Energy Transfer Partners Reports Second Quarter Results

Energy Transfer Partners, L.P. (NYSE: ETP) (“ETP” or the “Partnership”) today reported its financial results for the quarter ended June 30, 2015. Adjusted EBITDA for ETP for the three months ended June 30, 2015 totaled $1.49 billion, an increase of $95 million compared to the same period last year. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the three months ended June 30, 2015 totaled $894 million, an increase of $149 million compared to the same period last year. Income from continuing operations for the three months ended June 30, 2015 was $839 million, an increase of $334 million compared to the same period last year.

On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency Energy Partners LP (“Regency”), with Regency continuing as the surviving entity (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.4124 Partnership common units. ETP issued 172.2 million Partnership common units to Regency unitholders, including 15.5 million units issued to Partnership subsidiaries. The 1.9 million outstanding Regency series A preferred units were converted into corresponding new Partnership Series A Preferred Units on a one-for-one basis.

In connection with the Regency Merger, Energy Transfer Equity, L.P. (“ETE”) will reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy in connection with the Regency Merger will be $80 million in the first year post-closing and $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.

In July 2015, ETP announced an increase in its quarterly distribution to $1.035 per Partnership common unit ($4.14 annualized) for the quarter ended June 30, 2015, representing an increase of $0.32 per Partnership common unit on an annualized basis, or 8.4%, compared to the second quarter of 2014. For the quarter ended June 30, 2015, ETP’s distribution coverage ratio was 1.03x, and its distributable cash flow per common unit was $1.23.

ETP’s other recent key accomplishments include the following:

• In July 2015, ETP, Sunoco Logistics Partners L.P. (“Sunoco Logistics”) and Phillips 66 announced they have formed a joint venture to construct the Bayou Bridge pipeline that will deliver crude oil from the Phillips 66 and Sunoco Logistics terminals in Nederland, Texas to Lake Charles, Louisiana. Phillips 66 holds a 40% interest in the joint venture and ETP and Sunoco Logistics each hold a 30% interest.
• In July 2015, Sunoco LP acquired 100% of Susser Holdings Corporation (“Susser”) from ETP in a transaction valued at $1.93 billion. Sunoco LP paid approximately $997 million in cash (including payment for working capital) and issued 22 million Sunoco LP common units, valued at approximately $967 million, to ETP. In addition, there will be an exchange for 11 million Sunoco LP units owned by Susser for another 11 million new Sunoco LP units to a subsidiary of ETP.
• In July 2015, ETE entered into an exchange and repurchase agreement with ETP, pursuant to which ETE would acquire 100% of the membership interests of Sunoco GP LLC, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, in exchange for the repurchase of 21 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 would terminate upon ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE agreed to provide ETP a $35 million annual IDR subsidy for two years. Following this transaction, Sunoco LP will no longer be consolidated for accounting purposes by ETP. This transaction is expected to close in August 2015.
• During the second quarter 2015, progress on Lake Charles LNG Export Company, LLC (“Lake Charles LNG”), an entity owned 60% by ETE and 40% by ETP, continued as we purchased the land for the project from Alcoa Inc. and as we received the draft Environmental Impact Statement (“EIS”) and filed the additional data and information requests required thereunder. We have also continued our work with the short-listed EPC contractors as we continue to refine the cost structure for the project. We expect to receive the final EIS next week on August 14th. The next milestone after that will be the Federal Energy Regulatory Commission (“FERC”) authorization. With the expected emphasis on capital discipline and overall cost, we continue to believe that Lake Charles LNG is one of the most attractive pre-final investment decision (“FID”) projects for both Royal Dutch Shell plc and BG Group plc and that as a result, we remain on track to sanction FID of the project in 2016.
• Subsequent to the Regency Merger, ETP has undertaken a series of liability management steps, including (i) the repayment of $2.3 billion under Regency’s credit facility and cancellation of the facility upon the closing of the Regency Merger, (ii) the redemption in June 2015 of all of the outstanding $499 million aggregate principal amount of Regency’s 8.375% senior notes due 2019, (iii) the issuance in June 2015 of $3.0 billion aggregate principal amount of ETP senior notes with coupons ranging from 2.50% to 6.125% and maturities ranging from 2018 to 2045, and (iv) the repayment of outstanding borrowings under the ETP Credit Facility.
• As of June 30, 2015, the ETP Credit Facility had no outstanding borrowings and its credit ratio, as defined by the credit agreement, was 4.59x.
• In the second quarter of 2015, ETP issued 8.9 million common units through its at-the-market equity program, generating net proceeds of $493 million.

An analysis of ETP’s segment results and other supplementary data is provided after the financial tables shown below. ETP has scheduled a conference call for 8:00 a.m. Central Time, Thursday, August 6, 2015 to discuss the second quarter 2015 results. The conference call will be broadcast live via an internet web cast, which can be accessed through www.energytransfer.com and will also be available for replay on ETP’s web site for a limited time.

Energy Transfer Partners, L.P. (NYSE: ETP) is a master limited partnership owning and operating one of the largest and most diversified portfolios of energy assets in the United States. ETP’s subsidiaries include Panhandle Eastern Pipe Line Company, LP (the successor of Southern Union Company) and Lone Star NGL LLC, which owns and operates natural gas liquids storage, fractionation and transportation assets. In total, ETP currently owns and operates more than 62,000 miles of natural gas and natural gas liquids pipelines. ETP also owns the general partner, 100% of the incentive distribution rights, and approximately 67.1 million common units in Sunoco Logistics Partners L.P. (NYSE: SXL), which operates a geographically diverse portfolio of crude oil and refined products pipelines, terminalling and crude oil acquisition and marketing assets. ETP owns 100% of Sunoco, Inc. Additionally, ETP owns the general partner, 100% of the incentive distribution rights and approximately 66% of the limited partner interests in Sunoco LP (formerly Susser Petroleum Partners LP) (NYSE: SUN), a wholesale fuel distributor and convenience store operator. ETP’s general partner is owned by ETE. For more information, visit the Energy Transfer Partners, L.P. web site at www.energytransfer.com.

Energy Transfer Equity, L.P. (NYSE: ETE) is a master limited partnership which owns the general partner and 100% of the incentive distribution rights (IDRs) of Energy Transfer Partners, L.P. (NYSE: ETP) and approximately 23.6 million ETP Common Units and 81.0 million ETP Class H Units, which track 90% of the underlying economics of the general partner interest and the IDRs of Sunoco Logistics Partners L.P. (NYSE: SXL), and 100 ETP Class I Units. On a consolidated basis, ETE’s family of companies owns and operates approximately 71,000 miles of natural gas, natural gas liquids, refined products, and crude oil pipelines. For more information, visit the Energy Transfer Equity, L.P. web site at www.energytransfer.com.

Sunoco Logistics Partners L.P. (NYSE: SXL) is a master limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary crude oil, refined products, and natural gas liquids pipeline, terminalling and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, refined products, and natural gas liquids. Sunoco Logistics’ general partner is owned by Energy Transfer Partners, L.P. (NYSE: ETP). For more information, visit the Sunoco Logistics Partners, L.P. web site at www.sunocologistics.com.

Sunoco LP (NYSE: SUN) is a growth-oriented master limited partnership that primarily distributes motor fuel to convenience stores, independent dealers, commercial customers and distributors. Sunoco LP also operates more than 830 convenience stores and retail fuel sites. Sunoco LP conducts its business through wholly-owned subsidiaries, as well as through its 31.58% interest in Sunoco LLC, in partnership with its parent company, ETP. Sunoco LP’s general partner is owned by Energy Transfer Partners, L.P. (NYSE: ETP). For more information, visit the Sunoco LP web site at www.sunocolp.com.

Forward-Looking Statements

This press release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results are discussed in the Partnership’s Annual Reports on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. The Partnership undertakes no obligation to update or revise any forward-looking statement to reflect new information or events.

The information contained in this press release is available on our web site at www.energytransfer.com.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(unaudited)
		June 30, 2015				December 31, 2014
ASSETS
CURRENT ASSETS		$	7,259			$	6,043
PROPERTY, PLANT AND EQUIPMENT, net		42,857				38,907
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES		3,667				3,760
NON-CURRENT DERIVATIVE ASSETS		1				10
OTHER NON-CURRENT ASSETS, net		801				786
INTANGIBLE ASSETS, net		5,526				5,526
GOODWILL		7,440				7,642
Total assets		$	67,551			$	62,674
LIABILITIES AND EQUITY
CURRENT LIABILITIES		$	5,161			$	6,684
LONG-TERM DEBT, less current maturities		29,058				24,973
NON-CURRENT DERIVATIVE LIABILITIES		109				154
DEFERRED INCOME TAXES		4,104				4,246
OTHER NON-CURRENT LIABILITIES		1,220				1,258
COMMITMENTS AND CONTINGENCIES
SERIES A PREFERRED UNITS		33				33
REDEEMABLE NONCONTROLLING INTERESTS		15				15
EQUITY:
Total partners’ capital		21,313				12,070
Noncontrolling interest		6,538				5,153
Predecessor equity		—				8,088
Total equity		27,851				25,311
Total liabilities and equity		$	67,551			$	62,674

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(unaudited)
		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
REVENUES		$	11,540			$	14,088			$	21,866			$	27,115
COSTS AND EXPENSES
Cost of products sold		9,338				12,352				17,825				23,794
Operating expenses		651				417				1,270				831
Depreciation, depletion and amortization		501				436				980				796
Selling, general and administrative		162				115				295				220
Total costs and expenses		10,652				13,320				20,370				25,641
OPERATING INCOME		888				768				1,496				1,474
OTHER INCOME (EXPENSE)
Interest expense, net of interest capitalized		(336		)		(295		)		(646		)		(569		)
Equity in earnings of unconsolidated affiliates		117				77				174				181
Gain on sale of AmeriGas common units		—				93				—				163
Gains (losses) on interest rate derivatives		127				(46		)		50				(48		)
Other, net		(16		)		(21		)		(9		)		(21		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		780				576				1,065				1,180
Income tax expense (benefit) from continuing operations		(59		)		71				(42		)		216
INCOME FROM CONTINUING OPERATIONS		839				505				1,107				964
Income from discontinued operations		—				42				—				66
NET INCOME		839				547				1,107				1,030
Less: Net income attributable to noncontrolling interest		212				87				206				141
Less: Net income (loss) attributable to predecessor		(27		)		(11		)		(34		)		3
NET INCOME ATTRIBUTABLE TO PARTNERS		654				471				935				886
General Partner’s interest in net income		260				125				502				238
Class H Unitholder’s interest in net income		64				51				118				100
Class I Unitholder’s interest in net income		32				—				65				—
Common Unitholders’ interest in net income		$	298			$	295			$	250			$	548
INCOME FROM CONTINUING OPERATIONS PER COMMON UNIT:
Basic		$	0.67			$	0.79			$	0.63			$	1.47
Diluted		$	0.67			$	0.79			$	0.63			$	1.47
NET INCOME PER COMMON UNIT:
Basic		$	0.67			$	0.92			$	0.63			$	1.67
Diluted		$	0.67			$	0.92			$	0.63			$	1.67
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
Basic		434.8				318.5				379.6				321.4
Diluted		436.3				319.5				381.2				322.4

SUPPLEMENTAL INFORMATION
(Tabular dollar amounts in millions)
(unaudited)
		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (a):
Net income		$	839			$	547			$	1,107			$	1,030
Interest expense, net of interest capitalized		336				295				646				569
Gain on sale of AmeriGas common units		—				(93		)		—				(163		)
Income tax expense (benefit) from continuing operations (b)		(59		)		71				(42		)		216
Depreciation, depletion and amortization		501				436				980				796
Non-cash compensation expense		23				15				43				32
(Gains) losses on interest rate derivatives		(127		)		46				(50		)		48
Unrealized losses on commodity risk management activities		42				1				119				33
Inventory valuation adjustments		(184		)		(20		)		(150		)		(34		)
Equity in earnings of unconsolidated affiliates		(117		)		(77		)		(174		)		(181		)
Adjusted EBITDA related to unconsolidated affiliates		215				190				361				400
Other, net		19				(18		)		14				(15		)
Adjusted EBITDA (consolidated)		1,488				1,393				2,854				2,731
Adjusted EBITDA related to unconsolidated affiliates		(215		)		(190		)		(361		)		(400		)
Distributions from unconsolidated affiliates (c)		125				123				236				232
Interest expense, net of interest capitalized		(336		)		(295		)		(646		)		(569		)
Amortization included in interest expense		(8		)		(19		)		(21		)		(33		)
Current income tax (expense) benefit from continuing operations		112				(74		)		121				(327		)
Transaction-related income taxes (d)		—				41				—				347
Maintenance capital expenditures		(100		)		(74		)		(184		)		(138		)
Other, net		3				(1		)		7				—
Distributable Cash Flow (consolidated)		1,069				904				2,006				1,843
Distributable Cash Flow attributable to SXL (100%)		(264		)		(222		)		(424		)		(379		)
Distributions from SXL to ETP		98				68				188				130
Distributable Cash Flow attributable to Sunoco LP (100%)		(35		)		—				(68		)		—
Distributions from Sunoco LP to ETP		12				—				24				—
Distributable cash flow attributable to noncontrolling interest in Edwards Lime Gathering LLC		(5		)		(5		)		(10		)		(9		)
Distributable Cash Flow attributable to the partners of ETP		875				745				1,716				1,585
Transaction-related expenses		19				—				30				—
Distributable Cash Flow attributable to the partners of ETP, as adjusted		$	894			$	745			$	1,746			$	1,585
Distributions to the partners of ETP (e):
Limited Partners:
Common Units held by public		$	485			$	280			$	950			$	546
Common Units held by ETE		24				29				48				58
Class H Units held by ETE and ETE Common Holdings, LLC (“ETE Holdings”) (f)		62				53				118				103
General Partner interests held by ETE		7				5				15				10
Incentive Distribution Rights (“IDRs”) held by ETE		317				178				617				346
IDR relinquishments net of Class I Unit distributions		(28		)		(58		)		(55		)		(115		)
Total distributions to be paid to the partners of ETP		$	867			$	487			$	1,693			$	948
Distribution coverage ratio (g)		1.03x				1.53x				1.03x				1.67x
Distributable Cash Flow per Common Unit (h)		$	1.23			$	1.78			$	2.77			$	3.86

(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.

There are material limitations to using measures such as Adjusted EBITDA and Distributable Cash Flow, including the difficulty associated with using either as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA and Distributable Cash Flow may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP, such as gross margin, operating income, net income, and cash flow from operating activities.

Definition of Adjusted EBITDA

ETP defines Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, 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 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 ETP’s proportionate ownership.

Adjusted EBITDA is used by management to determine our operating performance and, along with other financial and volumetric data, as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.

Definition of Distributable Cash Flow

ETP defines Distributable Cash Flow as net income, adjusted for certain non-cash items, less maintenance capital expenditures. Non-cash items include depreciation and amortization, 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 and deferred income taxes. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Distributable Cash Flow reflects earnings from unconsolidated affiliates on a cash basis.

Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.

On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ETP’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among ETP’s subsidiaries, the Distributable Cash Flow generated by ETP’s subsidiaries may not be available to be distributed to the partners of ETP. In order to reflect the cash flows available for distributions to the partners of ETP, ETP has reported Distributable Cash Flow attributable to the partners of ETP, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:

• 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.

For Distributable Cash Flow attributable to the partners of ETP, as adjusted, certain transaction-related and non-recurring expenses that are included in net income are excluded.

(b) For the three and six months ended June 30, 2015, the Partnership’s income tax expense from continuing operations decreased primarily due to a decrease in earnings among the Partnership’s consolidated corporate subsidiaries, which resulted in decreases in income tax expense of $75 million and $135 million, respectively. The Partnership’s income tax expense also decreased for the three and six months ended June 30, 2015 by $12 million due to the exclusion of a portion of the dividend income received by certain of our consolidated corporate subsidiaries. For the three and six months ended June 30, 2015, the Partnership’s income tax expense was favorably impacted by $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. In addition, for the six months ended June 30, 2015, the Partnership’s income tax expense from continuing operations also decreased due to unfavorable income tax adjustments of $87 million in the prior period related to the Lake Charles LNG Transaction, which occurred in the first quarter of 2014 and was treated as a sale for tax purposes.

(c) Distributions from unconsolidated affiliates for the six months ended June 30, 2015 include $16 million of distributions paid to a subsidiary of ETP. Distributions from unconsolidated affiliates for the three and six months ended June 30, 2014 include $15 million and $30 million, respectively, of distributions paid to a subsidiary of ETP.

(d) Transaction-related income taxes primarily included income tax expense related to the Lake Charles LNG Transaction. For the three and six months ended June 30, 2014, amounts previously reported for each of the interim periods have been adjusted to reflect income taxes related to other transactions, which amounts had not previously been reflected in the calculation of Distributable Cash Flow for such interim periods.

(e) Distributions on ETP Common Units, as reflected above, exclude cash distributions on Partnership common units held by subsidiaries of ETP.

(f) Distributions on the Class H Units for the three and six months ended June 30, 2015 and 2014 were calculated as follows:

		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
General partner distributions and incentive distributions from SXL		$	69			$	43			$	131			$	82
		90.05		%		50.05		%		90.05		%		50.05		%
Share of SXL general partner and incentive distributions payable to Class H Unitholder		62				21				118				41
Incremental distributions payable to Class H Unitholder (IDR subsidy offset)*		—				32				—				62
Total Class H Unit distributions		$	62			$	53			$	118			$	103

* Incremental distributions previously paid to the Class H Unitholder were eliminated in Amendment No. 9 to ETP’s Amended and Restated Agreement of Limited Partnership effective in the first quarter of 2015.

(g) 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.

(h) 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.

Similar to Distributable Cash Flow as described above, Distributable Cash Flow per Common Unit is a significant liquidity measure used by the Partnership’s senior management to compare net cash flows generated by the Partnership to the distributions the Partnership expects to pay to its unitholders. Using this measure, the Partnership’s management can compare Distributable Cash Flow attributable to the partners of ETP, as adjusted, among different periods on a per-unit basis.

Distributable Cash Flow per Common Unit is calculated as follows:

		Three Months Ended June 30,								Six Months Ended June 30,
		2015				2014				2015				2014
Distributable Cash Flow attributable to the partners of ETP, as adjusted		$	894			$	745			$	1,746			$	1,585
Less:
Class H Units held by ETE and ETE Holdings		(62		)		(53		)		(118		)		(103		)
General Partner interests held by ETE		(7		)		(5		)		(15		)		(10		)
IDRs held by ETE		(317		)		(178		)		(617		)		(346		)
IDR relinquishments net of Class I Unit distributions		28				58				55				115
		$	536			$	567			$	1,051			$	1,241
Weighted average Common Units outstanding – basic		434.8				318.5				379.6				321.4
Distributable Cash Flow per Common Unit		$	1.23			$	1.78			$	2.77			$	3.86

SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)

Our segment results were presented based on the measure of Segment Adjusted EBITDA. The tables below identify the components of Segment Adjusted EBITDA, which was calculated as follows:

• 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.

		Three Months Ended June 30,
		2015				2014
Segment Adjusted EBITDA:
Midstream		$	376			$	356
Liquids transportation and services		151				141
Interstate transportation and storage		285				291
Intrastate transportation and storage		117				124
Investment in Sunoco Logistics		326				280
Retail marketing		140				136
All other		93				65
		$	1,488			$	1,393

Midstream

		Three Months Ended June 30,
		2015				2014
Gathered volumes (MMBtu/d)		10,161,338				8,042,365
NGLs produced (Bbls/d)		399,662				292,880
Equity NGLs (Bbls/d)		30,160				26,761
Revenues		$	1,244			$	1,798
Cost of products sold		797				1,339
Gross margin		447				459
Unrealized losses on commodity risk management activities		71				—
Operating expenses, excluding non-cash compensation expense		(147		)		(101		)
Selling, general and administrative expenses, excluding non-cash compensation expense		(3		)		(6		)
Adjusted EBITDA related to unconsolidated affiliates		7				4
Other		1				—
Segment Adjusted EBITDA		$	376			$	356

Gathered volumes, NGLs produced and equity NGLs produced increased primarily due to the Eagle Rock and King Ranch acquisitions, as well as increased gathering and processing capacities in the Eagle Ford Shale, Permian Basin and Cotton Valley regions.

Segment Adjusted EBITDA for the midstream segment reflected a decrease in gross margin as follows:

		Three Months Ended June 30,
		2015				2014
Gathering and processing fee-based revenues		$	384			$	311
Non fee-based contracts and processing		63				148
Total gross margin		$	447			$	459

Midstream gross margin reflected an increase in fee-based revenues of $48 million primarily due to increased production and increased capacity from assets recently placed in service in the Eagle Ford Shale, Permian Basin and Cotton Valley. Fee-based revenues also increased $5 million due to a change in contract terms on our Southeast Texas system where certain contracts were converted from non fee-based terms to fee-based. Additionally, the acquisition of Eagle Rock midstream assets in July 2014 also increased fee-based margin by $21 million. Lower commodity prices and changes in contract terms resulted in decreases of non fee-based margins of $70 million and $9 million, respectively. These decreases were partially offset by an increase from the acquisition of Eagle Rock midstream assets of $11 million.

Segment Adjusted EBITDA for the midstream segment reflected higher operating expenses primarily due to additional expense from assets recently placed in service and the acquisition of Eagle Rock midstream assets in July 2014.

Segment Adjusted EBITDA for the midstream segment also reflected lower selling, general and administrative expenses primarily due to a reduction in employee-related costs.

Liquids Transportation and Services

		Three Months Ended June 30,
		2015				2014
Liquids transportation volumes (Bbls/d)		482,351				367,564
NGL fractionation volumes (Bbls/d)		253,987				191,255
Revenues		$	824			$	903
Cost of products sold		628				731
Gross margin		196				172
Unrealized gains on commodity risk management activities		(5		)		—
Operating expenses, excluding non-cash compensation expense		(39		)		(29		)
Selling, general and administrative expenses, excluding non-cash compensation expense		(4		)		(4		)
Adjusted EBITDA related to unconsolidated affiliates		3				2
Segment Adjusted EBITDA		$	151			$	141

NGL transportation volumes increased due to an increase in volumes transported on our Lone Star Gateway pipeline system of 67,000 BBls/d. These increased volumes were primarily out of west Texas as producers ramped up volumes. Additionally, we commissioned a crude transportation pipeline at the end of 2014 that transported 36,000 Bbls/d during the three months ended June 30, 2015. The remainder of the increase related to volumes on our NGL pipelines from our plants in southeast Texas and in the Eagle Ford region.

Average daily fractionated volumes increased due to the ramp-up of our second 100,000 Bbls/d fractionator at Mont Belvieu, Texas, which was commissioned in October 2013. These volumes include all physical and contractual volumes where we collected a fractionation fee.

Segment Adjusted EBITDA for the liquids transportation and services segment reflected an increase in gross margin as follows:

		Three Months Ended June 30,
		2015				2014
Transportation margin		$	91			$	69
Processing and fractionation margin		76				57
Storage margin		39				37
Other margin		(10		)		9
Total gross margin		$	196			$	172

Transportation margin increased $16 million due to higher volumes transported out of west Texas on our Lone Star Gateway pipeline system, as noted in the volume discussion above. In addition, the increase in transportation margin also reflected an increase in volumes transported from our processing plants in southeast Texas and in the Eagle Ford region on our NGL pipeline system to Mont Belvieu, Texas, which increased $3 million. The commissioning of our crude transportation pipeline in south Texas also contributed an additional $3 million to the increase.

Processing and fractionation margin increased $18 million due to the ramp-up of Lone Star’s second fractionator at Mont Belvieu, Texas, which was commissioned in October 2013. Additionally, the commissioning of the Mariner South LPG export project during February 2015 contributed an additional $12 million for the three months ended June 30, 2015.

Storage margin reflected increases of approximately $7 million due to increased demand for leased storage capacity as a result of favorable market conditions. These increases in fee based storage margin were offset by a decrease of $4 million from lower non fee-based storage activities, including blending activities of $1 million, and $3 million of lower financial gains recognized on the withdrawal of inventory from our storage facilities.

Other margin decreased primarily due to the accounting treatment of NGL storage inventory and the timing of declines in the market price of component NGL products, resulting in losses realized during the three months ended June 30, 2015.

Segment Adjusted EBITDA for the liquids transportation and services segment also reflected an increase in operating expenses for the three months ended June 30, 2015 compared to the same period last year primarily due to the commissioning of the Mariner South LPG export project during February 2015 and the ramp-up of Lone Star’s second fractionator at Mont Belvieu, Texas, which was commissioned in October 2013.

Interstate Transportation and Storage

		Three Months Ended June 30,
		2015				2014
Natural gas transported (MMBtu/d)		5,873,424				5,745,746
Natural gas sold (MMBtu/d)		14,827				15,733
Revenues		$	243			$	249
Operating expenses, excluding non-cash compensation, amortization and accretion expenses		(71		)		(67		)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses		(14		)		(16		)
Adjusted EBITDA related to unconsolidated affiliates		127				125
Segment Adjusted EBITDA		$	285			$	291
Distributions from unconsolidated affiliates		$	83			$	76

Transported volumes increased primarily due to favorable throughput on the Tiger and Transwestern pipelines, resulting in increases of 183,446 MMBtu/d and 115,648 MMBtu/d, respectively. These increases were partially offset by a decrease of 96,255 MMBtu/d on the Trunkline Gas pipeline as a result of lower customer demand due to lower price spreads.

Segment Adjusted EBITDA for the interstate transportation and storage segment decreased primarily due to the expiration of a transportation rate schedule on the Transwestern pipeline.

The increase in cash distributions from unconsolidated affiliates reflected an increase in cash distributions from Citrus due to an increase in revenues from the sale of additional Phase VIII capacity.

Intrastate Transportation and Storage

		Three Months Ended June 30,
		2015				2014
Natural gas transported (MMBtu/d)		8,666,363				9,069,215
Revenues		$	569			$	712
Cost of products sold		383				551
Gross margin		186				161
Unrealized gains on commodity risk management activities		(34		)		(3		)
Operating expenses, excluding non-cash compensation expense		(42		)		(43		)
Selling, general and administrative expenses, excluding non-cash compensation expense		(8		)		(5		)
Adjusted EBITDA related to unconsolidated affiliates		15				14
Segment Adjusted EBITDA		$	117			$	124
Distributions from unconsolidated affiliates		$	14			$	12

Transported volumes declined compared to the same period last year primarily due to lower production from certain key shippers in the Barnett Shale region, offset by the ramp up of volumes related to significant new long-term transportation contracts.

Intrastate transportation and storage gross margin increased $10 million from natural gas sales and other primarily due to an increase in margin from the purchase and sale of natural gas on our system and an increase of $13 million in transportation fees primarily due to increased revenue from renegotiated and newly initiated long-term fixed capacity fee contracts on our Houston pipeline system. Additionally, storage margin increased $13 million primarily due to an increase in the volume of natural gas we own in the Bammel storage facility. These increases were partially offset by a decrease of $11 million in retained fuel revenues primarily due to significantly lower market prices.

Investment in Sunoco Logistics

		Three Months Ended June 30,
		2015				2014
Revenues		$	3,203			$	4,821
Cost of products sold		2,721				4,517
Gross margin		482				304
Unrealized losses on commodity risk management activities		7				8
Operating expenses, excluding non-cash compensation expense		(53		)		(26		)
Selling, general and administrative expenses, excluding non-cash compensation expense		(23		)		(20		)
Inventory valuation adjustments		(100		)		—
Adjusted EBITDA related to unconsolidated affiliates		13				14
Segment Adjusted EBITDA		$	326			$	280
Distributions from unconsolidated affiliates		$	5			$	4

Segment Adjusted EBITDA related to Sunoco Logistics increased due to the net impacts of the following:

• an increase of $43 million from terminal facilities, primarily attributable to higher results from Sunoco Logistics’ products acquisition and marketing activities, which were positively impacted by inventory accounting resulting from the liquidation of certain inventories that were stored during the first quarter to capture the contango market structure. Improved operating results from Sunoco Logistics’ Marcus Hook and Nederland terminals also contributed to the increase. These positive impacts were partially offset by lower results from Sunoco Logistics’ refined products terminals; and
• an increase of $30 million from products pipelines, primarily due to higher throughput volumes and higher average pipeline revenue per barrel associated with Sunoco Logistics’ Mariner NGL pipeline projects. These positive impacts were partially offset by lower contributions from Sunoco Logistics’ joint venture interests; partially offset by
• a decrease of $15 million from crude oil pipelines, primarily due to lower average pipeline revenue per barrel primarily driven by reduced volumes on higher-priced tariff movements. Increased operating expenses, which included lower pipeline operating gains and higher line testing costs, and selling, general and administrative expenses on growth also contributed to the decrease. These impacts were partially offset by additional throughput volumes largely attributable to expansion projects placed into service in 2014; and
• a decrease of $12 million from crude oil acquisition and marketing activities, primarily attributable to lower realized crude oil margins, which were negatively impacted by narrowing crude oil differentials compared to the prior year period. This impact was partially offset by increased crude oil volumes resulting from 2014 acquisitions and the expansion of Sunoco Logistics’ crude oil trucking fleet.

Retail Marketing

		Three Months Ended June 30,
		2015				2014
Motor fuel outlets and convenience stores, end of period:
Retail		1,276				568
Third-party wholesale		5,481				4,584
Total		6,757				5,152
Total motor fuel gallons sold (in millions):
Retail		639				328
Third-party wholesale		1,285				1,129
Total		1,924				1,457
Motor fuel gross profit (cents/gallon):
Retail		21.0				28.5
Third-party wholesale		8.1				10.1
Volume-weighted average for all gallons		12.4				14.3
Merchandise sales (in millions)		$	559			$	175
Retail merchandise margin %		31.5		%		26.6		%
Revenues		$	5,537			$	5,568
Cost of products sold		5,003				5,260
Gross margin		534				308
Unrealized (gains) losses on commodity risk management activities		1				(1		)
Operating expenses, excluding non-cash compensation expense		(281		)		(135		)
Selling, general and administrative expenses, excluding non-cash compensation expense		(57		)		(17		)
Inventory valuation adjustments		(57		)		(20		)
Adjusted EBITDA related to unconsolidated affiliates		—				1
Segment Adjusted EBITDA		$	140			$	136

Retail marketing gross margin increased due to the net impacts of the following:

• an increase of $199 million from the acquisition of Susser in August 2014;
• favorable impact of $26 million from other recent acquisitions;
• an increase of $36 million from non-retail margins;
• an increase of $6 million from other retail margins;
• favorable impact of $37 million related to non-cash inventory valuation adjustments; partially offset by
• unfavorable impact of $77 million in fuel margins and volumes of $3 million.

Segment Adjusted EBITDA for the retail marketing segment also reflected an increase in operating expenses and in selling, general and administrative expenses primarily due to recent acquisitions.

All Other

		Three Months Ended June 30,
		2015				2014
Revenues		$	721			$	825
Cost of products sold		617				735
Gross margin		104				90
Unrealized (gains) losses on commodity risk management activities		2				(3		)
Operating expenses, excluding non-cash compensation expense		(22		)		(20		)
Selling, general and administrative expenses, excluding non-cash compensation expense		(47		)		(48		)
Adjusted EBITDA related to unconsolidated affiliates		53				31
Other		19				19
Eliminations		(16		)		(4		)
Segment Adjusted EBITDA		$	93			$	65
Distributions from unconsolidated affiliates		$	19			$	13

Amounts reflected in our all other segment primarily include:

• our natural gas marketing and compression operations;
• an approximate 33% non-operating interest in PES, a refining joint venture;
• Regency’s investment in Coal Handling, an entity that owns and operates end-user coal handling facilities; and
• our investment in AmeriGas until August 2014.

Segment Adjusted EBITDA increased primarily due to an increase of $22 million in Adjusted EBITDA related to unconsolidated affiliates. The increase in Adjusted EBITDA related to unconsolidated affiliates was primarily due to higher earnings driven by stronger refining crack spreads from our investment in PES of $29 million, partially offset by a decrease of $5 million related to our investment in AmeriGas driven by a reduction in our investment due to the sale of AmeriGas common units in 2014.

In connection with the Lake Charles LNG Transaction, 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. These fees were reflected in “Other” in the “All other” segment and for the three months ended June 30, 2015 were reflected as an offset to operating expenses of $7 million and selling, general and administrative expenses of $12 million in the consolidated statements of operations.

The increase in cash distributions from unconsolidated affiliates was primarily due to an increase of $19 million in cash distribution from our ownership in PES, partially offset by a decrease of $11 million in cash distribution from our ownership in AmeriGas as a result of selling our interests in AmeriGas in 2014.

SUPPLEMENTAL INFORMATION ON CAPITAL EXPENDITURES
(Tabular amounts in millions)
(unaudited)
The following is a summary of capital expenditures (net of contributions in aid of construction costs) for the six months
ended June 30, 2015:
	Growth				Maintenance				Total
Direct(1):
Midstream	$	1,014			$	32			$	1,046
Liquids transportation and services(2)	1,117				8				1,125
Interstate transportation and storage(2)	586				47				633
Intrastate transportation and storage	28				8				36
Retail marketing(3)	134				33				167
All other (including eliminations)	183				18				201
Total direct capital expenditures	3,062				146				3,208
Indirect(1):
Investment in Sunoco Logistics	898				31				929
Investment in Sunoco LP(3)	83				7				90
Total indirect capital expenditures	981				38				1,019
Total capital expenditures	$	4,043			$	184			$	4,227

^{(1) Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.
(2) Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects.
(3) The retail marketing segment includes the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary.}

We currently expect capital expenditures (net of contributions in aid of construction costs) for the full year 2015 to be within the following ranges:

		Growth								Maintenance
		Low				High				Low				High
Direct(1):
Midstream		$	1,900			$	2,000			$	90			$	110
Liquids transportation and services:
NGL		1,550				1,600				20				25
Crude(2)		800				850				—				—
Interstate transportation and storage(2)		700				750				130				140
Intrastate transportation and storage		130				180				30				35
Retail marketing(3)		160				210				55				75
All other (including eliminations)		200				250				35				45
Total direct capital expenditures		5,440				5,840				360				430
Indirect(1):
Investment in Sunoco Logistics		2,400				2,600				65				75
Investment in Sunoco LP(3)		220				270				40				50
Total indirect capital expenditures		2,620				2,870				105				125
Total projected capital expenditures		$	8,060			$	8,710			$	465			$	555

^{(1) Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.
(2) Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects.
(3) The retail marketing segment includes the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary.}

SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions)
(unaudited)
		Three Months Ended June 30,
		2015				2014
Equity in earnings (losses) of unconsolidated affiliates:
Citrus		$	29			$	26
FEP		13				13
PES		47				18
MEP		11				11
HPC		6				8
AmeriGas		(2		)		(8		)
Other		13				9
Total equity in earnings of unconsolidated affiliates		$	117			$	77
Adjusted EBITDA related to unconsolidated affiliates:
Citrus		$	85			$	81
FEP		18				18
PES		54				25
MEP		24				26
HPC		15				14
AmeriGas		—				5
Other		19				21
Total Adjusted EBITDA related to unconsolidated affiliates		$	215			$	190
Distributions received from unconsolidated affiliates:
Citrus		$	47			$	41
FEP		16				16
PES		19				—
MEP		20				18
HPC		14				11
AmeriGas		—				11
Other		9				11
Total distributions received from unconsolidated affiliates – actual		$	125			$	108

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