years
Buildings and improvements [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Buildings and improvements [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	45 years
Pipelines And Equipment [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	5 years
Pipelines And Equipment [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Natural gas and NGL storage facilities (5 to 46 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	5 years
Natural gas and NGL storage facilities (5 to 46 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	46 years
Bulk storage, equipment and facilities (2 to 83 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	2 years
Bulk storage, equipment and facilities (2 to 83 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Tanks and other equipment (5 to 40 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	5 years
Tanks and other equipment (5 to 40 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	40 years
Retail equipment (2 to 99 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	2 years
Retail equipment (2 to 99 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	99 years
Vehicles [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Vehicles [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	25 years
Right of way (20 to 83 years) | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	20 years
Right of way (20 to 83 years) | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	83 years
Property, Plant and Equipment, Other Types [Member] | Minimum [Member]
Property, plant and equipment, useful life, minimum (years)	1 year
Property, Plant and Equipment, Other Types [Member] | Maximum [Member]
Property, plant and equipment, useful life, minimum (years)	40 years

XML

Estimates (Aggregate Amortization Expense Of Intangibles And Other Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Depreciation And Amortization [Member]
Reported in depreciation and amortization	$ 344	$ 264	$ 290

XML

Estimates (Estimated Aggregate Amortization Expense) (Details) $ in Millions	Dec. 31, 2017 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2018	$ 341
2019	338
2020	336
2021	319
2022	$ 287

XML

Estimates (Schedule Of Goodwill) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Goodwill [Roll Forward]
Goodwill	$ 5,670	[1]	$ 6,056
Goodwill acquired	12		509
Goodwill	4,768		5,670	[1]
Goodwill impairment	(895)		(897)
Goodwill, Other Changes	(19)		2
Goodwill, Written off Related to Sale of Business Unit			0
Investment In ETP [Member]
Goodwill [Roll Forward]
Goodwill	3,897		5,428
Goodwill acquired	12		428
Goodwill	3,115		3,897
Goodwill impairment	(793)		(670)
Goodwill, Other Changes	(1)		0
Goodwill, Written off Related to Sale of Business Unit			(1,289)
Investment In Sunoco LP [Member]
Goodwill [Roll Forward]
Goodwill	1,550		1,694
Goodwill acquired	0		81
Goodwill	1,430		1,550
Goodwill impairment	(102)
Goodwill, Other Changes	(18)		2
Goodwill, Written off Related to Sale of Business Unit			0
Investment in Lake Charles LNG [Member]
Goodwill [Roll Forward]
Goodwill	184		184
Goodwill acquired	0		0
Goodwill	184		184
Goodwill impairment	0		0
Goodwill, Other Changes	0		0
Goodwill, Written off Related to Sale of Business Unit			0
Corporate, Other and Eliminations [Member]
Goodwill [Roll Forward]
Goodwill	39		(1,250)
Goodwill acquired	0		0
Goodwill	39		39
Goodwill impairment	0		0
Goodwill, Other Changes	$ 0		0
Goodwill, Written off Related to Sale of Business Unit			$ 1,289

[1] * As adjusted. See Note 2.

XML

Estimates (Accrued And Other Current Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Information [Abstract]
Interest payable	$ 552	$ 545
Customer advances and deposits	59	72
Accrued capital expenditures	1,006	769
Accrued wages and benefits	280	254
Taxes payable other than income taxes	108	201
Income taxes payable	180	0
Exchanges payable	154	208
Other	243	318
Accrued and other current liabilities	$ 2,582	$ 2,367	[1]

[1] * As adjusted. See Note 2.

XML

Estimates (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Assets, Fair Value Disclosure		$ 0
Total liabilities	$ (560)
Level 1 [Member]
Total liabilities	(303)
Level 2 [Member]
Total liabilities	(257)
Fair Value, Measurements, Recurring [Member]
Commodity derivatives:	321	363
Other Assets, Fair Value Disclosure	21	13
Total assets	342	376
Interest rate derivatives	(219)	(193)
Embedded derivatives in the ETP Convertible Preferred Units		(1)
Commodity derivatives:	(341)	(478)
Total liabilities		(672)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Commodity derivatives:	277	356
Other Assets, Fair Value Disclosure	14	8
Total assets	291	364
Interest rate derivatives	0	0
Embedded derivatives in the ETP Convertible Preferred Units		0
Commodity derivatives:	(303)	(470)
Total liabilities		(470)
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Commodity derivatives:	44	7
Other Assets, Fair Value Disclosure	7	5
Total assets	51	12
Interest rate derivatives	(219)	(193)
Embedded derivatives in the ETP Convertible Preferred Units		0
Commodity derivatives:	(38)	(8)
Total liabilities		(201)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Commodity derivatives:		0
Total assets		0
Interest rate derivatives		0
Embedded derivatives in the ETP Convertible Preferred Units		(1)
Commodity derivatives:		0
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value		1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Options - Calls [Member]
Commodity derivatives:		1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Forward Swaps [Member]
Commodity derivatives:	23	4
Commodity derivatives:	(22)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Future [Member]
Commodity derivatives:		1
Commodity derivatives:		(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Options - Calls [Member]
Commodity derivatives:		1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:		1
Commodity derivatives:		(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Options - Calls [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:	23	4
Commodity derivatives:	(22)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Options - Calls [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Future [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Forward Swaps [Member]
Commodity derivatives:		2
Commodity derivatives:	(1)	(23)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member]
Commodity derivatives:	1
Commodity derivatives:	(28)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:		2
Commodity derivatives:	(1)	(23)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	1
Commodity derivatives:	(28)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:		9
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Future [Member]
Commodity derivatives:	2
Commodity derivatives:		(13)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:		9
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 1 [Member] | Future [Member]
Commodity derivatives:	2
Commodity derivatives:		(13)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 2 [Member] | Future [Member]
Commodity derivatives:	0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 3 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 3 [Member] | Future [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	11	14
Commodity derivatives:	(24)	(11)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	13	2
Commodity derivatives:	(15)	(3)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	70	96
Commodity derivatives:	(57)	(149)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	8	1
Commodity derivatives:	2
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	11	14
Commodity derivatives:	(24)	(11)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	0	0
Commodity derivatives:	(1)	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	70	96
Commodity derivatives:	(57)	(149)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:	13	2
Commodity derivatives:	(14)	(3)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:	0	0
Commodity derivatives:	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:	8	1
Commodity derivatives:	2
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Basis Swaps IFERC NYMEX [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives:		0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Forward Physical Swaps [Member]
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Forward Swaps [Member]
Commodity derivatives:	193	233
Commodity derivatives:	(192)	(273)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives:	193	233
Commodity derivatives:	(192)	(273)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives:	0	0
Commodity derivatives:		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives:		0
Commodity derivatives:		$ 0

XML

Acquisitions and Related Transactions Acquisitions (2018 Transactions) (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Jan. 31, 2018	Oct. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Goodwill, Impairment Loss			$ 895	$ 897
Payments to Acquire Businesses, Gross		$ 382
Subsequent Event [Member] | CDM Contribution [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 1,700
Payments to Acquire Businesses, Gross	$ 1,225
USA Compression Partners, LP [Member] | Subsequent Event [Member] | CDM Contribution [Member]
Business Acquisition [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	19,191,351
Equity Issued in Business Combination, Fair Value Disclosure	$ 335
USA Compression Partners, LP [Member] | Subsequent Event [Member] | CDM Contribution [Member] | Class B Units [Member]
Business Acquisition [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	6,397,965
Equity Issued in Business Combination, Fair Value Disclosure	$ 112
ETE [Member] | USA Compression Partners, LP [Member] | Subsequent Event [Member] | CDM Contribution [Member]
Business Acquisition [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	12,466,912
Equity Issued in Business Combination, Fair Value Disclosure	$ 250
Investment In Sunoco LP [Member]
Business Acquisition [Line Items]
Goodwill, Impairment Loss			102
Retail Divestment [Member]
Business Acquisition [Line Items]
Goodwill, Impairment Loss			$ 285	$ 447	$ 0

XML

Acquisitions and Related Transactions Acquisitions (2017 Transactions) (Details) - USD ($) $ in Millions	1 Months Ended				12 Months Ended
	Oct. 31, 2017	Jul. 31, 2017	Feb. 28, 2017	Oct. 31, 2015	Dec. 31, 2016		Dec. 31, 2015	Dec. 31, 2017	Feb. 01, 2017
Business Acquisition [Line Items]
Noncontrolling Interest, Increase from Sale of Parent Equity Interest		$ 988			$ 779		$ 65
Intangible assets, net					5,512	[1]		$ 6,116
Property, Plant and Equipment, Net					$ 53,578	[1]		$ 61,088
Permian Express Partners LLC [Member]
Business Acquisition [Line Items]
Percent of total equity ownership of a subsidiary		88.00%
Intangible assets, net									$ 547
Property, Plant and Equipment, Net									$ 435
ETP [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.10%
ETP [Member] | Holdco [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		49.90%
Holdco [Member] | Rover Pipeline LLC [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		65.00%
Blackstone [Member] | Rover Contribution [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	49.90%
Dakota Access and ETCOC [Member]
Business Acquisition [Line Items]
Percent of total equity ownership of a subsidiary		15.00%
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				75.00%
Phillips 66 Company [Member] | Dakota Access and ETCOC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			25.00%
Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				40.00%
Bakken Holdings Company LLC [Member] | Sunoco Logistics [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			49.00%
Bakken Holdings Company LLC [Member] | ETP [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Bakken Holdings Company LLC [Member] | Bakken Pipeline Investments LLC [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired									200000000000.00%
Bakken Pipeline Investments LLC [Member] | Dakota Access and ETCOC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			75.00%

[1] * As adjusted. See Note 2.

XML

Acquisitions and Related Transactions Acquisitions (2016 Narrative) (Details) shares in Millions, barrels in Millions	1 Months Ended
	Feb. 28, 2017	Nov. 30, 2016 USD ($) barrels	Oct. 31, 2016 USD ($)	Aug. 31, 2016 USD ($)	Apr. 30, 2016	Mar. 31, 2016 USD ($) shares	Oct. 31, 2015 USD ($)	Dec. 31, 2017 USD ($)	Feb. 01, 2017	Dec. 31, 2016 USD ($)		Nov. 01, 2016 USD ($)	Aug. 01, 2016 USD ($)	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross							$ 382,000,000
Property, Plant and Equipment, Net								$ 61,088,000,000		$ 53,578,000,000	[1]
Intangible assets, net								6,116,000,000		5,512,000,000	[1]
Goodwill								4,768,000,000		5,670,000,000	[1]			$ 6,056,000,000
PennTex Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Goodwill, Expected Tax Deductible Amount												$ 0
Intangible assets												446,000,000
Business Combination, Consideration Transferred		$ 627,000,000
Goodwill(1)												177,000,000
Total consideration, net of cash received												$ 606,000,000
Vitol Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred		$ 760,000,000
Crude Oil Terminal, Capacity, Bbls | barrels		2
Total consideration, net of cash received		$ 769,000,000
Net Working Capital		13,000,000
Property, Plant and Equipment, Net		286,000,000
Intangible assets, net		313,000,000
Goodwill		$ 251,000,000
Sunoco Retail to Sunoco LP [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred						$ 2,230,000,000
Payments to Acquire Businesses, Gross						$ 2,200,000,000
Sale of Stock, Number of Shares Issued in Transaction | shares						5.7
SunVit Pipeline LLC [Member] | Vitol Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		50.00%
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Sunoco LP [Member] | Emerge Energy Services [Member]
Business Acquisition [Line Items]
Business Acquisition, Goodwill, Expected Tax Deductible Amount													$ 53,000,000
Intangible assets													56,000,000
Business Combination, Consideration Transferred				$ 171,000,000
Sunoco LP [Member] | Convenience Stores [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred			$ 55,000,000	$ 114,000,000
Goodwill(1)													61,000,000
Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest							40.00%
Bayou Bridge Pipeline LLC [Member] | ETP and Sunoco Logistics [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					30.00%
Dakota Access and ETCOC [Member] | Phillips 66 Company [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	25.00%
Dakota Access and ETCOC [Member] | Bakken Pipeline Investments LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	75.00%
ETP [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Sunoco Logistics [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	49.00%
Bakken Pipeline Investments LLC [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired									200000000000.00%
Sunoco, LLC [Member] | ETP [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest						68.42%
Legacy Sunoco, Inc. [Member] | ETP [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest						100.00%
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Pipeline [Member]
Business Acquisition [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity													2,500,000,000
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Business Acquisition [Line Items]
Long-term Line of Credit								$ 2,500,000,000		$ 1,100,000,000			$ 2,500,000,000

[1] * As adjusted. See Note 2.

XML

Acquisitions and Related Transactions Acquisitions (2015 Transactions) (Details) $ in Millions, gallons in Billions	1 Months Ended						3 Months Ended	12 Months Ended
	Feb. 28, 2018 shares	Feb. 28, 2017	Oct. 31, 2015 USD ($) shares	Jul. 31, 2015 USD ($) shares	Apr. 30, 2015 USD ($) gallons shares	Mar. 31, 2015 USD ($) shares	Mar. 31, 2015 USD ($) shares	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross | $			$ 382
Class H Units [Member]
Business Acquisition [Line Items]
Allocation of Profits, Losses and Other by Sunoco, Percent											90.05%
Partners' Capital Account, Units						50,200,000	50,200,000
Class B Units [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			9,400,000
Dropdown of Sunoco LLC Interest [Member]
Business Acquisition [Line Items]
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage					31.58%
Business Combination, Consideration Transferred | $					$ 816
Gallons of motor fuel distributed | gallons					5.3
Payments to Acquire Businesses, Gross | $					$ 775
Equity Issued in Business Combination, Fair Value Disclosure | $					$ 41
Dropdown of Susser [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross | $				$ 970
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable | $				$ 970
Sunoco LP Exchange [Member]
Business Acquisition [Line Items]
Stock Repurchased During Period, Shares				31,500,000
IDR Subsidies | $				$ 35
Term of IDR Subsidy				10 years
Bakken Pipeline Transaction [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred | $						$ 879
Partners' Capital Account, Units, Redeemed						46,200,000
Class I Distributions | $							$ 55					$ 30
Bakken Pipeline Transaction [Member] | Class H Units [Member]
Business Acquisition [Line Items]
Allocation of Profits, Losses and Other by Sunoco, Percent						90.05%	90.05%
Partners' Capital Account, Units, Redeemed						30,800,000
Bakken Pipeline Transaction [Member] | Class I Units [Member]
Business Acquisition [Line Items]
Partners' Capital Account, Units						100	100
Regency Merger [Member]
Business Acquisition [Line Items]
Business Acquisition, Number Of Share Received In Exchange Of Each Share					0.6186
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					258,300,000
Relinquishment of Incentive Distributions | $											$ 60		$ 80
Susser [Member] | Dropdown of Susser [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				100.00%
Sunoco LP [Member] | Dropdown of Susser [Member]
Business Acquisition [Line Items]
Sale of Stock, Number of Shares Issued in Transaction				22,000,000
Sunoco LP [Member] | Dropdown of Susser [Member] | Class A Units [Member]
Business Acquisition [Line Items]
Sale of Stock, Number of Shares Issued in Transaction				79,308
Sunoco GP [Member] | Sunoco LP Exchange [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				100.00%
Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			40.00%
Dakota Access and ETCOC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			75.00%
ETP [Member] | Sunoco LP [Member] | Dropdown of Susser [Member]
Business Acquisition [Line Items]
Sale of Stock, Number of Shares Issued in Transaction				10,900,000
ETP [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Parent Company [Member] | Bakken Pipeline Transaction [Member]
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest						45.00%
ETP Subsidiaries [Member] | Regency Merger [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					23,300,000
ETP Series A Preferred Units [Member] | Regency Merger [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					1,900,000
Subsequent Event [Member]
Business Acquisition [Line Items]
Relinquishment of Incentive Distributions | $								$ 33	$ 128	$ 153
Subsequent Event [Member] | Regency Merger [Member]
Business Acquisition [Line Items]
Relinquishment of Incentive Distributions | $								$ 320
Subsequent Event [Member] | Sunoco LP [Member]
Business Acquisition [Line Items]
Stock Repurchased During Period, Shares	17,286,859

XML

Acquisitions (Schedule Of Assets Acquired And Liabilities Assumed In Acquisition Table) (Details) - PennTex Acquisition [Member] $ in Millions	Nov. 01, 2016 USD ($)
Business Acquisition [Line Items]
Current assets	$ 34
Property, plant and equipment	393
Goodwill(1)	177
Intangible assets	446
Total assets acquired	1,050
Current liabilities	6
Long-term debt obligations, less current maturities	164
Other non-current liabilities	17
Noncontrolling interest	236
Total liabilities assumed	423
Total consideration	627
Cash received	21
Total consideration, net of cash received	$ 606

XML

Acquisitions and Related Transactions Acquisitions (Schedule of Discontinued Operations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Revenue	$ 6,964	$ 5,712		$ 6,030
Disposal Group, Including Discontinued Operation, Costs of Goods Sold	5,806	4,649		5,026
Disposal Group, Including Discontinued Operation, Operating Expense	763	744		705
Disposal Group, Including Discontinued Operation, Depreciation and Amortization	34	143		128
Disposal Group, Including Discontinued Operation, General and Administrative Expense	168	114		91
Goodwill, Impairment Loss	895	897
Disposal Group, Including Discontinued Operations, Total Costs and Expenses	7,056	6,097		5,950
Disposal Group, Including Discontinued Operation, Operating Income (Loss)	(92)	(385)		80
Disposal Group, Including Discontinued Operation, Interest Expense	36	28		21
Disposal Group, Including Discontinued Operation, Other Expense	1	8		(2)
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax	(129)	(421)		61
Discontinued Operation, Tax Effect of Discontinued Operation	48	41		23
Income (loss) from discontinued operations, net of income taxes	(177)	(462)	[1]	38	[1]
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents	21	16
Disposal Group, Including Discontinued Operation, Inventory	149	150
Disposal Group, Including Discontinued Operation, Other Assets, Current	16	11
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	1,851	1,860
Disposal Group, Including Discontinued Operation, Goodwill	796	1,068
Disposal Group, Including Discontinued Operation, Intangible Assets	477	480
Disposal Group, Including Discontinued Operation, Other Assets	3	3
Disposal Group, Including Discontinued Operation, Assets	3,313	3,588
Disposal Group, Including Discontinued Operation, Liabilities	75	48
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	(6)	(12)		1
Retail Divestment [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill, Impairment Loss	$ 285	$ 447		$ 0

[1] * As adjusted. See Note 2.

XML

Advances to and Investments in Unconsolidated Affiliates Narrative (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	[1]	Dec. 31, 2015
Impairment of investments in unconsolidated affiliates		$ 313	$ 308		$ 0	[1]
Impairment losses		1,039	1,040		339	[1]
Payments to Acquire Businesses, Gross	$ 382
Proceeds from the sale of other assets		48	35		14	[1]
Advances to and investments in unconsolidated affiliates		2,705	3,040		3,462
Goodwill		4,768	5,670		6,056
Equity in earnings from unconsolidated affiliates		$ 144	$ 270		$ 276	[1]
Citrus [Member]
Interest ownership		50.00%
Business Acquisition, Percentage of Voting Interests Acquired		50.00%
FGT [Member]
Percentage Ownership Operating Facility		100.00%
Fayetteville Express Pipeline, LLC [Member]
Interest ownership		50.00%
FEP [Member]
Impairment of investments in unconsolidated affiliates		$ 141
Midcontinent Express Pipeline, LLC [Member]
Interest ownership		50.00%
RIGS Haynesville Partnership Co. [Member]
Interest ownership		49.99%
Impairment of investments in unconsolidated affiliates		$ (172)
Impairment losses		$ 185

[1] * As adjusted. See Note 2.

XML

Advances to and Investments in Unconsolidated Affiliates Investment in Affiliates (Carrying Values) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Equity in earnings from unconsolidated affiliates		$ 144	$ 270	[1]	$ 276	[1]
Advances to and investments in unconsolidated affiliates		2,705	3,040	[1]	3,462
Citrus [Member]
Equity in earnings from unconsolidated affiliates		144	102		97
Advances to and investments in unconsolidated affiliates		1,754	1,729
FEP [Member]
Equity in earnings from unconsolidated affiliates		53	51		55
Advances to and investments in unconsolidated affiliates		121	101
MEP [Member]
Equity in earnings from unconsolidated affiliates		38	40		45
Advances to and investments in unconsolidated affiliates		242	318
RIGS Haynesville Partnership Co. [Member]
Equity in earnings from unconsolidated affiliates	[2]	(168)	31		32
Advances to and investments in unconsolidated affiliates		28	382
Other Affiliates [Member]
Equity in earnings from unconsolidated affiliates		77	46		$ 47
Advances to and investments in unconsolidated affiliates		$ 560	$ 510

[1] * As adjusted. See Note 2.

[2] For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.

XML

Investments in Affiliates (Summarized Balance Sheet Information) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Investment In Affiliates [Abstract]
Current assets	$ 206	$ 214
Property, plant and equipment, net	8,336	8,726
Other assets	43	181
Total assets	8,585	9,121
Current Liabilities	861	816
Non-current liabilities	4,492	4,940
Equity	3,232	3,365
Total liabilities and equity	$ 8,585	$ 9,121

XML

Investments in Affiliates (Summarized Income Statement Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investment In Affiliates [Abstract]
Revenues	$ 1,358	$ 1,164	$ 1,385
Operating Income	407	714	800
Net income	$ 145	$ 384	$ 470

XML

Net Income Per Limited Partner Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Earnings Per Share [Abstract]
Income from continuing operations	$ 2,543	$ 462		$ 1,023
Less: Income (loss) from continuing operations attributable to noncontrolling interest	1,583	(545)		(165)
Income from continuing operations, net of noncontrolling interest	960	1,007		1,188
Less: General Partner’s interest in income from continuing operations	2	3		3
Convertible Unitholders’ interest in net income	38	8		0
Less: Class D Unitholder’s interest in income from continuing operations	0	0		3
Income from continuing operations available to Limited Partners	920	996		1,182
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units	38	8		3
Diluted income from continuing operations available to Limited Partners	$ 958	$ 1,004		$ 1,185
Weighted average limited partner units	1,078.2	1,045.5		1,062.8
Basic income from continuing operations per Limited Partner unit	$ 0.86	$ 0.95	[1]	$ 1.11	[1]
Basic income (loss) from discontinued operations per Limited Partner unit	$ (0.01)	$ (0.01)		$ 0.00
Dilutive effect of unconverted unit awards and Convertible Units	72.6	33.1		1.6
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	1,150.8	1,078.6		1,064.4
Diluted income from continuing operations per Limited Partner unit	$ 0.84	$ 0.93	[1]	$ 1.11	[1]
Diluted income (loss) from discontinued operations per Limited Partner unit	$ (0.01)	$ (0.01)		$ 0.00

[1] * As adjusted. See Note 2.

XML

Debt Obligations Debt Obligations (Schedule Of Debt Obligations) (Details) - USD ($) $ in Millions		Dec. 31, 2017	Dec. 31, 2016		Aug. 01, 2016	Apr. 30, 2016
Debt Instrument [Line Items]
Capital Lease Obligations		$ 113	$ 118
Debt Instrument, Unamortized Discount (Premium), Net		197
Other Long-term Debt		8	31
Long-term Debt		44,084	43,802
Current maturities of long-term debt		413	1,194	[1]
Long-term debt, less current maturities		43,671	42,608	[1]
Parent Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		11	15
Deferred Finance Costs, Noncurrent, Net		(34)	(30)
Long-term Debt		6,700	6,357
Long-term debt, less current maturities		6,700	6,358
Parent Company [Member] | ETE 7.5% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		1,187	1,187
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		1,150	1,150
Parent Company [Member] | 5.5% Senior Notes due June 1, 2027 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000	1,000
Parent Company [Member] | 4.25% Senior Notes due March 15, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000	0
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument [Line Items]
Secured Debt		0	2,190
Parent Company [Member] | ETE Senior Secured Term Loan due February 2, 2024 [Member]
Debt Instrument [Line Items]
Secured Debt		1,220	0
Parent Company [Member] | ETE Senior Secured Revolving Credit Facility due December 18, 2018 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		0	875
Parent Company [Member] | ETE Senior Secured Revolving Credit Facility due March 24, 2022 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		1,188	0
ETP [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		33	66
Deferred Finance Costs, Noncurrent, Net		(170)	(166)
Long-term Debt		29,210	29,454
ETP [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		277	277
ETP [Member] | 4.05% Senior Notes due March 2025 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000	1,000
ETP [Member] | 4.75% Senior Notes due January 2026 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000	1,000
ETP [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes		267	267
ETP [Member] | 4.90% Senior Notes due March 2035 [Member]
Debt Instrument [Line Items]
Senior Notes		500	500
ETP [Member] | 6.625% Senior Notes, due October 15, 2036 [Member]
Debt Instrument [Line Items]
Senior Notes		400	400
ETP [Member] | 7.5% Senior Notes, due July 1, 2038 [Member]
Debt Instrument [Line Items]
Senior Notes		550	550
ETP [Member] | Senior Notes 6.05% Due June 1, 2041 [Member]
Debt Instrument [Line Items]
Senior Notes		700	700
ETP [Member] | Senior Notes 6.50% Due February 1, 2042 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000	1,000
ETP [Member] | 5.15% Senior Notes due February 1, 2043 [Member]
Debt Instrument [Line Items]
Senior Notes		450	450
ETP [Member] | 5.95% Senior Notes due October 1, 2043 [Member]
Debt Instrument [Line Items]
Senior Notes		450	450
ETP [Member] | 5.15% Senior Notes due March 2045 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000	1,000
ETP [Member] | 6.125% Senior Notes due December 2045 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000	1,000
ETP [Member] | 5.30% Senior Notes due April 2047 [Member]
Debt Instrument [Line Items]
Senior Notes		900	0
ETP [Member] | 5.40% Senior Notes due October 1, 2047 [Member]
Debt Instrument [Line Items]
Senior Notes		1,500	0
ETP [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Junior Subordinated Notes		546	546
ETP [Member] | ETP Credit Facility due December 2022 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		2,292	0
ETP [Member] | ETP Credit Facility due November 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		0	2,777
ETP [Member] | 6.125% Senior Notes, due February 15, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		0	400
ETP [Member] | 2.50% Senior Notes due June 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	[2]	650	650
ETP [Member] | 6.7% Senior Notes, due July 1, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes	[2]	600	600
ETP [Member] | 9.7% Senior Notes, due March 15, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes		400	400
ETP [Member] | 9.0% Senior Notes due April 15, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes		450	450
ETP [Member] | 5.75% Senior Notes due September 1, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		400	400
ETP [Member] | 4.15% Senior Notes due October 1, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		1,050	1,050
ETP [Member] | 5.875% Senior Notes due April 1, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		900	900
ETP [Member] | 5.5% Senior Notes, due April 15, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		0	700
ETP [Member] | 4.5% Senior Notes due November 1, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		600	600
ETP [Member] | 4.9% Senior Notes due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		350	350
ETP [Member] | 6.5% Senior Notes due May 15, 2021 [Member]
Debt Instrument [Line Items]
Senior Notes		0	500
ETP [Member] | Senior Notes 4.65% Due June 1, 2021 [Member]
Debt Instrument [Line Items]
Senior Notes		800	800
ETP [Member] | Senior Notes 5.20% Due February 1, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		1,000	1,000
ETP [Member] | 5.0% Senior Notes due October 1, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		700	700
ETP [Member] | 3.6% Senior Notes due February 1, 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		800	800
ETP [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	[3]	50	0
Sunoco [Member] | 5.75% Senior Notes, due 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		0	400
Sunoco [Member] | 9.00% Debentures, due 2024 [Member]
Debt Instrument [Line Items]
Subordinated Debt		65	65
Sunoco Logistics [Member] | 5.50% Senior Notes, due February 15, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		250	250
Sunoco Logistics [Member] | Senior Note 4.65% Due February 15, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		300	300
Sunoco Logistics [Member] | 3.45% Senior Notes due January 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		350	350
Sunoco Logistics [Member] | 6.85% Senior Notes, due February 15, 2040 [Member]
Debt Instrument [Line Items]
Senior Notes		250	250
Sunoco Logistics [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		500	500
Sunoco Logistics [Member] | 5.95% Senior Notes due December 2025 [Member]
Debt Instrument [Line Items]
Senior Notes		400	400
Sunoco Logistics [Member] | 3.90% Senior Notes due July 15, 2026 [Member]
Debt Instrument [Line Items]
Senior Notes		550	550
Sunoco Logistics [Member] | 4.20% Senior Notes due April 2027 [Member]
Debt Instrument [Line Items]
Senior Notes		600	0
Sunoco Logistics [Member] | 4.00% Senior Notes due October 1, 2027 [Member]
Debt Instrument [Line Items]
Senior Notes		750	0
Sunoco Logistics [Member] | Senior Note 6.10%, due February 15, 2042 [Member]
Debt Instrument [Line Items]
Senior Notes		300	300
Sunoco Logistics [Member] | 5.30% Senior Notes due April 1, 2044 [Member]
Debt Instrument [Line Items]
Senior Notes		700	700
Sunoco Logistics [Member] | 5.35% Senior Notes due May 15, 2045 [Member]
Debt Instrument [Line Items]
Senior Notes		800	800
Sunoco Logistics [Member] | 4.95% Senior Notes due January 2043 [Member]
Debt Instrument [Line Items]
Senior Notes		350	350
Sunoco Logistics [Member] | Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		0	1,292
Sunoco Logistics [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		0	630
Bakken Project [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net		(8)	(13)
Long-term Debt		2,492	1,087
Bakken Project [Member] | Bakken Project $2.50 billion Credit Facility due August 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		2,500	1,100		$ 2,500
PennTex [Member] | PennTex $275 million Revolving Credit Facility due December 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		0	168
Sunoco LP [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net		(34)	(47)
Long-term Debt		4,287	4,514
Sunoco LP [Member] | 5.5% Senior Notes due August 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		600	600
Sunoco LP [Member] | 6.375% Senior Notes due April 2023 [Member]
Debt Instrument [Line Items]
Senior Notes		800	800
Sunoco LP [Member] | 6.25% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Senior Notes		800	800			$ 800
Sunoco LP [Member] | Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		765	1,000
Sunoco LP [Member] | Term loan due 2019 [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		1,243	1,243
Long-term Debt		2,035
Transwestern [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net		(1)	(1)
Long-term Debt		574	656
Transwestern [Member] | 5.64% Senior Unsecured Notes, due May 24, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		0	82
Transwestern [Member] | 5.36% Senior Unsecured Notes, due December 9, 2020 [Member]
Debt Instrument [Line Items]
Senior Notes		175	175
Transwestern [Member] | 5.89% Senior Unsecured Notes, due May 24, 2022 [Member]
Debt Instrument [Line Items]
Senior Notes		150	150
Transwestern [Member] | 5.66% Senior Unsecured Notes, due December 9, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		175	175
Transwestern [Member] | 6.16% Senior Unsecured Notes, due May 24, 2037 [Member]
Debt Instrument [Line Items]
Senior Notes		75	75
Panhandle [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net		(28)	(50)
Long-term Debt		813	1,135
Panhandle [Member] | 7.60% Senior Notes, due February 1, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		82	82
Panhandle [Member] | 8.25% Senior Notes, due November 14, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes		33	33
Panhandle [Member] | 7.2% Junior Subordinated Notes due November 21, 2066 [Member]
Debt Instrument [Line Items]
Junior Subordinated Notes		54	54
Panhandle [Member] | 6.20% Senior Notes, due November 1, 2017 [Member]
Debt Instrument [Line Items]
Senior Notes		0	300
Panhandle [Member] | 7.00% Senior Notes, due June 15, 2018 [Member]
Debt Instrument [Line Items]
Senior Notes		400	400
Panhandle [Member] | 8.125% Senior Notes, due June 1, 2019 [Member]
Debt Instrument [Line Items]
Senior Notes		150	150
Panhandle [Member] | 7.00% Senior Notes, due July 15, 2029 [Member]
Debt Instrument [Line Items]
Senior Notes		$ 66	$ 66

[1] * As adjusted. See Note 2.

[2] As of December 31, 2017 ETP’s management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.

[3] Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.

XML

Debt Obligations Debt Obligations (Future Maturities of Long-Term Debt) (Details) $ in Millions	Dec. 31, 2017 USD ($)
Debt Obligations [Abstract]
2018	$ 1,705
2019	5,512
2020	3,667
2021	2,205
2022	6,540
Thereafter	24,652
Long-term Debt	$ 44,281

XML

Debt Obligations (Debt Narrative) (Details) - USD ($) $ in Millions		1 Months Ended			12 Months Ended
		Jan. 31, 2018	Jan. 31, 2017	Apr. 30, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Aug. 01, 2016	Apr. 30, 2015
Noncontrolling interest					$ 31,176	$ 24,125	[1]
Less: Net income (loss) attributable to noncontrolling interest					1,412	(995)	[1]	$ (128)	[1]
Proceeds from Issuance of Private Placement			$ 580
Repayments of Long-term Debt					31,268	19,076	[1]	19,828	[1]
Long-term Debt					44,084	43,802
Proceeds from borrowings					31,608	25,785	[1]	26,455	[1]
Advances to and investments in unconsolidated affiliates					2,705	3,040	[1]	3,462
Equity in earnings from unconsolidated affiliates					144	270	[1]	276	[1]
Parent Company [Member]
Repayments of Long-term Debt					1,881	210		1,985
Long-term Debt					6,700	6,357
Proceeds from borrowings					2,219	225		3,672
Advances to and investments in unconsolidated affiliates					6,082	5,088
Equity in earnings from unconsolidated affiliates					$ 1,381	1,511		1,601
Parent Company [Member] | ETE Senior Secured Term Loan due February 2, 2024 [Member]
Debt Instrument, Covenant Description					Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP , and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP, and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.
Debt Instrument, Collateral					Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries
Debt Instrument, Maturity Date					Feb. 02, 2024
Line of Credit Facility, Maximum Borrowing Capacity					$ 2,200
Parent Company [Member] | ETE Senior Secured Revolving Credit Facility due March 24, 2022 [Member]
Line of Credit Facility, Current Borrowing Capacity					312
Outstanding borrowings					$ 1,188	0
Debt Instrument, Maturity Date					Mar. 24, 2022
Parent Company [Member] | ETE Senior Secured Revolving Credit Facility due December 18, 2018 [Member]
Outstanding borrowings					$ 0	875
Parent Company [Member] | 4.25% Senior Notes due March 15, 2023 [Member]
Senior Notes					1,000	0
Proceeds from Issuance of Senior Long-term Debt					$ 990
Debt instrument, interest rate, stated percentage					4.25%
Debt Instrument, Maturity Date					Mar. 15, 2023
Parent Company [Member] | 5.5% Senior Notes due June 1, 2027 [Member]
Senior Notes					$ 1,000	1,000
Debt instrument, interest rate, stated percentage					5.50%
Debt Instrument, Maturity Date					Jun. 01, 2027
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Senior Notes					$ 1,150	1,150
Debt instrument, interest rate, stated percentage					5.88%
Debt Instrument, Maturity Date					Jan. 15, 2024
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument, Maturity Date					Dec. 02, 2019
PennTex [Member] | PennTex $275 million Revolving Credit Facility due December 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity					$ 275
Outstanding borrowings					0	168
Sunoco [Member] | 5.75% Senior Notes, due 2017 [Member]
Senior Notes					$ 0	400
Debt instrument, interest rate, stated percentage					5.75%
Debt Instrument, Maturity Date					Jan. 15, 2017
Panhandle [Member]
Long-term Debt					$ 813	1,135
Junior Subordinated Notes, Noncurrent					$ 54
Panhandle [Member] | 3.26% Junior Subordinated Notes due November 1, 2066 [Member]
Debt Instrument, Interest Rate, Effective Percentage					4.39%
Panhandle [Member] | Junior Subordinated Debt [Member]
Debt Instrument, Description of Variable Rate Basis					three-month LIBOR rate plus 3.0175%
ETP [Member]
Proceeds from Issuance of Private Placement			$ 568
Long-term Debt					$ 29,210	29,454
ETP [Member] | ETP Credit Facility due December 2022 [Member]
Line of Credit Facility, Current Borrowing Capacity					1,560
Letters of Credit Outstanding, Amount					150
Outstanding borrowings					2,292	0
Long-term Commercial Paper, Noncurrent					2,010
Line of Credit Facility, Maximum Borrowing Capacity					$ 4,000
Line of Credit Facility, Interest Rate at Period End					2.48%
ETP [Member] | 2.50% Senior Notes due June 2018 [Member]
Senior Notes	[2]				$ 650	650
Debt instrument, interest rate, stated percentage					2.50%
Debt Instrument, Maturity Date					Jun. 15, 3028
ETP [Member] | 6.7% Senior Notes, due July 1, 2018 [Member]
Senior Notes	[2]				$ 600	600
Debt instrument, interest rate, stated percentage					6.70%
Debt Instrument, Maturity Date					Jul. 01, 2018
ETP [Member] | 3.26% Junior Subordinated Notes due November 1, 2066 [Member]
Debt instrument, interest rate, stated percentage					7.20%
Debt Instrument, Maturity Date					Nov. 01, 2066
ETP [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Debt instrument, interest rate, stated percentage					4.25%
Debt Instrument, Maturity Date					Apr. 01, 2024
ETP [Member] | 5.875% Senior Notes due April 1, 2022 [Member]
Senior Notes					$ 900	900
Debt instrument, interest rate, stated percentage					5.88%
Debt Instrument, Maturity Date					Mar. 01, 2022
ETP [Member] | 5.0% Senior Notes due October 1, 2022 [Member]
Senior Notes					$ 700	700
Debt instrument, interest rate, stated percentage					5.00%
Debt Instrument, Maturity Date					Oct. 01, 2022
ETP [Member] | 4.40% Senior Notes due April 2021 [Member]
Debt instrument, interest rate, stated percentage					4.40%
Debt Instrument, Maturity Date					Apr. 01, 2021
ETP [Member] | 3.90% Senior Notes due July 15, 2026 [Member]
Debt instrument, interest rate, stated percentage					3.90%
Debt Instrument, Maturity Date					Jul. 15, 2026
ETP [Member] | ETP Credit Facility due November 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity					$ 3,750
Outstanding borrowings					0	2,777
ETP [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Line of Credit Facility, Current Borrowing Capacity					950
Outstanding borrowings	[3]				50	0
Line of Credit Facility, Maximum Borrowing Capacity					$ 1,000
Line of Credit Facility, Interest Rate at Period End					5.00%
ETP [Member] | Minimum [Member] | ETP Credit Facility due December 2022 [Member]
Line of Credit Facility, Commitment Fee Percentage					0.125%
ETP [Member] | Minimum [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Line of Credit Facility, Commitment Fee Percentage					0.125%
ETP [Member] | Maximum [Member] | ETP Credit Facility due December 2022 [Member]
Line of Credit Facility, Commitment Fee Percentage					0.30%
ETP [Member] | Maximum [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Line of Credit Facility, Commitment Fee Percentage					0.225%
Sunoco Logistics [Member] | 5.35% Senior Notes due May 15, 2045 [Member]
Senior Notes					$ 800	800
Sunoco Logistics [Member] | 4.25% Senior Notes due April 1, 2024 [Member]
Senior Notes					500	500
Sunoco Logistics [Member] | 4.40% Senior Notes due April 2021 [Member]
Senior Notes					600	600
Sunoco Logistics [Member] | 3.90% Senior Notes due July 15, 2026 [Member]
Senior Notes					550	550
Sunoco Logistics [Member] | Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member]
Line of Credit Facility, Current Borrowing Capacity					2,500
Outstanding borrowings					0	1,292
Sunoco Logistics [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Line of Credit Facility, Current Borrowing Capacity					1,000
Outstanding borrowings					0	630
Bakken Project [Member]
Long-term Debt					2,492	1,087
Bakken Project [Member] | Bakken Project $2.50 billion Credit Facility due August 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity					2,500
Outstanding borrowings					$ 2,500	1,100				$ 2,500
Line of Credit Facility, Interest Rate at Period End					3.00%
ETP GP [Member]
Noncontrolling interest					$ 28,020	18,410
Less: Net income (loss) attributable to noncontrolling interest					1,080	(660)		$ 325
Sunoco LP [Member]
Long-term Debt					4,287	4,514
Sunoco LP [Member] | Term loan due 2019 [Member]
Long-term Debt					2,035
Outstanding borrowings					1,243	1,243
Sunoco LP [Member] | Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity					1,500						$ 1,250
Letters of Credit Outstanding, Amount					9
Outstanding borrowings					765	1,000
Line of Credit Facility, Remaining Borrowing Capacity					726
Sunoco LP [Member] | 5.5% Senior Notes due August 2020 [Member]
Senior Notes					$ 600	600
Debt instrument, interest rate, stated percentage					5.50%
Debt Instrument, Maturity Date					Aug. 01, 2020
Sunoco LP [Member] | 6.375% Senior Notes due April 2023 [Member]
Senior Notes					$ 800	800
Debt instrument, interest rate, stated percentage					6.375%
Debt Instrument, Maturity Date					Apr. 01, 2023
Sunoco LP [Member] | 6.25% Senior Notes due 2021 [Member]
Senior Notes				$ 800	$ 800	$ 800
Debt instrument, interest rate, stated percentage				6.25%	6.25%
Proceeds from borrowings				$ 789
Debt Instrument, Maturity Date					Apr. 15, 2021
Sunoco LP [Member] | Leverage Ratio [Member]
Debt Instrument, Covenant Description					The Sunoco LP Credit Facilities  require Sunoco LP to maintain a leverage ratio (as defined therein) of not more than (a) as of the last day of each fiscal quarter through December 31, 2017, 6.75 to 1.0, (b) as of March 31, 2018, 6.5 to 1.0, (c) as of June 30, 2018, 6.25 to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (in the case of the quarter ending March 31, 2019 and thereafter, subject to increases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of $50 million, as permitted under the Credit Facilities.  Indebtedness under the Credit Facilities is secured by a security interest in, among other things, all of Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Credit Facilities will be released.
Subsequent Event [Member] | Sunoco LP [Member]
Proceeds from Issuance of Private Placement		$ 2,200
Partners' Capital Account, Units, Treasury Units Purchased		17,286,859
Subsequent Event [Member] | Sunoco LP [Member] | 5.5% Senior Notes due August 2020 [Member]
Debt instrument, interest rate, stated percentage		5.50%
Early Repayment of Senior Debt		$ 600
Subsequent Event [Member] | Sunoco LP [Member] | 4.875% senior notes due 2023 [Member]
Senior Notes		$ 1,000
Debt instrument, interest rate, stated percentage		4.875%
Subsequent Event [Member] | Sunoco LP [Member] | 5.500% senior notes due 2026 [Member]
Senior Notes		$ 800
Debt instrument, interest rate, stated percentage		5.50%
Subsequent Event [Member] | Sunoco LP [Member] | 5.875% senior notes due 2028 [Member]
Senior Notes		$ 400
Debt instrument, interest rate, stated percentage		5.875%
Subsequent Event [Member] | Sunoco LP [Member] | 6.375% Senior Notes due April 2023 [Member]
Debt instrument, interest rate, stated percentage		6.375%
Early Repayment of Senior Debt		$ 800
Subsequent Event [Member] | Sunoco LP [Member] | 6.25% Senior Notes due 2021 [Member]
Debt instrument, interest rate, stated percentage		6.25%
Early Repayment of Senior Debt		$ 800
ETE Credit Facility [Member]
Line of Credit Facility, Current Borrowing Capacity					$ 1,500
Letters Of Credit Availablity					150
Accordion feature [Member] | ETP [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Outstanding borrowings					$ 6,000
Eurodollar [Member] | Maximum [Member]
Debt Instrument, Basis Spread on Variable Rate					2.00%
Eurodollar [Member] | ETP [Member] | Minimum [Member] | ETP Credit Facility due December 2022 [Member]
Debt Instrument, Basis Spread on Variable Rate					1.125%
Eurodollar [Member] | ETP [Member] | Minimum [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Debt Instrument, Basis Spread on Variable Rate					1.125%
Eurodollar [Member] | ETP [Member] | Maximum [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Debt Instrument, Basis Spread on Variable Rate					1.75%
Base Rate Loans [Member] | ETP [Member] | Minimum [Member] | ETP Credit Facility due December 2022 [Member]
Debt Instrument, Basis Spread on Variable Rate					0.125%
Base Rate Loans [Member] | ETP [Member] | Minimum [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Debt Instrument, Basis Spread on Variable Rate					0.25%
Base Rate Loans [Member] | ETP [Member] | Maximum [Member] | ETP Credit Facility due December 2022 [Member]
Debt Instrument, Basis Spread on Variable Rate					1.00%
Base Rate Loans [Member] | ETP [Member] | Maximum [Member] | ETP $1.0 billion 364-day Credit Facility due December 2018 [Member]
Debt Instrument, Basis Spread on Variable Rate					0.75%
Applicable margins for LIBOR rate loans [Member] | Minimum [Member] | ETE Senior Secured Term Loan due February 2, 2024 [Member]
Debt Instrument, Basis Spread on Variable Rate					2.75%
Applicable margins for LIBOR rate loans [Member] | Maximum [Member] | ETE Senior Secured Term Loan due February 2, 2024 [Member]
Debt Instrument, Basis Spread on Variable Rate					2.00%
Letter of Credit [Member] | ETE Senior Secured Term Loan due February 2, 2024 [Member]
Debt Instrument, Basis Spread on Variable Rate					2.75%
Letter of Credit [Member] | ETE Credit Facility [Member] | Minimum [Member]
Debt Instrument, Basis Spread on Variable Rate					1.75%
Letter of Credit [Member] | ETE Credit Facility [Member] | Maximum [Member]
Debt Instrument, Basis Spread on Variable Rate					2.50%
Base Rate Loans [Member] | ETE Senior Secured Term Loan due February 2, 2024 [Member]
Debt Instrument, Basis Spread on Variable Rate					1.75%
Base Rate Loans [Member] | Minimum [Member] | ETE Senior Secured Term Loan due February 2, 2024 [Member]
Debt Instrument, Basis Spread on Variable Rate					1.75%
Base Rate Loans [Member] | Maximum [Member] | ETE Senior Secured Term Loan due February 2, 2024 [Member]
Debt Instrument, Basis Spread on Variable Rate					1.00%
Base Rate Loans [Member] | ETE Credit Facility [Member] | Minimum [Member]
Debt Instrument, Basis Spread on Variable Rate					0.75%
Base Rate Loans [Member] | ETE Credit Facility [Member] | Maximum [Member]
Debt Instrument, Basis Spread on Variable Rate					1.50%

[1] * As adjusted. See Note 2.

[2] As of December 31, 2017 ETP’s management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.

[3] Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.

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Debt Obligations Debt Obligations (Covenants Related To Credit Agrrements) (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Debt Instrument [Line Items]
Leverage Ratio Maximum	6.0
Maximum Leverage Ratio Permitted	7
Supplementary Leverage Ratio	396.00%
Debt instrument covenant minimum fixed charge coverage ratio	1.5
ETP [Member]
Debt Instrument [Line Items]
Leverage Ratio Maximum	5.0
Maximum Leverage Ratio Permitted	5.5
Bakken Project $2.50 billion Credit Facility due August 2019 [Member]
Debt Instrument [Line Items]
Minimum debt service coverage ratio	1.20
Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member] | Sunoco LP [Member]
Debt Instrument [Line Items]
Minimum interest coverage ratio	0
Eurodollar [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%

XML

Debt Obligations Debt Obligations (Interest Rates & Maturities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Apr. 30, 2016
Parent Company [Member]
Deferred Finance Costs, Noncurrent, Net	$ 34	$ 30
ETP [Member]
Deferred Finance Costs, Noncurrent, Net	170	166
Sunoco LP [Member]
Deferred Finance Costs, Noncurrent, Net	34	47
Transwestern [Member]
Deferred Finance Costs, Noncurrent, Net	$ 1	$ 1
6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.375%
Debt Instrument, Maturity Date	Apr. 01, 2023
6.25% Senior Notes due 2021 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.25%		6.25%
Debt Instrument, Maturity Date	Apr. 15, 2021
ETE 7.5% Senior Notes due 2020 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	Oct. 15, 2020
5.875% Senior Notes due January 15, 2024 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	Jan. 15, 2024
5.5% Senior Notes due June 1, 2027 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Jun. 01, 2027
4.25% Senior Notes due March 15, 2023 [Member] | Parent Company [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Debt Instrument, Maturity Date	Mar. 15, 2023
ETE Senior Secured Term Loan due February 2, 2024 [Member] | Parent Company [Member]
Debt Instrument, Maturity Date	Feb. 02, 2024
ETE Senior Secured Term Loan due December 2, 2018 [Member] | Parent Company [Member]
Debt Instrument, Maturity Date	Dec. 02, 2018
ETE Senior Secured Revolving Credit Facility due March 24, 2022 [Member] | Parent Company [Member]
Debt Instrument, Maturity Date	Mar. 24, 2022
ETE Senior Secured Term Loan due December 2, 2019 [Member] | Parent Company [Member]
Debt Instrument, Maturity Date	Dec. 02, 2019
6.125% Senior Notes, due February 15, 2017 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	Feb. 15, 2017
2.50% Senior Notes due June 2018 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument, Maturity Date	Jun. 15, 3028
6.7% Senior Notes, due July 1, 2018 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.70%
Debt Instrument, Maturity Date	Jul. 01, 2018
9.7% Senior Notes, due March 15, 2019 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.70%
Debt Instrument, Maturity Date	Mar. 15, 2019
9.0% Senior Notes due April 15, 2019 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt Instrument, Maturity Date	Apr. 15, 2019
4.15% Senior Notes due October 1, 2020 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Debt Instrument, Maturity Date	Oct. 01, 2020
Senior Notes 4.65% Due June 1, 2021 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	Jun. 01, 2021
Senior Notes 5.20% Due February 1, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.20%
Debt Instrument, Maturity Date	Feb. 01, 2022
3.6% Senior Notes due February 1, 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.60%
Debt Instrument, Maturity Date	Feb. 01, 2023
4.9% Senior Notes due February 1, 2024 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.90%
Debt Instrument, Maturity Date	Feb. 01, 2024
6.625% Senior Notes, due October 15, 2036 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Debt Instrument, Maturity Date	Oct. 15, 2036
4.90% Senior Notes due March 2035 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.90%
Debt Instrument, Maturity Date	Mar. 15, 2035
7.5% Senior Notes, due July 1, 2038 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.50%
Debt Instrument, Maturity Date	Jul. 01, 2038
Senior Notes 6.05% Due June 1, 2041 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.05%
Debt Instrument, Maturity Date	Jun. 01, 2041
Senior Notes 6.50% Due February 1, 2042 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Maturity Date	Feb. 01, 2042
5.15% Senior Notes due February 1, 2043 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt Instrument, Maturity Date	Feb. 01, 2043
5.95% Senior Notes due October 1, 2043 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	Oct. 01, 2043
5.15% Senior Notes due March 2045 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Debt Instrument, Maturity Date	Mar. 15, 2045
6.125% Senior Notes due December 2045 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument, Maturity Date	Dec. 15, 2045
5.30% Senior Notes due April 2047 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.30%
Debt Instrument, Maturity Date	Apr. 01, 2047
5.40% Senior Notes due October 1, 2047 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.40%
Debt Instrument, Maturity Date	Oct. 01, 2047
6.20% Senior Notes, due November 1, 2017 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.20%
Debt Instrument, Maturity Date	Nov. 01, 2017
7.00% Senior Notes, due June 15, 2018 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt Instrument, Maturity Date	Jun. 15, 2018
8.125% Senior Notes, due June 1, 2019 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.125%
Debt Instrument, Maturity Date	Jun. 01, 2019
7.00% Senior Notes, due July 15, 2029 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Debt Instrument, Maturity Date	Jul. 15, 2029
Term Loan due February 23, 2015 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.84%
Debt Instrument, Maturity Date	Feb. 23, 2015
5.75% Senior Notes due September 1, 2020 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument, Maturity Date	Sep. 01, 2020
5.875% Senior Notes due April 1, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.88%
Debt Instrument, Maturity Date	Mar. 01, 2022
5.5% Senior Notes, due April 15, 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Apr. 15, 2023
4.5% Senior Notes due November 1, 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Debt Instrument, Maturity Date	Nov. 01, 2023
6.5% Senior Notes due May 15, 2021 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Maturity Date	May 15, 2021
5.0% Senior Notes due October 1, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Debt Instrument, Maturity Date	Oct. 01, 2022
7.60% Senior Notes, due February 1, 2024 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt Instrument, Maturity Date	Feb. 01, 2024
7.60% Senior Notes, due February 1, 2024 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.60%
Debt Instrument, Maturity Date	Feb. 01, 2024
4.05% Senior Notes due March 2025 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.05%
Debt Instrument, Maturity Date	Mar. 15, 2025
4.75% Senior Notes due January 2026 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.75%
Debt Instrument, Maturity Date	Jan. 15, 2026
8.25% Senior Notes, due November 14, 2029 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt Instrument, Maturity Date	Nov. 15, 2029
8.25% Senior Notes, due November 14, 2029 [Member] | Panhandle [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Debt Instrument, Maturity Date	Nov. 14, 2029
7.2% Junior Subordinated Notes due November 21, 2066 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	7.20%
Debt Instrument, Maturity Date	Nov. 01, 2066
5.75% Senior Notes, due 2017 [Member] | Sunoco [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument, Maturity Date	Jan. 15, 2017
9.00% Debentures, due 2024 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	9.00%
Debt Instrument, Maturity Date	Nov. 01, 2024
5.50% Senior Notes, due February 15, 2020 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Feb. 15, 2020
4.40% Senior Notes due April 2021 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.40%
Debt Instrument, Maturity Date	Apr. 01, 2021
Senior Note 4.65% Due February 15, 2022 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.65%
Debt Instrument, Maturity Date	Feb. 15, 2022
3.45% Senior Notes due January 2023 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.45%
Debt Instrument, Maturity Date	Feb. 01, 2023
4.25% Senior Notes due April 1, 2024 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Debt Instrument, Maturity Date	Apr. 01, 2024
5.95% Senior Notes due December 2025 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Debt Instrument, Maturity Date	Dec. 01, 2025
3.90% Senior Notes due July 15, 2026 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Debt Instrument, Maturity Date	Jul. 15, 2026
4.20% Senior Notes due April 2027 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.20%
Debt Instrument, Maturity Date	Apr. 15, 2027
4.00% Senior Notes due October 1, 2027 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.00%
Debt Instrument, Maturity Date	Oct. 01, 2027
6.85% Senior Notes, due February 15, 2040 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.85%
Debt Instrument, Maturity Date	Feb. 15, 2040
Senior Note 6.10%, due February 15, 2042 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.10%
Debt Instrument, Maturity Date	Feb. 15, 2042
4.95% Senior Notes due January 2043 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.95%
Debt Instrument, Maturity Date	Jan. 15, 2043
5.30% Senior Notes due April 1, 2044 [Member] | ETP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.30%
Debt Instrument, Maturity Date	Apr. 01, 2044
5.54% Senior Unsecured Notes, due November 17, 2016 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.54%
Debt Instrument, Maturity Date	Nov. 17, 2016
5.64% Senior Unsecured Notes, due May 24, 2017 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.64%
Debt Instrument, Maturity Date	May 24, 2017
5.36% Senior Unsecured Notes, due December 9, 2020 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.36%
Debt Instrument, Maturity Date	Dec. 09, 2020
5.89% Senior Unsecured Notes, due May 24, 2022 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.89%
Debt Instrument, Maturity Date	May 24, 2022
5.66% Senior Unsecured Notes, due December 9, 2024 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.66%
Debt Instrument, Maturity Date	Dec. 09, 2024
6.16% Senior Unsecured Notes, due May 24, 2037 [Member] | Transwestern [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.16%
Debt Instrument, Maturity Date	May 24, 2037

XML

Redeemable Preferred Units (Details) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) shares	Dec. 31, 2015 USD ($)	Dec. 31, 2017 shares	Apr. 30, 2015 USD ($) $ / commonunit
Preferred Units, Issued | shares		329,299,267		329,299,267
Mandatory redeemable price of units outstanding					$ 35
Issuance of common units		$ 37	$ 0
Preferred Units Quarterly Cash Distribution Per Unit | $ / commonunit					0.445
Payments for Repurchase of Preferred Stock and Preference Stock	$ 53
ETP Series A Preferred Units [Member]
Partners' Capital Account, Units, Redeemed | shares	1,900,000

XML

Equity (Narrative) (Details) - USD ($)	1 Months Ended											3 Months Ended																								6 Months Ended		12 Months Ended					36 Months Ended
	Feb. 28, 2018	Jan. 31, 2018	Nov. 30, 2017	Aug. 31, 2017	Feb. 28, 2017	Jan. 31, 2017	Oct. 31, 2016	Mar. 31, 2016	Oct. 31, 2015	Jul. 31, 2015	Mar. 31, 2015	Jun. 30, 2018	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014		Dec. 31, 2016		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2017	Feb. 01, 2017	Apr. 30, 2015	Dec. 31, 2013	Oct. 05, 2012
Payments for Repurchase of Preferred Stock and Preference Stock						$ 53,000,000
Preferred Units, Outstanding													329,299,267								329,299,267															329,299,267		329,299,267	329,299,267				329,299,267
Proposed Environmental Penalty				$ 100,000			$ 100,000						$ 0																									$ 0					$ 0
Distribution Made to Limited Partner, Distributions Paid, Per Unit													$ 0.5650		$ 0.5650		$ 0.5500		$ 0.5350
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)													$ 450,000,000								$ 180,000,000	[1]														$ 180,000,000	[1]	450,000,000	$ 180,000,000	[1]			450,000,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest													29,980,000,000								$ 22,431,000,000	[1]							$ 23,553,000,000	[1]				$ 22,301,000,000	[1]	$ 22,431,000,000	[1]	$ 29,980,000,000	$ 22,431,000,000	[1]	$ 23,553,000,000	[1]	29,980,000,000
Stock Issued During Period, Shares, New Issues																																						32,200,000	2,100,000		0
Stock Repurchase Program, Authorized Amount													2,000,000,000																									$ 2,000,000,000					2,000,000,000
Partners' Capital Account, Units, Unit-based Compensation																																						0	0		33,600,000
Stock Repurchase Program, Remaining Authorized Repurchase Amount													$ 936,000,000																									$ 936,000,000					$ 936,000,000
Minimum beneficial percentage ownership, other than the Partnership's General Partner and its affiliates, no voting rights, not considered outstanding													20.00%																									20.00%					20.00%
Limited Partners' Capital Account, Units Outstanding													1,079,145,561								1,046,947,157								1,044,800,000					1,077,500,000		1,046,947,157		1,079,145,561	1,046,947,157		1,044,800,000		1,079,145,561
Limited Partner interest in the Partnership, percentage																																						94.38%
Gain from subsidiary issuances of common units																																						$ (56,000,000)	$ 16,000,000		$ (526,000,000)
Units repurchased under buyback program																																						$ 0	0	[1]	1,064,000,000	[1]
Class E Unit Distribution Rate													11.10%																									11.10%					11.10%
Class E Unit Maximum Distribution													$ 1.41																									$ 1.41					$ 1.41
Class G Unit Distribution Rate													35.00%																									35.00%					35.00%
Class G Unit Maximum Distribution													$ 3.75																									$ 3.75					$ 3.75
Partners' Capital Account, Sale of Units																																						$ 568,000,000
Payments to Acquire Businesses, Gross									$ 382,000,000
Partners' Capital Account, Units, Sold in Private Placement						32,200,000
Proceeds from Issuance of Private Placement						$ 580,000,000
Partners' Capital Account, Units, Sold in Public Offering																																						54,000,000
Proceeds from Issuance of Common Limited Partners Units				$ 997,000,000																																		$ 568,000,000	0	[1]	0	[1]
Parent Company [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit													$ 0.3050	[2]	0.2950	[2]	0.2850	[2]	0.2850	[2]	$ 0.2850	[2]	$ 0.2850	[2]	$ 0.2850	[2]	$ 0.2850	[2]	$ 0.2850	[2]	$ 0.2850	$ 0.2650	$ 0.2450	$ 0.2250
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)													$ 450,000,000								$ 180,000,000															$ 180,000,000		450,000,000	180,000,000				$ 450,000,000
Units repurchased under buyback program																																						0	0		1,064,000,000
Proceeds from Issuance of Common Limited Partners Units																																						$ 568,000,000	0		0
PennTex [Member]
Sale of Stock, Price Per Share																	20.00
Phillips 66 Company [Member] | Dakota Access and ETCOC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					25.00%
ETP [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit																					$ 0.7033		0.7033		0.7033		0.7033		0.7033		0.7033	0.6900	0.6767	0.6633
Common Units Issued Inconnection With The Equity Distribution Agreement																																						22,600,000					25,500,000
Equity Distribution Agreement, maximum aggregate value of common units sold																																						$ 1,000,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement																																						503,000,000
Fees and Commissions																																						5,000,000
Equity Distribution Agreements, Value of Units Available to be Issued													$ 752,000,000																									752,000,000					$ 752,000,000
Stock Issued During Period, Value, Dividend Reinvestment Plan																																						$ 228,000,000	216,000,000		$ 360,000,000
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan													20,800,000																									20,800,000					20,800,000
Partners' Capital Account, Units, Sold in Private Placement						23,700,000
Proceeds from Issuance of Private Placement						$ 568,000,000
ETP [Member] | Sunoco, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest								68.42%
ETP [Member] | Legacy Sunoco, Inc. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest								100.00%
Sunoco Logistics [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit																					0.5200		0.5100		0.5000		0.4890		0.4790		0.4580	0.4380	0.4190	0.4000
Proceeds from Issuance of Common Stock											$ 629,000,000																									$ 644,000,000
Equity Distribution Agreement, maximum aggregate value of common units sold																																							$ 1,250,000,000
Partners' Capital Account, Units, Sale of Units											15,500,000																									24,200,000
Sunoco LP [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit													$ 0.8255		0.8255		0.8255		0.8255		0.8255		0.8255		0.8255		$ 0.8173		$ 0.8013		$ 0.7454	$ 0.6934	$ 0.6450	$ 0.6000
Common Units Issued Inconnection With The Equity Distribution Agreement																																						1,300,000	2,800,000
Equity Distribution Agreement, maximum aggregate value of common units sold							$ 400,000,000
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement					$ 33,000,000																																		$ 71,000,000
Fees and Commissions																																						$ 300,000
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan													295,000,000																									295,000,000					295,000,000
Partners' Capital Account, Units, Sale of Units										5,500,000
Partners' Capital Account, Sale of Units										$ 213,000,000
Partners' Capital Account, Units, Sold in Private Placement								2,300,000
Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest									40.00%
Bakken Holdings Company LLC [Member] | Bakken Pipeline Investments LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired																																												200000000000.00%
Bakken Holdings Company LLC [Member] | Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					49.00%
Bakken Holdings Company LLC [Member] | ETP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					100.00%
Bakken Pipeline Investments LLC [Member] | Dakota Access and ETCOC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					75.00%
Class D Units [Member]
Limited Partners' Capital Account, Units Outstanding																																														3,080,000
Class H Units [Member]
Partners' Capital Account, Units											50,200,000																						50,200,000
Allocation of Profits, Losses and Other by Sunoco, Percent													90.05%																									90.05%					90.05%
Class K Units [Member]
Distribution Made to Limited Partner, Distributions Declared, Per Unit																					$ 0.67275
Common Stock Held by Subsidiary													$ 101,525,429																									$ 101,525,429					$ 101,525,429
Common Class C [Member] | Sunoco LP [Member]
Partners' Capital Account, Units, Sale of Units																											16,400,000
Common Class C [Member] | Sunoco LP [Member] | Aloha Petroleum LP [Member]
Partners' Capital Account, Units, Sale of Units																											5,200,000
Common Class C [Member] | Sunoco LP [Member] | Indirect wholly-owned subsidiary [Member]
Partners' Capital Account, Units, Sale of Units																											11,200,000
Second Target Distribution [Member]
Distribution Payment Targets													0.0833
Series A Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit													$ 15.451
Preferred Stock, Shares Issued			950,000
Preferred Stock, Dividend Rate, Percentage			6.25%
Preferred Units, Offering Costs			$ 1,000
Preferred Stock, Liquidation Preference Per Share			$ 1,000
Preferred Units, Liquidation Spread, Percent			4.028%
Preferred Stock, Redemption Price Per Share													1,000																									$ 1,000					$ 1,000
Series A Preferred Units [Member] | Sunoco LP [Member]
Preferred Stock, Dividend Rate, Percentage																																						10.00%
Preferred Stock, Liquidation Preference Per Share													$ 25.00																									$ 25.00					$ 25.00
Preferred Units, Liquidation Spread, Percent													8.00%																									8.00%					8.00%
Call premium on preferred units.													1.00%																									1.00%					1.00%
Series B Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit													$ 16,378,000
Preferred Stock, Shares Issued			550,000
Preferred Stock, Dividend Rate, Percentage			6.625%
Preferred Units, Offering Costs			$ 1,000
Preferred Stock, Liquidation Preference Per Share			$ 1,000
Preferred Units, Liquidation Spread, Percent			4.155%
Preferred Stock, Redemption Price Per Share													$ 1,000																									$ 1,000					$ 1,000
Holdco Transaction [Member] | Class G Units [Member]
Partners' Capital Account, Units																																															90,700,000
Bakken Pipeline Transaction [Member]
Class I Distributions																																	$ 55,000,000						$ 30,000,000
Partners' Capital Account, Units, Redeemed											46,200,000
Business Combination, Consideration Transferred											$ 879,000,000
Bakken Pipeline Transaction [Member] | Parent Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest											45.00%
Bakken Pipeline Transaction [Member] | Class H Units [Member]
Allocation of Profits, Losses and Other by Sunoco, Percent											90.05%																						90.05%
Partners' Capital Account, Units, Redeemed											30,800,000
Bakken Pipeline Transaction [Member] | Class I Units [Member]
Partners' Capital Account, Units											100																						100
Sunoco Retail to Sunoco LP [Member]
Business Combination, Consideration Transferred								$ 2,230,000,000
Payments to Acquire Businesses, Gross								$ 2,200,000,000
Sale of Stock, Number of Shares Issued in Transaction								5,700,000
Series A Convertible Preferred Units [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest																																						31.50%
Preferred Units, Outstanding													329,295,770								329,300,000								0					0		329,300,000		329,295,770	329,300,000		0		329,295,770
Preferred Stock Conversions, Inducements												$ 6.56
Stock Issued During Period, Shares, New Issues								329,300,000																														0	329,300,000		0
Class E Units [Member] | ETP [Member]
Limited Partners' Capital Account, Units Outstanding													8,900,000																									8,900,000					8,900,000
Class D Units [Member]
Stock Issued During Period, Shares, New Issues																																						0	0		900,000
Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member] | Sunoco Logistics [Member]
Line of Credit Facility, Current Borrowing Capacity													$ 2,500,000,000																									$ 2,500,000,000					$ 2,500,000,000
Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member] | Sunoco LP [Member]
Line of Credit Facility, Current Borrowing Capacity													$ 1,500,000,000																									$ 1,500,000,000					$ 1,500,000,000		$ 1,250,000,000
Subsequent Event [Member] | Sunoco LP [Member]
Stock Repurchased During Period, Shares	17,286,859
Units repurchased under buyback program	$ 540,000,000
Proceeds from Issuance of Private Placement		$ 2,200,000,000
Subsequent Event [Member] | Series A Preferred Units [Member] | Sunoco LP [Member]
Payments for Repurchase of Preferred Stock and Preference Stock		$ 300,000,000
Stock Repurchased and Retired During Period, Shares		12,000,000
Preferred Stock Redemption Premium		$ 313,000,000
IDRs [Member] | Maximum [Member]
Marginal Percentage Interest in Distributions													48.00%																									48.00%					48.00%
Series A Convertible Preferred Units [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest													$ 450,000,000								$ 180,000,000	[1]							$ 0	[1]				$ 0	[1]	$ 180,000,000	[1]	$ 450,000,000	$ 180,000,000	[1]	$ 0	[1]	$ 450,000,000
Partners' Capital Account, Sale of Units																																						$ 0
Series A Convertible Preferred Units [Member] | Parent Company [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit													$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100
Kelcy L. Warren [Member] | Series A Convertible Preferred Units [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest																																						18.00%
Preferred Units, Outstanding													187,313,942																									187,313,942					187,313,942
Messrs. McReynolds, Ramsey and McCrea [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest																																						2.20%
Mr. McReynolds [Member] | Series A Convertible Preferred Units [Member]
Preferred Units, Outstanding													21,382,155																									21,382,155					21,382,155
Mr. Ramsey [Member] | Series A Convertible Preferred Units [Member]
Preferred Units, Outstanding													51,317																									51,317					51,317
Mr. McCrea [Member] | Series A Convertible Preferred Units [Member]
Preferred Units, Outstanding													1,112,728																									1,112,728					1,112,728
Mr. Ray Davis [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest																																						6.90%
Mr. Ray Davis [Member] | LE GP, LLC [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest																																						18.80%
Mr. Ray Davis [Member] | Series A Convertible Preferred Units [Member]
Preferred Units, Outstanding													72,042,486																									72,042,486					72,042,486

[1] * As adjusted. See Note 2.

[2] Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See additional information below.

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Equity (Change In ETE Common Units) (Details) - shares	1 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Preferred Units, Outstanding					329,299,267	329,299,267
Stock Issued During Period, Shares, New Issues		32,200,000	2,100,000	0
Outstanding		1,079,145,561	1,046,947,157	1,044,800,000	1,079,145,561	1,046,947,157	1,044,800,000	1,077,500,000
Issuance of restricted Common Units under long-term incentive plans		0	0	(33,600,000)
Number of Common Units, end of period		1,079,145,561	1,046,947,157	1,044,800,000
Series A Convertible Preferred Units [Member]
Preferred Units, Outstanding					329,295,770	329,300,000	0	0
Stock Issued During Period, Shares, New Issues	329,300,000	0	329,300,000	0
Class D Units [Member]
Stock Issued During Period, Shares, New Issues		0	0	900,000

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Equity (Quarterly Distributions Of Available Cash) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																						12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Distribution Made to Limited Partner, Date of Record	Feb. 08, 2018		Nov. 07, 2017		Aug. 07, 2017		May 10, 2017
Distribution Made to Limited Partner, Distribution Date	Feb. 14, 2018		Nov. 14, 2017		Aug. 15, 2017		May 16, 2017
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.5650		$ 0.5650		$ 0.5500		$ 0.5350
Partners' Capital Account, Distributions																							$ 1,010	$ 1,022	$ 1,090
Parent Company [Member]
Distribution Made to Limited Partner, Date of Record	Feb. 08, 2018	[1]	Nov. 07, 2017	[1]	Aug. 07, 2017	[1]	May 10, 2017	[1]	Feb. 07, 2017	[1]	Nov. 07, 2016	[1]	Aug. 08, 2016	[1]	May 06, 2016	[1]	Feb. 04, 2016		Nov. 05, 2015	Aug. 06, 2015	May 08, 2015	Feb. 06, 2015
Distribution Made to Limited Partner, Distribution Date	Feb. 20, 2018	[1]	Nov. 20, 2017	[1]	Aug. 21, 2017	[1]	May 19, 2017	[1]	Feb. 21, 2017	[1]	Nov. 18, 2016	[1]	Aug. 19, 2016	[1]	May 19, 2016	[1]	Feb. 19, 2016		Nov. 19, 2015	Aug. 19, 2015	May 19, 2015	Feb. 19, 2015
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.3050	[1]	$ 0.2950	[1]	$ 0.2850	[1]	$ 0.2850	[1]	$ 0.2850	[1]	$ 0.2850	[1]	$ 0.2850	[1]	$ 0.2850	[1]	$ 0.2850	[1]	$ 0.2850	$ 0.2650	$ 0.2450	$ 0.2250
ETP [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit									$ 0.7033		$ 0.7033		$ 0.7033		$ 0.7033		$ 0.7033		$ 0.7033	$ 0.6900	$ 0.6767	$ 0.6633
Sunoco LP [Member]
Distribution Made to Limited Partner, Date of Record	Feb. 06, 2018		Nov. 07, 2017		Aug. 07, 2017		May 09, 2017		Feb. 13, 2017		Nov. 07, 2016		Aug. 05, 2016		May 06, 2016		Feb. 05, 2016		Nov. 17, 2015	Aug. 18, 2015	May 19, 2015	Feb. 17, 2015
Distribution Made to Limited Partner, Distribution Date	Feb. 14, 2018		Nov. 14, 2017		Aug. 15, 2017		May 16, 2017		Feb. 21, 2017		Nov. 15, 2016		Aug. 15, 2016		May 16, 2016		Feb. 16, 2016		Nov. 27, 2015	Aug. 28, 2015	May 29, 2015	Feb. 27, 2015
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.8255		$ 0.8255		$ 0.8255		$ 0.8255		$ 0.8255		$ 0.8255		$ 0.8255		$ 0.8173		$ 0.8013		$ 0.7454	$ 0.6934	$ 0.6450	$ 0.6000
Sunoco Logistics [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit									$ 0.5200		$ 0.5100		$ 0.5000		$ 0.4890		$ 0.4790		$ 0.4580	$ 0.4380	$ 0.4190	$ 0.4000
Series A Convertible Preferred Units [Member] | Parent Company [Member]
Distribution Made to Limited Partner, Date of Record	Feb. 08, 2018		Nov. 07, 2017		Aug. 07, 2017		May 10, 2017		Feb. 07, 2017		Nov. 07, 2016		Aug. 08, 2016		May 06, 2016
Distribution Made to Limited Partner, Distribution Date	Feb. 20, 2018		Nov. 20, 2017		Aug. 21, 2017		May 19, 2017		Feb. 21, 2017		Nov. 18, 2016		Aug. 19, 2016		May 19, 2016
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100		$ 0.1100
Preferred Units [Member]
Distribution Made to Limited Partner, Date of Record	Feb. 01, 2018
Distribution Made to Limited Partner, Distribution Date	Feb. 15, 2018
Series A Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 15.451
Series B Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 16,378,000
Minimum Quarterly Distribution [Member] | ETP [Member]
Distribution Payment Targets																							0.0750
Minimum Quarterly Distribution [Member] | Sunoco LP [Member]
Distribution Payment Targets																							.4375
First Target Distribution [Member] | ETP [Member]
Distribution Payment Targets																							up to $0.0833
First Target Distribution [Member] | Sunoco LP [Member]
Distribution Payment Targets																							$0.4375 to $0.503125
Second Target Distribution [Member] | ETP [Member]
Distribution Payment Targets																							above $0.0833 up to $0.0958
Second Target Distribution [Member] | Sunoco LP [Member]
Distribution Payment Targets																							$0.503125 to $0.546875
Third Target Distribution [Member] | ETP [Member]
Distribution Payment Targets																							above $0.0958 up to $0.2638
Third Target Distribution [Member] | Sunoco LP [Member]
Distribution Payment Targets																							$0.546875 to $0.656250
Thereafter [Member] | ETP [Member]
Distribution Payment Targets																							above $0.2638
Thereafter [Member] | Sunoco LP [Member]
Distribution Payment Targets																							Above $0.656250
IDRs [Member] | Minimum Quarterly Distribution [Member] | ETP [Member]
Marginal Percentage Interest in Distributions	0.00%																						0.00%
IDRs [Member] | Minimum Quarterly Distribution [Member] | Sunoco LP [Member]
Marginal Percentage Interest in Distributions	100.00%																						100.00%
IDRs [Member] | First Target Distribution [Member] | ETP [Member]
Marginal Percentage Interest in Distributions	0.00%																						0.00%
IDRs [Member] | First Target Distribution [Member] | Sunoco LP [Member]
Marginal Percentage Interest in Distributions	100.00%																						100.00%
IDRs [Member] | Second Target Distribution [Member] | ETP [Member]
Marginal Percentage Interest in Distributions	13.00%																						13.00%
IDRs [Member] | Second Target Distribution [Member] | Sunoco LP [Member]
Marginal Percentage Interest in Distributions	85.00%																						85.00%
IDRs [Member] | Third Target Distribution [Member] | ETP [Member]
Marginal Percentage Interest in Distributions	35.00%																						35.00%
IDRs [Member] | Third Target Distribution [Member] | Sunoco LP [Member]
Marginal Percentage Interest in Distributions	75.00%																						75.00%
IDRs [Member] | Thereafter [Member] | ETP [Member]
Marginal Percentage Interest in Distributions	48.00%																						48.00%
IDRs [Member] | Thereafter [Member] | Sunoco LP [Member]
Marginal Percentage Interest in Distributions	50.00%																						50.00%
Limited Partner [Member]
Partners' Capital Account, Distributions																							$ 1,008	$ 1,019	$ 1,084
Limited Partner [Member] | Minimum Quarterly Distribution [Member] | ETP [Member]
Marginal Percentage Interest in Distributions	100.00%																						100.00%
Limited Partner [Member] | Minimum Quarterly Distribution [Member] | Sunoco LP [Member]
Marginal Percentage Interest in Distributions	0.00%																						0.00%
Limited Partner [Member] | First Target Distribution [Member] | ETP [Member]
Marginal Percentage Interest in Distributions	100.00%																						100.00%
Limited Partner [Member] | First Target Distribution [Member] | Sunoco LP [Member]
Marginal Percentage Interest in Distributions	0.00%																						0.00%
Limited Partner [Member] | Second Target Distribution [Member] | ETP [Member]
Marginal Percentage Interest in Distributions	87.00%																						87.00%
Limited Partner [Member] | Second Target Distribution [Member] | Sunoco LP [Member]
Marginal Percentage Interest in Distributions	15.00%																						15.00%
Limited Partner [Member] | Third Target Distribution [Member] | ETP [Member]
Marginal Percentage Interest in Distributions	65.00%																						65.00%
Limited Partner [Member] | Third Target Distribution [Member] | Sunoco LP [Member]
Marginal Percentage Interest in Distributions	25.00%																						25.00%
Limited Partner [Member] | Thereafter [Member] | ETP [Member]
Marginal Percentage Interest in Distributions	52.00%																						52.00%
Limited Partner [Member] | Thereafter [Member] | Sunoco LP [Member]
Marginal Percentage Interest in Distributions	50.00%																						50.00%

[1] Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See additional information below.

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Equity (Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Partners' Capital Notes [Abstract]
Unrealized gains on available-for-sale securities	$ 8	$ 2
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Gain (Loss) Arising During Period, Net of Tax	(5)	(5)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax	(5)	7
AOCI attributable to equity method investments	5	4
Subtotal	3	8
Amounts attributable to noncontrolling interest	(3)	(8)
Total AOCI included in partners' capital, net of tax	$ 0	$ 0	[1]

[1] * As adjusted. See Note 2.

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Equity Tax amounts in components of other comprehensive income (loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Other Comprehensive Income Loss Commodity Hedges Tax	$ (2)	$ (2)
Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Tax	3	3
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized (Gain) Loss Arising During Period, Tax	3	0
Other Comprehensive Income (Loss), Tax	$ 4	$ 1

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Equity (Relinquishments of Incentive Distribution Rights) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Subsequent Event [Member]
Relinquishment of Incentive Distributions	$ 33	$ 128	$ 153

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ETE Unit-Based Compensation Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stock Issued During Period, Shares, New Issues	32,200,000	2,100,000	0
ETE Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	12,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	10,800,000
Unvested awards	1,251,002
Units Vested In Period	2,018	28,648
Fair Value Of Units As Of The Vesting Date	$ 39	$ 205
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 21,000
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	3 years 6 months 15 days
Employee [Member] | ETE Long-Term Incentive Plan [Member]
Awards granted	1,200,000
Director [Member] | ETE Long-Term Incentive Plan [Member]
Awards granted	15,648

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Unit-Based Compensation Plans Subsidiary Unit-Based Compensation Plans (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsidiary Unit Based Compensation [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair Value Of Units As Of The Vesting Date	$ 40.0	$ 40.0	$ 57.0
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 216.0
Equity Instruments Other than Options, Outstanding, Weighted Average Remaining Contractual Term	2 years 9 months
ETP Unit-Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	14.1	9.4
Weighted Average Grant-Date Fair Value Per ETP Unit	$ 23.18	$ 27.68
Awards granted	4.9
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted	$ 17.69	$ 23.82	$ 23.47
Awards vested	(2.3)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards vested	$ 34.22
Stock Granted, Value, Share-based Compensation, Forfeited	$ (1.1)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards forfeited	$ 25.03
Sunoco LP Unit Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards	1.7	2.0
Weighted Average Grant-Date Fair Value Per ETP Unit	$ 31.89	$ 34.43
Awards granted	0.2
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards granted	$ 28.31	$ 26.95	$ 40.63
Awards vested	(0.3)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards vested	$ 45.48
Stock Granted, Value, Share-based Compensation, Forfeited	$ (0.2)
Weighted Average Grant-Date Fair Value Per ETP Unit, Awards forfeited	$ 34.71
Legacy Sunoco Logistics Unit-Based Compensation Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested awards		3.2
Weighted Average Grant-Date Fair Value Per ETP Unit		$ 28.57

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Income Taxes Narrative (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Dec. 31, 2017	Nov. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	$ 403		$ 403
Operating Loss Carryforwards, Expiration Date			Jan. 01, 2031
Deferred Tax Liabilities, Gross	4,035		$ 4,035	$ 5,710
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	605		605
Net operating losses and alternative minimum tax credit	683		683	472
Valuation allowance	(189)		(189)	(118)
Unrecognized Tax Benefits That Would Impact Effective Tax Rate, Ater Tax	576		576
Proceeds from Income Tax Refunds	530		530
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	530		530
State			(16)	(34)	$ (54)
Unrecognized Tax Benefits, Interest on Income Taxes Expense			3
Income Tax Examination, Penalties and Interest Accrued	$ 9		9
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%
Tax Credit Carryforward, Valuation Allowance	$ 186		186
Deferred Income Tax Expense (Benefit)			(1,871)	$ (177)	$ 239
Operating Loss Carryforwards, Valuation Allowance	3		3
Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Net operating losses and alternative minimum tax credit	62		62
Operating Loss Carryforwards	274		274
Tax Cut and Jobs Act [Member]
Operating Loss Carryforwards [Line Items]
Deferred Income Tax Expense (Benefit)			(1,810)
Net of federal tax [Member]
Operating Loss Carryforwards [Line Items]
State			$ 53
Maximum [Member] | ETP Holdco and other corporate subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date			Dec. 31, 2037
Maximum [Member] | Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date			Dec. 31, 2037
Minimum [Member] | Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Date			Jan. 01, 2018
Reclassed to current income tax receivable within 12 months [Member]
Operating Loss Carryforwards [Line Items]
Net operating losses and alternative minimum tax credit	29		$ 29
Net of federal tax [Member] | Corporate Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	217		217
Pennsylvania Constitution [Member]
Operating Loss Carryforwards [Line Items]
State			67
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	27		27
Pennsylvania Constitution [Member] | Net of federal tax [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Contingencies	$ 21		$ 21

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Income Taxes Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Current expense (benefit):
Federal	$ 54	$ (47)		$ (308)
State	(16)	(34)		(54)
Total	38	(81)		(362)
Deferred expense (benefit):
Federal	(2,055)	(189)		268
State	184	12		(29)
Total	(1,871)	(177)		239
Total income tax expense (benefit) from continuing operations	$ (1,833)	$ (258)	[1]	$ (123)	[1]

[1] * As adjusted. See Note 2.

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Income Taxes Reconciliation of Income Tax Satutory Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Effective Income Tax Rate Reconciliation, Change in Tax Status of Subsidiary	$ (124)	$ 0		$ 0
Income tax expense (benefit) at United States statutory rate of 35 percent	248	71		316
Increase (reduction) in income taxes resulting from:
Goodwill impairment	207	278		0
Partnership earnings not subject to tax	(477)	(576)		(355)
State tax, net of federal tax benefit	124	(10)		(29)
Dividend received deduction	(14)	(15)		(22)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	(1,812)	0		0
Audit settlement	0	0		(7)
Other	15	(6)		(26)
Total income tax expense (benefit) from continuing operations	$ (1,833)	$ (258)	[1]	$ (123)	[1]

[1] * As adjusted. See Note 2.

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Income Taxes Effects of Temporary Differences That Comprise Net Deffered Income Tax Liability (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Deferred income tax assets:
Net operating losses and alternative minimum tax credit	$ 683	$ 472
Pension and other postretirement benefits	21	30
Long-term debt	14	32
Other	191	182
Deferred Tax Assets, Gross	909	716
Valuation allowance	(189)	(118)
Net deferred income tax assets	720	598
Deferred income tax liabilities:
Property, plant and equipment	(1,036)	(1,633)
Investments in unconsolidated affiliates	(2,726)	(3,789)
Trademarks	(173)	(273)
Other	(100)	(15)
Deferred Tax Liabilities, Gross	4,035	5,710
Deferred Tax Liabilities	$ (3,315)	$ (5,112)	$ (4,590)

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Income Taxes Components of Net Deferred Tax Liability (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Components of Net Deferred Income Tax [Abstract]
Total deferred income tax assets	$ 909	$ 716
Deferred Tax Liabilities, Net	(3,315)	(5,112)	$ (4,590)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)	0	460
Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3)	0	243
Tax provision, including provision from discontinued operations	1,825	201
Other	(28)	(20)
Valuation allowance	189	118
Net deferred income tax assets	$ 720	$ 598

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Income Taxes Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes in Unrecognized Tax Benefits [Abstract]
Balance at beginning of year	$ 615	$ 610	$ 440
Additions attributable to tax positions taken in the current year	0	8	178
Additions attributable to tax positions taken in prior years	28	18	0
Reduction attributable to tax positions taken in prior years	(25)	(20)	0
Lapse of statute	9	1	8
Balance at end of year	$ 609	$ 615	$ 610

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details)	1 Months Ended				3 Months Ended	12 Months Ended
	Jan. 31, 2018 USD ($)	May 31, 2017 USD ($)	Oct. 31, 2015 USD ($)	Apr. 30, 2015 USD ($)	Sep. 30, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Aug. 31, 2017 USD ($)	Oct. 31, 2016 USD ($)	Apr. 30, 2016 USD ($)
Lessee, Operating Lease, Term of Contract						40 years
Payments for Environmental Liabilities						$ 32,000,000	$ 43,000,000
Operating leases rent expense						196,000,000	187,000,000	$ 281,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed						0
Total environmental liabilities						372,000,000	344,000,000
Operating Leases, Rent Expense, Contingent Rentals						$ 16,000,000	18,000,000	20,000,000
Site Contingency, Number of Sites Needing Remediation						43
Proposed Environmental Penalty						$ 0			$ 100,000	$ 100,000
Payments to Acquire Businesses, Gross			$ 382,000,000
Long-term Debt						44,084,000,000	43,802,000,000
BP Products North America [Member]
Loss Contingency, Damages Awarded, Value		$ 13,000,000		$ 62,000,000				$ 41,000,000
Sunoco LP [Member]
Long-term Debt						4,287,000,000	4,514,000,000
Williams [Member]
Loss on Contract Termination for Default					$ 410,000,000
Loss Contingency, Damages Sought					1.48
Loss Contingency, Damages Sought, Value					$ 10,000,000,000
Permian Express 2 [Member]
Proposed Environmental Penalty											$ 100,000
Related To Deductibles [Member]
Accrual for loss contingency						$ 33,000,000	77,000,000
Dropdown of Sunoco LLC Interest [Member]
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage				31.58%
Payments to Acquire Businesses, Gross				$ 775,000,000
Equity Issued in Business Combination, Fair Value Disclosure				$ 41,000,000
6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage						6.375%
Senior Notes						$ 800,000,000	800,000,000
6.25% Senior Notes due 2021 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage						6.25%					6.25%
Senior Notes						$ 800,000,000	$ 800,000,000				$ 800,000,000
Term loan due 2019 [Member] | Sunoco LP [Member]
Long-term Debt						2,035,000,000
Subsequent Event [Member] | 6.375% Senior Notes due April 2023 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.375%
Subsequent Event [Member] | 6.25% Senior Notes due 2021 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Subsequent Event [Member] | 4.875% senior notes due 2023 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Senior Notes	$ 1,000,000,000
Subsequent Event [Member] | 5.500% senior notes due 2026 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Senior Notes	$ 800,000,000
Subsequent Event [Member] | 5.875% senior notes due 2028 [Member] | Sunoco LP [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.875%
Senior Notes	$ 400,000,000
Federal [Member] | Sunoco Pipeline L.P. [Member]
Proposed Environmental Penalty						7,000,000
State and Local Jurisdiction [Member] | Sunoco Pipeline L.P. [Member]
Proposed Environmental Penalty						$ 1,000,000
PENNSYLVANIA | Subsequent Event [Member]
Civil penalties	$ 12,600,000
Initial term [Member] | Minimum [Member]
Lessee, Operating Lease, Term of Contract						5 years
Initial term [Member] | Maximum [Member]
Lessee, Operating Lease, Term of Contract						15 years
Final Judgement [Member]
Gain Contingency, Unrecorded Amount						$ 536,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount						1,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount						595,000,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount						$ 319,000,000

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Derivative Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details) MB_bls in Thousands, BBtu in Thousands	12 Months Ended
	Dec. 31, 2017 bushels MW BBtu MB_bls	Dec. 31, 2016 bushels MW BBtu MB_bls
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member]
Term Of Commodity Derivatives		2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Maximum [Member]
Term Of Commodity Derivatives	2019
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Minimum [Member]
Term Of Commodity Derivatives	2018
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Maximum [Member]
Term Of Commodity Derivatives	2019	2018
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Minimum [Member]
Term Of Commodity Derivatives	2018	2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member] | Maximum [Member]
Term Of Commodity Derivatives	2020	2018
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member] | Minimum [Member]
Term Of Commodity Derivatives	2018	2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member]
Term Of Commodity Derivatives		2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Maximum [Member]
Term Of Commodity Derivatives	2020
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Minimum [Member]
Term Of Commodity Derivatives	2018
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member]
Term Of Commodity Derivatives	2018	2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Term Of Commodity Derivatives		2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member] | Maximum [Member]
Term Of Commodity Derivatives	2020
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member] | Minimum [Member]
Term Of Commodity Derivatives	2018
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Term Of Commodity Derivatives	2018
Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member]
Term Of Commodity Derivatives	2018	2017
Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Term Of Commodity Derivatives	2018	2017
Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Term Of Commodity Derivatives	2018	2017
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member]
Derivative, Nonmonetary Notional Amount		5,663
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount	4,390	52,653
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member]
Derivative, Nonmonetary Notional Amount	145,105	22,492
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount		683
Natural Gas [Member] | Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount	39,770	36,370
Natural Gas [Member] | Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount	39,770	36,370
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member]
Derivative, Nonmonetary Notional Amount	87,253
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount	4,650	10,750
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member]
Derivative, Nonmonetary Notional Amount	1,078
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC NYMEX [Member]
Derivative, Nonmonetary Notional Amount	48,510	2,243
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount	13,000	0
Natural Gas [Member] | Long [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member]
Derivative, Nonmonetary Notional Amount	39,770	36,370
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Term Of Commodity Derivatives	2018	2017
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forward Swaps [Member] | Maximum [Member]
Term Of Commodity Derivatives	2019	2018
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forward Swaps [Member] | Minimum [Member]
Term Of Commodity Derivatives	2018	2017
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Term Of Commodity Derivatives	2018
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Maximum [Member]
Term Of Commodity Derivatives		2018
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Minimum [Member]
Term Of Commodity Derivatives		2017
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]
Term Of Commodity Derivatives	2018	2017
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | MW	25,760
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Put Option [Member]
Derivative, Nonmonetary Notional Amount | MW	153,600	50,400
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Calls [Member]
Derivative, Nonmonetary Notional Amount | MW	137,600	186,400
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forward Swaps [Member]
Derivative, Nonmonetary Notional Amount | MW	435,960	391,880
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | MW		109,564
WTI Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Term Of Commodity Derivatives		2017
WTI Crude Oil [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | MB_bls	0	617
Natural Gas Liquids [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member]
Term Of Commodity Derivatives		2017
Natural Gas Liquids [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member] | Maximum [Member]
Term Of Commodity Derivatives	2019
Natural Gas Liquids [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member] | Minimum [Member]
Term Of Commodity Derivatives	2018
Natural Gas Liquids [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member]
Derivative, Nonmonetary Notional Amount | MB_bls		5,787
Natural Gas Liquids [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Swaps [Member]
Derivative, Nonmonetary Notional Amount | MB_bls	6,744
Refined Products [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Term Of Commodity Derivatives		2017
Refined Products [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Maximum [Member]
Term Of Commodity Derivatives	2019
Refined Products [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Minimum [Member]
Term Of Commodity Derivatives	2018
Refined Products [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | MB_bls	3,901	3,144
Corn [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Term Of Commodity Derivatives	2018	2017
Corn [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Derivative, Nonmonetary Notional Amount | bushels	1,870,000	1,580,000

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Schedule of Future Minimum Rental Payments for Operating Leases) (Details) $ in Millions	Dec. 31, 2017 USD ($)
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]
2018	$ 113
2019	100
2020	96
2021	83
2022	71
Thereafter	606
Total Future Rent Payments	1,069
Future Rental Income	(152)
Net Future Rental Payments	$ 917

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Derivative Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) - Derivatives Not Designated As Hedging Instruments - Interest Rate Derivatives [Member] - ETP [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
March 2019 [Member]
Notional Amount		$ 300	$ 300
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
July 2020 [Member] | Forward-Starting Swaps [Member]
Notional Amount	[2]	$ 400	0
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
July 2019 [Member] | Forward-Starting Swaps [Member]
Notional Amount	[2]	$ 300	200
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate
July 2018 [Member] | Forward-Starting Swaps [Member]
Notional Amount	[2]	$ 300	200
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate
July 2017 [Member] | Forward-Starting Swaps [Member]
Notional Amount	[2]	$ 0	500
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate
December 2018 [Member]
Notional Amount		$ 1,200	$ 1,200
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%

[1] Floating rates are based on 3-month LIBOR.

[2] Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingencies And Environemental Liabilities (Environmental Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Environmental Remediation Obligations [Abstract]
Current	$ 35	$ 26
Non-current	337	318
Total environmental liabilities	$ 372	$ 344

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Derivative Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Asset Derivatives	$ 321	$ 363
Liability Derivatives	(560)	(672)
Designated as Hedging Instrument [Member]
Asset Derivatives	14	0
Liability Derivatives	(2)	(4)
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Asset Derivatives	14	0
Liability Derivatives	(2)	(4)
Not Designated as Hedging Instrument [Member]
Asset Derivatives	307	363
Liability Derivatives	(558)	(668)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Asset Derivatives	262	338
Liability Derivatives	(281)	(416)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Asset Derivatives	45	25
Liability Derivatives	(58)	(58)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Asset Derivatives	0	0
Liability Derivatives	(219)	(193)
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Asset Derivatives	0	0
Liability Derivatives	0	(1)
Broker cleared derivative contracts [Member]
Asset Derivatives	276	338
Liability Derivatives	$ (283)	$ (420)

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Regulatory Matters, Commitments, Contingincies and Enviironmental (Schedule of Rental Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Rent Expense, Contingent Rentals	$ 16	$ 18	$ 20
Rental expense(1)	196	187	281
Less: Sublease rental income	(25)	(26)	(26)
Rental expense, net	$ 171	$ 161	$ 255

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Derivative Assets And Liabilities Derivative Assets and Lianilities (Offsetting Agreements Netting Table) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Asset Derivatives	$ 321	$ 363
Derivative Liability, Fair Value, Gross Liability	(560)	(672)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(21)	(4)
Derivative Liability, Fair Value, Amount Offset Against Collateral	21	4
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(263)	(338)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	263	338
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	37	21
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(276)	(330)
Without offsetting agreements [Member]
Asset Derivatives	0	0
Derivative Liability, Fair Value, Gross Liability	(219)	(194)
OTC Contracts [Member]
Asset Derivatives	45	25
Derivative Liability, Fair Value, Gross Liability	(58)	(58)
Broker cleared derivative contracts [Member]
Asset Derivatives	276	338
Derivative Liability, Fair Value, Gross Liability	$ (283)	$ (420)

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Derivative Assets And Liabilities (Derivative Amount Of Gain (Loss) Recognized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	$ 26	$ 14	$ 21
Amount of Gain/(Loss) Recognized in Income on Derivatives	0	(220)	(2)
Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	26	14	21
Interest Rate Derivatives [Member] | Losses On Non-Hedged Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(37)	(12)	(18)
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	1	4	12
Non Trading [Member] | Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	5	(177)	15
Trading [Member] | Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 31	$ (35)	$ (11)

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Retirement Benefits (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ETP [Member]
Retirement Benefits [Line Items]
Defined Contribution Plan, Cost	$ 38	$ 44	$ 40
Sunoco [Member]
Retirement Benefits [Line Items]
Liability, Other Postretirement Defined Benefit Plan, Noncurrent	$ 200
Pension Benefits
Retirement Benefits [Line Items]
Large Cap US Equitiies	100.00%	100.00%
Other Postretirement Benefits
Retirement Benefits [Line Items]
Large Cap US Equitiies	38.00%	31.00%
Fixed Income Securities	61.00%	66.00%
Cash Fund Investments	2.00%	3.00%
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	$ 10
Minimum [Member] | Other Postretirement Benefits | Equity [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum (Deprecated 2017-01-31)	0.25
Minimum [Member] | Other Postretirement Benefits | Fixed Income Investments [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum (Deprecated 2017-01-31)	0.65
Maximum [Member] | Other Postretirement Benefits | Equity [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum (Deprecated 2017-01-31)	0.35
Maximum [Member] | Other Postretirement Benefits | Fixed Income Investments [Member]
Retirement Benefits [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Maximum (Deprecated 2017-01-31)	0.75
Funded Plans [Member] | Pension Benefits
Retirement Benefits [Line Items]
Defined Benefit Plan, Expected Future Benefit Payment, Next Twelve Months	$ 1

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Retirement Benefits (Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Change in benefit obligation:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	$ 0	$ 0
Change in plan assets:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0	0
Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Interest Cost	2	3
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	12
Defined Benefit Plan, Fair Value of Plan Assets	1	12
Other Postretirement Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	166	181
Defined Benefit Plan, Interest Cost	4	4
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	7	0
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	(20)	(21)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	(1)	2
Defined Benefit Plan, Benefit Obligation	156	166
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	256	261
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)	11	6
Defined Benefit Plan, Plan Assets, Contributions by Employer	10	10
Defined Benefit Plan, Fair Value of Plan Assets	257	256
Defined Benefit Plan, Funded (Unfunded) Status of Plan	(101)	(90)
Amounts recognized in the consolidated balance sheets consist of:
Assets for Plan Benefits, Defined Benefit Plan	127	114
Liability, Defined Benefit Plan, Current	(2)	(2)
Liability, Defined Benefit Plan, Noncurrent	(24)	(23)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	101	89
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Reclassification Adjustment, before Tax	(18)	(13)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	21	15
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	3	2
Defined Benefit Plan, Plan Assets, Benefits Paid	20	21
Funded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	(18)
Change in plan assets:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	(18)
Funded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	18	20
Defined Benefit Plan, Interest Cost	1	1
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	(2)	(1)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	2	(2)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0
Defined Benefit Plan, Benefit Obligation	1	18
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	12	15
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)	3	(2)
Defined Benefit Plan, Plan Assets, Contributions by Employer	6	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0
Defined Benefit Plan, Fair Value of Plan Assets	1	12
Defined Benefit Plan, Funded (Unfunded) Status of Plan	0	6
Amounts recognized in the consolidated balance sheets consist of:
Assets for Plan Benefits, Defined Benefit Plan	0	0
Liability, Defined Benefit Plan, Current	0	0
Liability, Defined Benefit Plan, Noncurrent	0	(6)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	0	(6)
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Reclassification Adjustment, before Tax	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	0	0
Defined Benefit Plan, Plan Assets, Benefits Paid	2	1
Unfunded Plans [Member]
Change in benefit obligation:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0	0
Change in plan assets:
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0	0
Unfunded Plans [Member] | Pension Benefits
Change in benefit obligation:
Defined Benefit Plan, Benefit Obligation	51	57
Defined Benefit Plan, Interest Cost	1	2
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	(6)	(7)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	1	(1)
Defined Benefit Plan, Benefit Obligation	47	51
Change in plan assets:
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Plan Assets, Increase (Decrease) for Actual Return (Loss)	0	0
Defined Benefit Plan, Plan Assets, Contributions by Employer	0	0
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Funded (Unfunded) Status of Plan	47	51
Amounts recognized in the consolidated balance sheets consist of:
Assets for Plan Benefits, Defined Benefit Plan	0	0
Liability, Defined Benefit Plan, Current	(8)	(7)
Liability, Defined Benefit Plan, Noncurrent	(39)	(44)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position	(47)	(51)
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Reclassification Adjustment, before Tax	5	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	5	0
Defined Benefit Plan, Plan Assets, Benefits Paid	$ 0	$ 0

XML

Retirement Benefits (Accumulated Benefit Obligation In Excess of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Accumulated Benefit Obligation	$ 156	$ 166
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Fair Value of Plan Assets	257	256
Funded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	1	18
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Accumulated Benefit Obligation	1	18
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Fair Value of Plan Assets	1	12
Unfunded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	47	51
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Accumulated Benefit Obligation	47	51
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Fair Value of Plan Assets	$ 0	$ 0

XML

Retirement Benefits (Net Periodic Benefit Costs Schedule) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost	$ 2	$ 3
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	0	(1)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	2	2
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost	4	4
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	(9)	(8)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	2	1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ (3)	$ (3)

XML

Retirement Benefits (Benefit Assumptions) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Next Fiscal Year	7.20%	6.73%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate	4.99%	4.96%
Defined Benefit Plan, Year Health Care Cost Trend Rate Reaches Ultimate Trend Rate	2023	2021
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.27%	3.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.52%	3.60%
Expected long term return on assets, tax exempt accounts	3.50%	3.50%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.34%	2.34%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.10%	3.06%
Expected long term return on assets, tax exempt accounts	7.00%	7.00%
Expected long term return on assets, taxable accounts	4.50%	4.50%

XML

Retirement Benefits (Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 257	$ 256	$ 261
Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1	12
Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	33	23
Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	154	142
Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1	12
Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	70	91
Level 1 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	187	165
Level 1 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1	12
Level 1 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	33	23
Level 1 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	154	142
Level 1 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1	12
Level 1 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	70	91
Level 2 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 2 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	70	91
Level 3 [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Mutual Fund [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Mutual Fund [Member] | Pension Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Level 3 [Member] | Fixed Income Securities [Member] | Other Postretirement Benefits
Fair Value of Plan Assets [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	$ 0

XML

Retirement Benefits (Benefit Payments) (Details) $ in Millions	Dec. 31, 2017 USD ($)
Other Postretirement Benefits (Gross, Before Medicare Part D) [Member]
Defined Benefit Plan Disclosure [Line Items]
2017	$ 24
2018	23
2019	21
2020	19
2021	17
2022-2026	37
Unfunded Plans [Member] | Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2017	8
2018	6
2019	6
2020	5
2021	4
2022-2026	$ 15

XML

Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenue	$ 303	$ 221	$ 290

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Reportable Segments (Operating Segments) (Details) - USD ($) $ in Millions	3 Months Ended															12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	[1]	Jun. 30, 2016	[1]	Mar. 31, 2016	[1]	Dec. 31, 2015	[1]	Sep. 30, 2015	[1]	Jun. 30, 2015	[1]	Mar. 31, 2015	[1]	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Revenues	$ 11,452	$ 9,984		$ 9,427		$ 9,660		$ 9,323		$ 8,156		$ 7,866		$ 6,447		$ 40,523	$ 31,792	[1],[2]	$ 36,096	[2]
Cost of products sold																30,966	23,693	[2]	28,668	[2]
Depreciation, depletion and amortization																2,554	2,216	[2]	1,951	[2]
Equity in earnings from unconsolidated affiliates																144	270	[2]	276	[2]
Investment In ETP [Member]
Revenues																29,054	21,827		34,292
Cost of products sold																20,801	15,080		26,714
Depreciation, depletion and amortization																2,332	1,986		1,929
Equity in earnings from unconsolidated affiliates																156	59		469
Investment In Sunoco LP [Member]
Revenues																11,723	9,986		12,430
Cost of products sold																10,615	8,830		11,450
Depreciation, depletion and amortization																169	176		150
Investment in Lake Charles LNG [Member]
Depreciation, depletion and amortization																39	39		39
Corporate and Other [Member]
Depreciation, depletion and amortization																14	15		17
Adjustments and Eliminations [Member]
Revenues																(451)	(218)		(10,842)
Cost of products sold																(450)	(217)		(9,496)
Depreciation, depletion and amortization																0	0		(184)
Equity in earnings from unconsolidated affiliates																(12)	211		(193)
External Customers [Member]
Revenues																11,713	9,977		12,419
External Customers [Member] | Investment In ETP [Member]
Revenues																28,613	21,618		34,156
External Customers [Member] | Investment In Sunoco LP [Member]
Revenues																11,713	9,977		12,419
External Customers [Member] | Investment in Lake Charles LNG [Member]
Revenues																197	197		216
Intersegment [Member] | Investment In ETP [Member]
Revenues																441	209		136
Intersegment [Member] | Investment In Sunoco LP [Member]
Revenues																$ 10	$ 9		$ 11

[1] * As adjusted. See Note 2 and Note 3.

[2] * As adjusted. See Note 2.

XML

Reportable Segments (Equity in earnings of unconsolidated affiliates) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Segment Reporting Information [Line Items]
Equity in earnings from unconsolidated affiliates	$ 144	$ 270	[1]	$ 276	[1]
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Equity in earnings from unconsolidated affiliates	156	59		469
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Equity in earnings from unconsolidated affiliates	$ (12)	$ 211		$ (193)

[1] * As adjusted. See Note 2.

XML

Reportable Segments Reportable Segments (Segment Adjusted EBITDA) (Details) - USD ($) $ in Millions	3 Months Ended															12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	[2]	Jun. 30, 2016	[2]	Mar. 31, 2016	[2]	Dec. 31, 2015	[2]	Sep. 30, 2015	[2]	Jun. 30, 2015	[2]	Mar. 31, 2015	[2]	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Segment Reporting Information [Line Items]
Adjusted EBITDA																$ 7,320	$ 6,135		$ 5,738
Depreciation, depletion and amortization																(2,554)	(2,216)	[1]	(1,951)	[1]
Interest expense, net of interest capitalized																(1,922)	(1,804)	[1]	(1,622)	[1]
Gains on acquisitions																0	83	[1]	0	[1]
Impairment of investments in unconsolidated affiliates																(313)	(308)	[1]	0	[1]
Impairment losses																1,039	1,040	[1]	339	[1]
Losses on interest rate derivatives																(37)	(12)	[1]	(18)	[1]
Non-cash unit-based compensation expense																(99)	(70)	[1]	(91)	[1]
Losses on interest rate derivatives																59	(136)		(65)
Losses on extinguishments of debt																(89)	0	[1]	(43)	[1]
Inventory valuation adjustments																24	97	[1]	(67)	[1]
Adjusted EBITDA related to discontinued operations																(223)	(199)		(228)
Adjusted EBITDA related to unconsolidated affiliates																(716)	(675)		(713)
Equity in earnings from unconsolidated affiliates																144	270	[1]	276	[1]
Other, net																155	79		23
Income from continuing operations before income tax benefit																710	204	[1]	900	[1]
Income tax benefit from continuing operations																(1,833)	(258)	[1]	(123)	[1]
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent																2,543	462	[1]	1,023	[1]
Income (loss) from discontinued operations, net of income taxes																(177)	(462)	[1]	38	[1]
Net income	$ 1,168	$ 758		$ 121		$ 319		$ (734)		$ (3)		$ 417		$ 320		2,366	0	[1],[2]	1,061	[1]
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA																6,712	5,733		5,517
Depreciation, depletion and amortization																(2,332)	(1,986)		(1,929)
Equity in earnings from unconsolidated affiliates																156	59		469
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA																732	665		719
Depreciation, depletion and amortization																(169)	(176)		(150)
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA																175	179		196
Depreciation, depletion and amortization																(39)	(39)		(39)
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA																(31)	(170)		(104)
Depreciation, depletion and amortization																(14)	(15)		(17)
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA																(268)	(272)		(590)
Depreciation, depletion and amortization																0	0		184
Equity in earnings from unconsolidated affiliates																$ (12)	$ 211		$ (193)

[1] * As adjusted. See Note 2.

[2] * As adjusted. See Note 2 and Note 3.

XML

Reportable Segments (Assets Segments)(Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Assets	$ 86,246	$ 78,925	[1]	$ 71,144
Investment In ETP [Member]
Assets	77,965	70,105		65,128
Investment In Sunoco LP [Member]
Assets	8,344	8,701		8,842
Investment in Lake Charles LNG [Member]
Assets	1,646	1,508		1,369
Corporate and Other [Member]
Assets	598	711		638
Adjustments and Eliminations [Member]
Assets	$ (2,307)	$ (2,100)		$ (4,833)

[1] * As adjusted. See Note 2.

XML

Reporting Segments (Additions To Property Plant And Equipment Including Acquisitions Net Of Contributions In Aid Of Construction Costs Segments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	$ 6,006	$ 5,929	$ 8,223
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	5,901	5,810	8,167
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	103	119	178
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	2	0	1
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Additions	$ 0	$ 0	$ (123)

XML

Reportable Segments (Advances to and investments in affiliates) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Segment Reporting Information [Line Items]
Advances to and investments in unconsolidated affiliates	$ 2,705	$ 3,040	[1]	$ 3,462
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Advances to and investments in unconsolidated affiliates	3,816	4,280		5,003
Adjustments and Eliminations [Member]
Segment Reporting Information [Line Items]
Advances to and investments in unconsolidated affiliates	$ (1,111)	$ (1,240)		$ (1,541)

[1] * As adjusted. See Note 2.

XML

Reportable Segments Revenue (Details) - USD ($) $ in Millions	3 Months Ended															12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	[1]	Jun. 30, 2016	[1]	Mar. 31, 2016	[1]	Dec. 31, 2015	[1]	Sep. 30, 2015	[1]	Jun. 30, 2015	[1]	Mar. 31, 2015	[1]	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Revenue from External Customer [Line Items]
Revenues	$ 11,452	$ 9,984		$ 9,427		$ 9,660		$ 9,323		$ 8,156		$ 7,866		$ 6,447		$ 40,523	$ 31,792	[1],[2]	$ 36,096	[2]
External Customers [Member]
Revenue from External Customer [Line Items]
Revenues																11,713	9,977		12,419
Investment In Sunoco LP [Member]
Revenue from External Customer [Line Items]
Revenues																11,723	9,986		12,430
Investment In Sunoco LP [Member] | Retail [Member]
Revenue from External Customer [Line Items]
Revenues																2,263	1,991		2,226
Investment In Sunoco LP [Member] | Wholesale [Member]
Revenue from External Customer [Line Items]
Revenues																9,460	7,995		10,204
Investment In Sunoco LP [Member] | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues																11,713	9,977		12,419
Investment In Sunoco LP [Member] | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues																10	9		11
Investment In ETP [Member]
Revenue from External Customer [Line Items]
Revenues																29,054	21,827		34,292
Investment In ETP [Member] | Intrastate Transportation And Storage [Member]
Revenue from External Customer [Line Items]
Revenues																2,891	2,155		1,912
Investment In ETP [Member] | Interstate Transportation and Storage [Member]
Revenue from External Customer [Line Items]
Revenues																915	946		1,008
Investment In ETP [Member] | Midstream [Member]
Revenue from External Customer [Line Items]
Revenues																2,510	2,342		2,607
Investment In ETP [Member] | NGL and refined products transportation and services [Member]
Revenue from External Customer [Line Items]
Revenues																8,326	5,973		4,569
Investment In ETP [Member] | Investment in Sunoco Logistics [Member]
Revenue from External Customer [Line Items]
Revenues																11,672	7,539		8,980
Investment In ETP [Member] | Other Segments [Member]
Revenue from External Customer [Line Items]
Revenues																2,740	2,872		15,216
Investment In ETP [Member] | External Customers [Member]
Revenue from External Customer [Line Items]
Revenues																28,613	21,618		34,156
Investment In ETP [Member] | Intersegment [Member]
Revenue from External Customer [Line Items]
Revenues																$ 441	$ 209		$ 136

[1] * As adjusted. See Note 2 and Note 3.

[2] * As adjusted. See Note 2.

XML

Reportable Segments (Lake Charles Revenue) (Details) - USD ($) $ in Millions	3 Months Ended															12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	[1]	Jun. 30, 2016	[1]	Mar. 31, 2016	[1]	Dec. 31, 2015	[1]	Sep. 30, 2015	[1]	Jun. 30, 2015	[1]	Mar. 31, 2015	[1]	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Revenues	$ 11,452	$ 9,984		$ 9,427		$ 9,660		$ 9,323		$ 8,156		$ 7,866		$ 6,447		$ 40,523	$ 31,792	[1],[2]	$ 36,096	[2]
External Customers [Member]
Revenues																11,713	9,977		12,419
Investment in Lake Charles LNG [Member] | External Customers [Member]
Revenues																$ 197	$ 197		$ 216

[1] * As adjusted. See Note 2 and Note 3.

[2] * As adjusted. See Note 2.

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Quarterly Financial Data (Unaudited) (Schedule of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended															12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	[1]	Jun. 30, 2016	[1]	Mar. 31, 2016	[1]	Dec. 31, 2015	[1]	Sep. 30, 2015	[1]	Jun. 30, 2015	[1]	Mar. 31, 2015	[1]	Dec. 31, 2017	Dec. 31, 2016	[1],[2]	Dec. 31, 2015	[2]
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 11,452	$ 9,984		$ 9,427		$ 9,660		$ 9,323		$ 8,156		$ 7,866		$ 6,447		$ 40,523	$ 31,792		$ 36,096
Operating income (loss)	285	924		746		758		(275)		624		814		680		2,713	1,843		2,287
Net income (loss)	1,168	758		121		319		(734)		(3)		417		320		2,366	0		1,061
Limited Partners’ interest in net income	$ 239	$ 240		$ 204		$ 232		$ 226		$ 207		$ 239		$ 311		$ 915	$ 983		$ 1,183
Basic net income per limited partner unit	$ 0.22	$ 0.22		$ 0.18		$ 0.22		$ 0.22		$ 0.20		$ 0.23		$ 0.30		$ 0.85	$ 0.94		$ 1.11
Diluted net income per limited partner unit	$ 0.22	$ 0.22		$ 0.18		$ 0.21		$ 0.21		$ 0.19		$ 0.23		$ 0.30		$ 0.83	$ 0.92		$ 1.11

[1] * As adjusted. See Note 2 and Note 3.

[2] * As adjusted. See Note 2.

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Quarterly Financial Data (Unaudited) Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	[1]	Dec. 31, 2015	[1]
Income Statement [Abstract]
Impairment losses	$ 1,039	$ 1,040		$ 339
Impairment of investments in unconsolidated affiliates	$ 313	$ 308		$ 0

[1] * As adjusted. See Note 2.

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Supplemental Financial Statement Information (Schedule Of Balance Sheets) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Cash and cash equivalents	$ 336	$ 467	[1]	$ 585	[1]	$ 839	[1]
Accounts receivable from related companies	53	47	[1]
Other current assets	295	447	[1]
Total current assets	10,683	6,899	[1]
Property, Plant and Equipment, Net	61,088	53,578	[1]
Advances to and investments in unconsolidated affiliates	2,705	3,040	[1]	3,462
Intangible assets, net	6,116	5,512	[1]
Goodwill	4,768	5,670	[1]	6,056
OTHER NON-CURRENT ASSETS, net	886	815	[1]
Total assets	86,246	78,925	[1]	71,144
Accounts Payable, Current	4,685	3,502	[1]
Accounts payable to related companies	31	42	[1]
Interest payable	552	545
Accrued and other current liabilities	2,582	2,367	[1]
Total current liabilities	7,897	7,277	[1]
Long-term debt, less current maturities	43,671	42,608	[1]
Other non-current liabilities	1,217	1,075	[1]
COMMITMENTS AND CONTINGENCIES			[1]
General Partner	(3)	(3)	[1]
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)	(1,643)	(1,871)	[1]
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)	450	180	[1]
Accumulated other comprehensive loss	0	0	[1]
Total partners’ deficit	(1,196)	(1,694)	[1]	24,485
Total liabilities and equity	86,246	78,925	[1]
Parent Company [Member]
Cash and cash equivalents	1	2		$ 1		$ 2
Accounts receivable from related companies	65	55
Other current assets	1	0
Total current assets	67	57
Property, Plant and Equipment, Net	27	36
Advances to and investments in unconsolidated affiliates	6,082	5,088
Intangible assets, net	0	1
Goodwill	9	9
OTHER NON-CURRENT ASSETS, net	8	10
Total assets	6,193	5,201
Accounts Payable, Current	0	1
Accounts payable to related companies	0	22
Interest payable	66	66
Accrued and other current liabilities	4	3
Total current liabilities	70	92
Long-term debt, less current maturities	6,700	6,358
NOTE PAYABLE TO AFFILIATE	617	443
Other non-current liabilities	2	2
COMMITMENTS AND CONTINGENCIES
General Partner	(3)	(3)
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)	(1,643)	(1,871)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)	450	180
Total partners’ deficit	(1,196)	(1,694)
Total liabilities and equity	$ 6,193	$ 5,201

[1] * As adjusted. See Note 2.

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Supplemental Financial Statement Information (Schedule Of Statements Of Operations) (Details) - USD ($) $ in Millions	3 Months Ended															12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	[2]	Jun. 30, 2016	[2]	Mar. 31, 2016	[2]	Dec. 31, 2015	[2]	Sep. 30, 2015	[2]	Jun. 30, 2015	[2]	Mar. 31, 2015	[2]	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES																$ (607)	$ (693)	[1]	$ (548)	[1]
Interest expense, net of interest capitalized																(1,922)	(1,804)	[1]	(1,622)	[1]
Equity in earnings from unconsolidated affiliates																144	270	[1]	276	[1]
Gains on interest rate derivatives																(37)	(12)	[1]	(18)	[1]
Losses on extinguishments of debt																(89)	0	[1]	(43)	[1]
Other, net																214	132	[1]	20	[1]
Income tax expense																(1,833)	(258)	[1]	(123)	[1]
NET INCOME ATTRIBUTABLE TO PARTNERS																954	995	[1]	1,189	[1]
General Partner’s interest in net income																2	3	[1]	3	[1]
Convertible Unitholders’ interest in net income																37	9	[1]	0	[1]
Class D Unitholder’s interest in net income																0	0	[1]	3	[1]
Limited Partners’ interest in net income	$ 239	$ 240		$ 204		$ 232		$ 226		$ 207		$ 239		$ 311		915	983	[1],[2]	1,183	[1]
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES																(31)	(185)		(112)
Interest expense, net of interest capitalized																(347)	(327)		(294)
Equity in earnings from unconsolidated affiliates																1,381	1,511		1,601
Losses on extinguishments of debt																(47)	0		0
Other, net																(2)	(4)		(5)
INCOME BEFORE INCOME TAXES																954	995		1,190
Income tax expense																0	0		1
NET INCOME ATTRIBUTABLE TO PARTNERS																954	995		1,189
General Partner’s interest in net income																2	3		3
Convertible Unitholders’ interest in net income																37	9		0
Class D Unitholder’s interest in net income																0	0		3
Limited Partners’ interest in net income																$ 915	$ 983		$ 1,183

[1] * As adjusted. See Note 2.

[2] * As adjusted. See Note 2 and Note 3.

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Supplemental Financial Statement Information (Schedule Of Statements Of Cash Flows) (Details) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
		Aug. 31, 2017	Jan. 31, 2017	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES				$ 4,429	$ 3,322	[1]	$ 2,979	[1]
Cash paid for Bakken Pipeline Transaction				(303)	(1,398)	[1]	(777)	[1]
Proceeds from the sale of other assets				48	35	[1]	14	[1]
Contributions to unconsolidated affiliates				268	68	[1]	45	[1]
Capital expenditures				(8,444)	(7,771)	[1]	(9,073)	[1]
Net cash used in investing activities				(5,606)	(8,982)	[1]	(9,735)	[1]
Proceeds from borrowings				31,608	25,785	[1]	26,455	[1]
Repayments of long-term debt				(31,268)	(19,076)	[1]	(19,828)	[1]
Distributions to partners				(1,010)	(1,022)	[1]	(1,090)	[1]
Cash received from affiliate notes				0	5,317	[1]	0	[1]
Redemption of Preferred Units			$ (53)
Proceeds from Issuance of Common Limited Partners Units		$ 997		568	0	[1]	0	[1]
Units repurchased under buyback program				0	0	[1]	(1,064)	[1]
Debt issuance costs				(131)	(52)	[1]	(75)	[1]
Net cash provided by financing activities				953	5,927	[1]	6,785	[1]
Decrease in cash and cash equivalents				(131)	(118)	[1]	(254)	[1]
Cash and cash equivalents, beginning of period	[1]		467	467	585		839
Cash and cash equivalents, end of period				336	467	[1]	585	[1]
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES				831	918		1,103
Cash paid for Bakken Pipeline Transaction				0	0		(817)
Contributions to unconsolidated affiliates				861	70		0
Capital expenditures				(1)	(16)		(19)
Payments to Acquire Additional Interest in Subsidiaries				7	0		0
Net cash used in investing activities				(855)	(86)		(836)
Proceeds from borrowings				2,219	225		3,672
Repayments of long-term debt				(1,881)	(210)		(1,985)
Distributions to partners				(1,010)	(1,022)		(1,090)
Cash received from affiliate notes				174	176		210
Proceeds from Issuance of Common Limited Partners Units				568	0		0
Units repurchased under buyback program				0	0		(1,064)
Debt issuance costs				(47)	0		(11)
Net cash provided by financing activities				23	(831)		(268)
Decrease in cash and cash equivalents				(1)	1		(1)
Cash and cash equivalents, beginning of period			$ 2	2	1		2
Cash and cash equivalents, end of period				$ 1	$ 2		$ 1

[1] * As adjusted. See Note 2.

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Supplemental Financial Statement Information Supplemental Financial Information (Balance Sheet Units) (Details) - shares	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Authorized	1,079,145,561	1,046,947,157
Issued	1,079,145,561	1,046,947,157
Outstanding	1,079,145,561	1,046,947,157	1,044,800,000	1,077,500,000
Preferred Units, Authorized	329,299,267	329,299,267
Preferred Units, Issued	329,299,267	329,299,267
Preferred Units, Outstanding	329,299,267	329,299,267
Class D Units [Member]
Outstanding					3,080,000