¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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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 ETP Retail Holdings, LLC, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016.

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In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics Partners L.P. (“Sunoco Logistics”) and Phillips 66 Partners LP, began commercial operations on the 30-inch segment of its pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics will be the operator of the system.

•	As of March 31, 2016, ETP’s $3.75 billion credit facility had $4 million of outstanding borrowings and its leverage ratio, as defined by the credit agreement, was 4.27x.

•	In the first quarter of 2016, ETP issued 11.2 million common units through its at-the-market equity program, generating net proceeds of $324 million.

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(a)

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures used by industry analysts, investors, lenders, and rating agencies to assess the financial performance and the operating results of ETP’s fundamental business activities and should not be considered in isolation or as a substitute for net income, income from operations, cash flows from operating activities, or other GAAP measures.

•	For subsidiaries with publicly traded equity interests, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to the partners of ETP includes distributions to be received by the parent company with respect to the periods presented.

•	For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, but Distributable Cash Flow attributable to the partners of ETP is net of distributions to be paid by the subsidiary to the noncontrolling interests.

(b)	For the three months ended March 31, 2016, the Partnership’s effective income tax rate decreased from the prior year primarily due to lower earnings among the Partnership’s consolidated corporate subsidiaries. The three months ended March 31, 2016 also reflected a benefit of $20 million of net state tax benefit attributable to statutory state rate changes resulting from the

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(c)	Amounts related to Sunoco LP reflect the periods through June 30, 2015, subsequent to which Sunoco LP was deconsolidated and is now reflected as an unconsolidated affiliate.

(d)	Distributions on ETP Common Units and the number of ETP Common Units outstanding at the end of the period, both as reflected above, exclude amounts related to ETP Common Units held by subsidiaries of ETP. For the three months ended March 31, 2015, ETP Common Units outstanding at the end of the period includes ETP Common Units issued in connection with the Regency Merger.

(e)	Distributions on the Class H Units for the three months ended March 31, 2016 and 2015 were calculated as follows:

(f)	Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to the partners of ETP, as adjusted, divided by net distributions expected to be paid to the partners of ETP in respect of such period.

(g)	The Partnership defines Distributable Cash Flow per Common Unit for a period as the quotient of Distributable Cash Flow attributable to the partners of ETP, as adjusted, net of distributions related to the Class H Units, Class I Units and the General Partner and IDR interests, divided by the weighted average number of Common Units outstanding.

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

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

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

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

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•	a decrease of $9 million in non-fee based margins for natural gas due to lower natural gas prices and a $20 million decrease in non-fee based margins for crude oil and NGL due to lower crude oil and NGL prices;

•	a decrease in gross margin of $22 million from realized gains and losses on derivatives;

•	an increase of $7 million in operating expenses primarily due to assets that are recently placed in service, including the King Ranch and Eagle Ford systems in south Texas; and

•	an increase of $9 million in general and administrative expenses primarily due to a higher allocation of costs to the midstream segment; partially offset by

•	an increase of $4 million in fee-based revenues due to increased production and increased capacity from assets placed in service in the Eagle Ford Shale, Permian Basin and Cotton Valley regions partially offset by volume declines in the North Texas, Mid-Continent/Panhandle and North East regions; and

•	an increase of $5 million in adjusted EBITDA related to unconsolidated affiliates due to increased volumes through unconsolidated joint ventures.

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an increase of $24 million in transportation fees due to higher volumes transported out of all of our producing regions and higher average rates. The increase in average rates was primarily due to a higher proportion of the volumes originating from West Texas where transport rates are higher. Higher volumes from the West Texas region resulted in an increase in margin of $20 million between periods;

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an increase of $40 million in processing and fractionation margin (excluding changes in unrealized losses of $5 million) due to a $27 million increase in margin from our fractionators due to the ramp-up of our third 100,000 Bbls/d fractionator at Mont Belvieu, Texas, and additional producer volumes, primarily from West Texas. Additionally, the commissioning of the Mariner South LPG export project during February 2015 contributed an additional $15 million for the three months ended March 31, 2016. Margin associated with our off-gas fractionator in Geismar, Louisiana decreased by $2 million, as NGL and olefins market prices decreased significantly for the comparable periods; and

•	an increase of $5 million in storage margin due to an increase in demand for leased storage capacity as a result of favorable market conditions, which increased fee-based storage revenues by $6 million. This increase in fee-based storage revenues was partially offset by lower non-fee based revenues of $2 million due to lower commodity prices; partially offset by

•	a decrease of $7 million in other margin (excluding changes in unrealized losses of $4 million) primarily due to less favorable commodity prices;

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•	an increase of $2 million in operating expenses primarily due to increased utilities costs offset by lower project related expenses; and

•	an increase of $1 million in general and administrative expenses due to higher employee related expenses.

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a decrease of approximately $10 million in revenues due to the transfer and conversion from crude oil service to natural gas service of one of the Trunkline pipelines, and $11 million on the Transwestern pipeline from the expiration of a transportation rate schedule and lower sales of gas due to lower prices. The decreases on the Transwestern pipeline were offset by a $7 million increase primarily from sales of capacity at higher rates and new transportation services; partially offset by

•	a decrease of $3 million in selling, general and administrative expenses primarily due to a reduction in allocations and lower employee related expenses for the three months ended March 31, 2016; and

•	an increase of $5 million in adjusted EBITDA related to unconsolidated affiliates due to higher equity from Citrus as a result of higher revenues from one additional operating day and Phase VIII related revenues and lower maintenance related expenses.

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•	an increase of $7 million in transportation fees, despite the decrease in transported volumes, primarily due to increased revenue from renegotiated and newly initiated long-term, fixed capacity fee contracts on our Houston Pipeline system;

•	an increase of $7 million in natural gas sales and other primarily due to higher realized gains from the buying and selling of gas along our system, as well as lower fuel losses;

•	a decrease of $2 million in operating expenses due to lower pipeline maintenance related costs, as well as lower costs for electricity used to run compressors on our pipelines; and

•	a decrease of $1 million in general and administrative expenses resulting from lower overhead allocation costs due to shared services cost savings; partially offset by

•	a decrease of $8 million in storage margin (excluding changes in unrealized losses of $2 million and inventory fair value adjustments of $5 million), primarily driven by the timing of the movement of market prices during both periods; and

•	a decrease of $7 million from the sale of retained fuel (excluding changes in unrealized gains of $1 million) primarily due to significantly lower market prices. The average spot price at the Houston Ship Channel location for the three months ended March 31, 2016 decreased by $0.83/MMBtu, or 30%, to $1.93/MMBtu, compared to $2.76/MMBtu for the same period in the prior year.

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an increase of $64 million from Sunoco Logistics’ crude oil operations. During the quarter, Sunoco Logistics continued to utilize its storage capabilities to capture the contango market structure. The impact of last-in, first-out (“LIFO”) method of accounting in an environment where commodity prices are falling resulted in approximately $60 million of positive earnings in the quarter. This favorable LIFO timing is expected to be reversed in future periods as commodity prices rise or those inventory positions are liquidated. Excluding this favorable inventory timing, the Sunoco Logistics’ crude oil operations increased $4 million compared to the same period last year. This increase was primarily attributable to improved results from Sunoco Logistics’ crude oil pipelines which benefited from the Permian Express 2 pipeline that commenced operations in July 2015 and higher results from Sunoco Logistics’ crude oil terminals largely related to Sunoco Logistics’ Nederland facility. These increases were largely offset by a decrease in operating results from Sunoco Logistics’ crude oil acquisition and marketing activities resulting from narrowing crude oil differentials;

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an increase of $46 million from Sunoco Logistics’ NGLs operations, primarily due to increased volumes and fees from Sunoco Logistics’ Mariner NGLs projects, which includes Sunoco Logistics’ Nederland and Marcus Hook facilities. Higher volumes related to Sunoco Logistics’ NGLs acquisition and marketing activities and the absence of unfavorable LIFO inventory accounting also contributed to the increase; and

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an increase of $18 million from Sunoco Logistics’ refined products operations, primarily due to increased operating results from Sunoco Logistics’ refined products pipelines, which was largely attributable to the commencement of operations on Sunoco Logistics’ Allegheny Access project in 2015. Improved earnings from Sunoco Logistics’ refined products acquisition and marketing activities and increased contributions from Sunoco Logistics’ refined products joint ventures also contributed to the improvement.

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•	our natural gas marketing and compression operations;

•	a 33% non-operating interest in PES, a refining joint venture; and

•	our investment in Coal Handling, an entity that owns and operates end-user coal handling facilities.

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(1)	Indirect capital expenditures comprise those funded by our publicly traded subsidiary; all other capital expenditures are reflected as direct capital expenditures.

(2)	Includes capital expenditures related to the Bakken, Bayou Bridge and Rover pipeline projects, which includes $112 million related to Sunoco Logistics’ proportionate ownership in the Bakken and Bayou Bridge pipeline projects.

(1)	Direct capital expenditures exclude those funded by our publicly traded subsidiary.

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

(3)	Net of amounts forecasted to be financed at the asset level with non-recourse debt of approximately $1.21 billion.

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