Energy Transfer Partners Reports Third Quarter Results

DALLAS--(BUSINESS WIRE)-- Energy Transfer Partners, L.P. (NYSE: ETP) (“ETP” or the “Partnership”) today reported its financial results for the quarter ended September 30, 2015. Adjusted EBITDA for ETP for the three months ended September 30, 2015 totaled $1.50 billion, an increase of $49 million compared to the same period last year. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the three months ended September 30, 2015 totaled $740 million, a decrease of $130 million compared to the same period last year. Income from continuing operations for the three months ended September 30, 2015 was $393 million, a decrease of $121 million compared to the same period last year.

Distributable Cash Flow for the third quarter of 2015 was affected by a partial reversal from the second quarter 2015 tax benefit, with $79 million of current income tax expense for the third quarter of 2015. Distributable Cash Flow was also affected this quarter by a lower overall pricing environment for percent-of-proceeds volumes, continued shut-in volumes in the Northeast and unscheduled plant outages in the Permian Basin.

In October 2015, ETP announced an increase in its quarterly distribution to $1.055 per Partnership common unit ($4.22 annualized) for the quarter ended September 30, 2015, representing an increase of $0.32 per Partnership common unit on an annualized basis, or 8.2%, compared to the third quarter of 2014.

ETP’s other recent key accomplishments include the following:

• Effective July 1, 2015, Energy Transfer Equity, L.P. (“ETE”) acquired 100% of the membership interests of Sunoco GP LLC (“Sunoco GP”), the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETE transferred to ETP 21 million ETP common units. 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. In connection with this transaction, the Partnership deconsolidated Sunoco LP. The Partnership continues to hold 26.8 million Sunoco LP common units and 10.9 million Sunoco LP subordinated units accounted for under the equity method.
• In October 2015, Sunoco Logistics Partners L.P. (“Sunoco Logistics”) completed the previously announced 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, LLC and Energy Transfer Crude Oil Company, LLC, which together intend to develop the previously announced pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast (the “Bakken Pipeline Project”). 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.
• During the third quarter 2015, Lake Charles LNG Export Company, LLC (“Lake Charles LNG”), an entity owned 60% by ETE and 40% by ETP, received the Federal Energy Regulatory Commission (“FERC”) Final Environmental Impact Study for the liquefaction project. This issuance starts the 90-day period in which other federal agencies are required to complete their review of the liquefaction project and issue any necessary agency authorizations. That decision deadline is November 12, 2015. The FERC authorization for the liquefaction project is expected to be issued during this 90-day period. With the expected emphasis on capital discipline and overall cost, ETP continues 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, the project remains on track to receive FID in 2016, with construction to start immediately thereafter and first LNG exports anticipated in late-2020.
• As of September 30, 2015, the ETP Credit Facility had $665 million outstanding borrowings and its credit ratio, as defined by the credit agreement, was 4.49x.
• In the third quarter of 2015, ETP issued 4.4 million common units through its at-the-market equity program, generating net proceeds of $206 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, November 5, 2015 to discuss the third 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 62,500 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. Additionally, ETP owns fuel distribution and retail marketing assets and approximately 50.8% 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 Energy Transfer Equity, L.P. (NYSE: 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 Sunoco LP (NYSE: SUN) and approximately 2.6 million ETP Common Units, approximately 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.

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)
		September 30,2015				December 31,2014
ASSETS
CURRENT ASSETS		$	5,325			$	6,043
PROPERTY, PLANT AND EQUIPMENT, net			42,821				38,907
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES			5,119				3,760
NON-CURRENT DERIVATIVE ASSETS			15				10
OTHER NON-CURRENT ASSETS, net			738				786
INTANGIBLE ASSETS, net			4,494				5,526
GOODWILL			5,633				7,642
Total assets		$	64,145			$	62,674
LIABILITIES AND EQUITY
CURRENT LIABILITIES		$	4,483			$	6,684
LONG-TERM DEBT, less current maturities			27,449				24,973
NON-CURRENT DERIVATIVE LIABILITIES			189				154
DEFERRED INCOME TAXES			3,768				4,246
OTHER NON-CURRENT LIABILITIES			1,144				1,258
COMMITMENTS AND CONTINGENCIES
SERIES A PREFERRED UNITS			33				33
REDEEMABLE NONCONTROLLING INTERESTS			15				15
EQUITY:
Total partners’ capital			21,074				12,070
Noncontrolling interest			5,990				5,153
Predecessor equity			—				8,088
Total equity			27,064				25,311
Total liabilities and equity		$	64,145			$	62,674

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(unaudited)
		Three Months EndedSeptember 30,								Nine Months EndedSeptember 30,
			2015				2014			2015				2014
REVENUES		$	6,601			$	14,933			$	28,467			$	42,048
COSTS AND EXPENSES
Cost of products sold			4,925				13,014			22,750				36,808
Operating expenses			535				547			1,805				1,378
Depreciation, depletion and amortization			471				410			1,451				1,206
Selling, general and administrative			94				152			389				372
Total costs and expenses			6,025				14,123			26,395				39,764
OPERATING INCOME			576				810			2,072				2,284
OTHER INCOME (EXPENSE)
Interest expense, net of interest capitalized			(333	)			(299	)		(979		)		(868		)
Equity in earnings of unconsolidated affiliates			214				84			388				265
Losses on extinguishments of debt			(10	)			—			(43		)		—
Gain on sale of AmeriGas common units			—				14			—				177
Losses on interest rate derivatives			(64	)			(25	)		(14		)		(73		)
Other, net			32				(15	)		56				(36		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE			415				569			1,480				1,749
Income tax expense (benefit) from continuing operations			22				55			(20		)		271
INCOME FROM CONTINUING OPERATIONS			393				514			1,500				1,478
Income from discontinued operations			—				—			—				66
NET INCOME			393				514			1,500				1,544
Less: Net income (loss) attributable to noncontrolling interest			(24	)			78			182				219
Less: Net income (loss) attributable to predecessor			—				94			(34		)		97
NET INCOME ATTRIBUTABLE TO PARTNERS			417				342			1,352				1,228
General Partner’s interest in net income			277				135			779				373
Class H Unitholder’s interest in net income			66				59			184				159
Class I Unitholder’s interest in net income			15				—			80				—
Common Unitholders’ interest in net income		$	59			$	148			$	309			$	696
INCOME FROM CONTINUING OPERATIONS PER COMMON UNIT:
Basic		$	0.11			$	0.44			$	0.70			$	1.91
Diluted		$	0.10			$	0.44			$	0.68			$	1.90
NET INCOME PER COMMON UNIT:
Basic		$	0.11			$	0.44			$	0.70			$	2.11
Diluted		$	0.10			$	0.44			$	0.68			$	2.10
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
Basic			485.0				331.4			415.1				324.8
Diluted			487.3				333.1			417.7				326.5

SUPPLEMENTAL INFORMATION
(Dollars and units in millions, except per unit amounts)
(unaudited)
		Three Months EndedSeptember 30,								Nine Months EndedSeptember 30,
			2015				2014				2015				2014
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (a):
Net income		$	393			$	514			$	1,500			$	1,544
Interest expense, net of interest capitalized			333				299				979				868
Gain on sale of AmeriGas common units			—				(14	)			—				(177	)
Income tax expense (benefit) from continuing operations (b)			22				55				(20	)			271
Depreciation, depletion and amortization			471				410				1,451				1,206
Non-cash compensation expense			16				18				59				50
Losses on interest rate derivatives			64				25				14				73
Unrealized (gains) losses on commodity risk management activities			(47	)			(32	)			72				1
Inventory valuation adjustments			134				51				(16	)			17
Losses on extinguishments of debt			10				—				43				—
Equity in earnings of unconsolidated affiliates			(214	)			(84	)			(388	)			(265	)
Adjusted EBITDA related to unconsolidated affiliates			350				184				711				584
Other, net			(32	)			25				(51	)			10
Adjusted EBITDA (consolidated)			1,500				1,451				4,354				4,182
Adjusted EBITDA related to unconsolidated affiliates			(350	)			(184	)			(711	)			(584	)
Distributable cash flow from unconsolidated affiliates (c)			232				131				468				363
Interest expense, net of interest capitalized			(333	)			(299	)			(979	)			(868	)
Amortization included in interest expense			(9	)			(15	)			(30	)			(48	)
Current income tax (expense) benefit from continuing operations			(79	)			(10	)			42				(337	)
Transaction-related income taxes (d)			—				34				—				381
Maintenance capital expenditures			(124	)			(122	)			(308	)			(260	)
Other, net			4				5				11				5
Distributable Cash Flow (consolidated)			841				991				2,847				2,834
Distributable Cash Flow attributable to SXL (100%)			(210	)			(194	)			(634	)			(573	)
Distributions from SXL to ETP			107				74				295				204
Distributable Cash Flow attributable to Sunoco LP (100%) (e)			—				(4	)			(68	)			(4	)
Distributions from Sunoco LP to ETP (e)			—				8				24				8
Distributable cash flow attributable to noncontrolling interest in Edwards Lime Gathering LLC			(5	)			(5	)			(15	)			(14	)
Distributable Cash Flow attributable to the partners of ETP			733				870				2,449				2,455
Transaction-related expenses			7				—				37				—
Distributable Cash Flow attributable to the partners of ETP, as adjusted		$	740			$	870			$	2,486			$	2,455
Distributions to the partners of ETP (f):
Limited Partners:
Common Units held by public		$	508			$	312			$	1,458			$	858
Common Units held by ETE			3				30				51				88
Class H Units held by ETE (g)			68				56				186				159
General Partner interests held by ETE			8				6				23				16
Incentive Distribution Rights (“IDRs”) held by ETE			320				200				937				546
IDR relinquishments net of Class I Unit distributions			(28	)			(67	)			(83	)			(182	)
Total distributions to be paid to the partners of ETP		$	879			$	537			$	2,572			$	1,485
Common Units outstanding – end of period			495.6				351.0				495.6				351.0
Distribution coverage ratio (h)		0.84x				1.62x				0.97x				1.65x
Distributable Cash Flow per Common Unit (i)		$	0.77			$	2.04			$	3.43			$	5.90

(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, including (i) for unconsolidated affiliates with publicly traded equity interests, distributions paid or expected to be paid for the periods presented and (ii) for unconsolidated affiliates that are under common control of ETP’s parent, ETP’s proportionate share of the distributable cash flow of the investee.

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 nine months ended September 30, 2015, 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 and nine months ended September 30, 2015 also reflect 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. For the three and nine months ended September 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. Additionally, the Partnership recognized a net tax benefit of $7 million related to the settlement of the Southern Union 2004-2009 Internal Revenue Service (“IRS”) examination in July 2015. For the three and nine months ended September 30, 2014, the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $87 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes.

(c) For the three and nine months ended September 30, 2015, distributions from unconsolidated affiliates includes distributions to be paid by Sunoco LP with respect to the third quarter of 2015, as well as the Partnership’s share of the distributable cash flow of Sunoco LLC for the third quarter of 2015.

(d) Transaction-related income taxes primarily included income tax expense related to the Lake Charles LNG Transaction. For the three and nine months ended September 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) 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 equity method investment.

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

(g) Distributions on the Class H Units for the three and nine months ended September 30, 2015 and 2014 were calculated as follows:

		Three Months EndedSeptember 30,								Nine Months EndedSeptember 30,
			2015				2014				2015				2014
General partner distributions and incentive distributions from SXL		$	76			$	49			$	207			$	131
			90.05	%			50.05	%			90.05	%			50.05	%
Share of SXL general partner and incentive distributions payable to Class H Unitholder			68				25				186				66
Incremental distributions payable to Class H Unitholder (IDR subsidy offset)*			—				31				—				93
Total Class H Unit distributions		$	68			$	56			$	186			$	159

* 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.

(h) 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.

(i) 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 EndedSeptember 30,								Nine Months EndedSeptember 30,
			2015				2014				2015				2014
Distributable Cash Flow attributable to the partners of ETP, as adjusted		$	740			$	870			$	2,486			$	2,455
Less:
Class H Units held by ETE			(68	)			(56	)			(186	)			(159	)
General Partner interests held by ETE			(8	)			(6	)			(23	)			(16	)
IDRs held by ETE			(320	)			(200	)			(937	)			(546	)
IDR relinquishments net of Class I Unit distributions			28				67				83				182
		$	372			$	675			$	1,423			$	1,916
Weighted average Common Units outstanding – basic			485.0				331.4				415.1				324.8
Distributable Cash Flow per Common Unit		$	0.77			$	2.04			$	3.43			$	5.90

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 EndedSeptember 30,
		2015					2014
Segment Adjusted EBITDA:
Midstream		$	318			$	379
Liquids transportation and services			192				163
Interstate transportation and storage			286				288
Intrastate transportation and storage			127				124
Investment in Sunoco Logistics			289				246
Retail marketing			195				191
All other			93				60
		$	1,500			$	1,451

Midstream
	Three Months EndedSeptember 30,
		2015				2014
Gathered volumes (MMBtu/d)		10,384,788				9,150,060
NGLs produced (Bbls/d)		413,426				364,302
Equity NGLs (Bbls/d)		26,296				30,703
Revenues	$	1,383			$	1,967
Cost of products sold		916				1,428
Gross margin		467				539
Unrealized gains on commodity risk management activities		—				(16	)
Operating expenses, excluding non-cash compensation expense		(148	)			(136	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(9	)			(12	)
Adjusted EBITDA related to unconsolidated affiliates		6				4
Other		2				—
Segment Adjusted EBITDA	$	318			$	379

Gathered volumes and NGLs produced increased primarily due to the King Ranch acquisition, 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 EndedSeptember 30,
			2015			2014
Gathering and processing fee-based revenues		$	400		$	352
Non fee-based contracts and processing			67			187
Total gross margin		$	467		$	539

Midstream gross margin reflected an increase in fee-based revenues of $46 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. Midstream gross margin reflected a decrease in non fee-based revenues due to lower commodity prices. The decrease between periods also reflected the impact from $16 million of gains on commodity risk management activities recorded in the prior period.

Segment Adjusted EBITDA for the midstream segment reflected higher operating expenses primarily due to additional expense from assets recently placed in service, including the Rebel system in west Texas and the King Ranch system in south Texas.

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 EndedSeptember 30,
			2015				2014
Liquids transportation volumes (Bbls/d)			442,683				352,990
NGL fractionation volumes (Bbls/d)			236,874				226,847
Revenues		$	854			$	1,196
Cost of products sold			614				994
Gross margin			240				202
Unrealized gains on commodity risk management activities			(4	)			(2	)
Operating expenses, excluding non-cash compensation expense			(40	)			(33	)
Selling, general and administrative expenses, excluding non-cash compensation expense			(4	)			(6	)
Adjusted EBITDA related to unconsolidated affiliates			—				2
Segment Adjusted EBITDA		$	192			$	163

NGL transportation volumes increased due to an increase in volumes transported on our Lone Star Gateway pipeline system of 63,000 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 37,000 Bbls/d during the three months ended September 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 EndedSeptember 30,
		2015					2014
Transportation margin		$	105			$	84
Processing and fractionation margin			77				75
Storage margin			41				36
Other margin			17				7
Total gross margin		$	240			$	202

Transportation margin increased $22 million primarily due to higher volumes transported out of west Texas on our Lone Star Gateway pipeline system, as noted in the volume discussion above. The commissioning of our crude transportation pipeline in south Texas also contributed an additional $2 million to the increase.

Processing and fractionation margin increased $16 million due to the commissioning of the Mariner South LPG export project during February 2015 and was partially offset by decreases in processing and fractionation margin of $8 million and $6 million due to lower prices at our Lone Star fractionators and our off-gas fractionator as Geismar, Louisiana, respectively.

Storage margin reflected increases of approximately $6 million due to increased demand for leased storage capacity as a result of favorable market conditions. These increases in fee based storage margin were partially offset by a decrease of $2 million from lower non fee-based storage activities, including blending activities, and lower financial gains recognized on the withdrawal of inventory from our storage facilities.

Other margin decreased primarily due to the withdrawal and sale of physical storage volumes, primarily propanes and butanes.

Segment Adjusted EBITDA for the liquids transportation and services segment also reflected an increase in operating expenses for the three months ended September 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 EndedSeptember 30,
			2015				2014
Natural gas transported (MMBtu/d)			5,903,285				5,785,862
Natural gas sold (MMBtu/d)			19,171				18,697
Revenues		$	248			$	258
Operating expenses, excluding non-cash compensation, amortization and accretion expenses			(78	)			(81	)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses			(14	)			(16	)
Adjusted EBITDA related to unconsolidated affiliates			130				127
Segment Adjusted EBITDA		$	286			$	288
Distributions from unconsolidated affiliates		$	104			$	87

Transported volumes increased 111,582 MMBtu/d on the Tiger pipeline, primarily due to increased deliveries to pipelines supporting the upper Midwest due to favorable market conditions and 77,639 MMBtu/d on the Transwestern pipeline due to increased customer demand in the Texas intrastate market. These increases were partially offset by a decrease of 73,900 MMBtu/d on the Trunkline pipeline as a result of lower customer demand due to lower price spreads and a managed contract roll off to facilitate the transfer of one of the pipelines at Trunkline that was taken out of service in advance of being repurposed from natural gas service to crude oil service.

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 and a managed contract roll off to facilitate the transfer of one of the 30” pipelines at Trunkline that was taken out of service in advance of being repurposed from natural gas to crude oil service.

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 EndedSeptember 30,
			2015				2014
Natural gas transported (MMBtu/d)			8,308,105				8,799,708
Revenues		$	592			$	601
Cost of products sold			428				438
Gross margin			164				163
Unrealized (gains) losses on commodity risk management activities			(4	)			1
Operating expenses, excluding non-cash compensation expense			(43	)			(46	)
Selling, general and administrative expenses, excluding non-cash compensation expense			(6	)			(9	)
Adjusted EBITDA related to unconsolidated affiliates			16				15
Segment Adjusted EBITDA		$	127			$	124
Distributions from unconsolidated affiliates		$	14			$	15

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 increased volumes related to significant new long-term transportation contracts.

Intrastate transportation and storage gross margin increased $7 million, despite a reduction in volume, 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 $2 million primarily due to the timing of the movement of market prices during the period. These increases were partially offset by a decrease of $6 million in retained fuel revenues primarily due to significantly lower market prices and $2 million from natural gas sales and other primarily due to a decrease in margin from the purchase and sale of natural gas on our system.

Investment in Sunoco Logistics
		Three Months EndedSeptember 30,
			2015				2014
Revenues		$	2,406			$	4,915
Cost of products sold			2,127				4,581
Gross margin			279				334
Unrealized gains on commodity risk management activities			(31	)			(21	)
Operating expenses, excluding non-cash compensation expense			(57	)			(55	)
Selling, general and administrative expenses, excluding non-cash compensation expense			(23	)			(26	)
Inventory valuation adjustments			103				—
Adjusted EBITDA related to unconsolidated affiliates			18				14
Segment Adjusted EBITDA		$	289			$	246
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 $35 million from terminal facilities, primarily attributable to increased operating results from Sunoco Logistics’ bulk marine terminals of $28 million, which benefited from NGL contributions at Sunoco Logistics’ Nederland terminal and Marcus Hook Industrial Complex, and approximately $5 million on the timing of recognition on committed crude oil throughput volumes under deficiency agreements. Improved contributions from Sunoco Logistics’ products and NGLs acquisition and marketing activities of $2 million and refined products terminals of $3 million also contributed to the increase;
• an increase of $37 million from products pipelines, primarily due to higher average pipeline revenue per barrel of $21 million and increased throughput volumes of $15 million primarily related to the Mariner NGL and Allegheny Access pipeline projects. Higher contributions from Sunoco Logistics’ joint venture interests of $3 million also contributed to the increase. These positive impacts were partially offset by higher operating expenses of $4 million largely attributable to growth projects; and
• an increase of $38 million from crude oil pipelines, primarily due to increased volumes of $12 million and higher average pipeline revenue per barrel of $25 million largely related to the Permian Express 2 pipeline that commenced operations in July 2015. Expansion projects placed into service in 2014 also contributed to the increase; partially offset by
• a decrease of $67 million from crude oil acquisition and marketing activities, primarily attributable to lower gross profit per barrel purchased, which was negatively impacted by narrowing crude oil differentials compared to the prior period.

Retail Marketing
		Three Months EndedSeptember 30,
			2015			2014
Motor fuel outlets and convenience stores, end of period:
Retail			438			1,210
Third-party wholesale			—			5,287
Total			438			6,497
Total motor fuel gallons sold (in millions):
Retail			390			424
Third-party wholesale			10			1,198
Total			400			1,622
Motor fuel gross profit (cents/gallon):
Retail			28.5			30.8
Third-party wholesale			15.1			9.0
Volume-weighted average for all gallons			28.2			14.7
Merchandise sales (in millions)		$	285			$	287
Retail merchandise margin %			30.2	%		28.8		%
Revenues		$	1,363			$	5,988
Cost of products sold			1,149			5,645
Gross margin			214			343
Unrealized (gains) losses on commodity risk management activities			(1	)		4
Operating expenses, excluding non-cash compensation expense			(149	)		(183		)
Selling, general and administrative expenses, excluding non-cash compensation expense			(8	)		(24		)
Inventory valuation adjustments			4			51
Adjusted EBITDA related to unconsolidated affiliates			135			—
Segment Adjusted EBITDA		$	195			$	191

Segment Adjusted EBITDA for the retail marketing segment increased due to the net impacts of the following:

• the favorable impact of recent acquisitions, including $81 million from the acquisition of Susser in August 2014 and $15 million from the acquisition of Aloha in December 2014; offset by
• a decrease of $67 million due to the deconsolidation of Sunoco LP as a result of the sale of Sunoco LP’s general partner interest and incentive distribution rights to ETE effective July 1, 2015; and
• a decrease of $25 million in margins as 2014 benefited from favorable regional market conditions for ethanol.

All Other
		Three Months EndedSeptember 30,
			2015				2014
Revenues		$	976			$	897
Cost of products sold			855				798
Gross margin			121				99
Unrealized (gains) losses on commodity risk management activities			(7	)			2
Operating expenses, excluding non-cash compensation expense			(26	)			(28	)
Selling, general and administrative expenses, excluding non-cash compensation expense			(35	)			(47	)
Adjusted EBITDA related to unconsolidated affiliates			47				23
Other			18				18
Eliminations			(25	)			(7	)
Segment Adjusted EBITDA		$	93			$	60
Distributions from unconsolidated affiliates		$	14			$	2

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 $24 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 $25 million.

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 September 30, 2015 were reflected as an offset to operating expenses of $6 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 $15 million in cash distribution from our ownership in PES.

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 nine months ended September 30, 2015:

		Growth			Maintenance			Total
Direct(1):
Midstream		$	1,563		$	67		$	1,630
Liquids transportation and services(2)			1,618			13			1,631
Interstate transportation and storage(2)			586			81			667
Intrastate transportation and storage			54			19			73
Retail marketing(3)			179			45			224
All other (including eliminations)			290			27			317
Total direct capital expenditures			4,290			252			4,542
Indirect(1):
Investment in Sunoco Logistics			1,419			49			1,468
Investment in Sunoco LP(4)			83			7			90
Total indirect capital expenditures			1,502			56			1,558
Total capital expenditures		$	5,792		$	308		$	6,100

(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 our wholly-owned retail marketing operations.
(4)		Investment in Sunoco LP includes capital expenditures for the period prior to deconsolidation on July 1, 2015.

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		$	2,100		$	2,200		$	90		$	110
Liquids transportation and services:
NGL			1,550			1,600			20			25
Crude(2)			700			750			—			—
Interstate transportation and storage(2)			700			750			130			140
Intrastate transportation and storage			125			150			30			35
Retail marketing(3)			210			240			50			60
All other (including eliminations)			320			360			25			35
Total direct capital expenditures			5,705			6,050			345			405
Indirect(1):
Investment in Sunoco Logistics			2,400			2,600			65			75
Investment in Sunoco LP(4)			80			85			5			10
Total indirect capital expenditures			2,480			2,685			70			85
Total projected capital expenditures		$	8,185		$	8,735		$	415		$	490

(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 our wholly-owned retail marketing operations.
(4)		Investment in Sunoco LP includes capital expenditures for the period prior to deconsolidation on July 1, 2015.

SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions)
(unaudited)
		Three Months EndedSeptember 30,
			2015				2014
Equity in earnings (losses) of unconsolidated affiliates:
Citrus		$	29			$	32
FEP			14				14
PES			39				14
MEP			10				10
HPC			9				10
AmeriGas			(2	)			(3	)
Sunoco, LLC			(13	)			—
Sunoco LP			117				—
Other			11				7
Total equity in earnings of unconsolidated affiliates		$	214			$	84
Adjusted EBITDA related to unconsolidated affiliates:
Citrus		$	88			$	84
FEP			19				19
PES			46				21
MEP			23				24
HPC			16				16
Sunoco, LLC			53				—
Sunoco LP			81				—
Other			24				20
Total Adjusted EBITDA related to unconsolidated affiliates		$	350			$	184
Distributions received from unconsolidated affiliates:
Citrus		$	65			$	51
FEP			19				19
PES			15				—
MEP			20				18
HPC			14				14
Other			21				14
Total distributions received from unconsolidated affiliates		$	154			$	116

View source version on businesswire.com: http://www.businesswire.com/news/home/20151104006887/en/

Investor Relations:
Energy Transfer
Brent Ratliff, 214-981-0700
or
Lyndsay Hannah, 214-840-5477
or
Media Relations:
Granado Communications Group
Vicki Granado, 214-599-8785
214-498-9272 (cell)

Source: Energy Transfer Partners

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