Energy Transfer 8K Reports Second Quarter Results | SEC 6 Aug 14

ENERGY TRANSFER PARTNERS

REPORTS SECOND QUARTER RESULTS

Dallas – August 6, 2014 – Energy Transfer Partners, L.P. (NYSE: ETP) today reported its financial results for the quarter ended June 30, 2014. Adjusted EBITDA for Energy Transfer Partners, L.P. (“ETP” or the “Partnership”) for the three months ended June 30, 2014 totaled $1.17 billion, an increase of $100 million over the same period last year. Distributable Cash Flow attributable to the partners of ETP for the three months ended June 30, 2014 totaled $538 million, an increase of $55 million over the same period last year. Income from continuing operations for the three months ended June 30, 2014 was $539 million, an increase of $135 million over the same period last year.

Adjusted EBITDA for ETP for the six months ended June 30, 2014 totaled $2.38 billion, an increase of $350 million over the same period last year. Distributable Cash Flow attributable to the partners of ETP for the six months ended June 30, 2014 totaled $1.25 billion, an increase of $379 million over the same period last year. Income from continuing operations for the six months ended June 30, 2014 was $1.01 billion, an increase of $200 million over the same period last year.

In July, ETP announced that its Board of Directors approved an increase in its quarterly distribution to $0.955 per unit ($3.82 annualized) on ETP Common Units for the quarter ended June 30, 2014, representing an increase of $0.08 per Common Unit on an annualized basis compared to the first quarter of 2014. For the quarter ended June 30, 2014, ETP’s distribution coverage ratio was 1.10x.

ETP’s other recent key accomplishments include the following:

•

In June 2014, ETP announced that our Board of Directors approved the construction of a pipeline (“ET Rover”) to transport natural gas from the prolific Marcellus and Utica Shale areas to numerous market regions in the United States and Canada. To date, ETP has secured 2.95 billion cubic feet per day (“Bcf/d”) of binding, fee-based commitments under predominantly 20 year agreements, representing 91% of the 3.25 Bcf/d total design capacity, and is still evaluating additional bids that were received in the open season. The project is fully subscribed to the Dawn, Ontario hub at 1.3 Bcf/d, with the balance of capacity commitments delivered to interconnects with other pipelines in the Midwest. ETP has ordered the pipe for the project and expects the segment to the Midwest markets to be in-service by December 2016 and in-service to Dawn, Ontario by July 2017.

•

In June 2014, ETP also announced that our Board of Directors approved the construction of an approximately 1,100 mile pipeline to transport crude oil supply from strategic receipt points in the Bakken/Three Forks production area in North Dakota to Patoka, Illinois, where the pipeline will interconnect with ETP’s existing Trunkline Pipeline, which is being converted from natural gas service to crude oil transportation service. ETP currently expects to build the pipeline to a capacity as high as 570,000 barrels per day based on binding commitments received to date and ongoing discussions with a number of key potential shippers. The pipeline is expected to be in-service by December 2016.


•	In June 2014, ETP sold 8.5 million AmeriGas Partners, L.P. (“AmeriGas”) common units for net proceeds of $377 million, and sold an additional 1.2 million AmeriGas common units for net proceeds of $55 million in August 2014.


•	The Partnership continues to make progress toward the close of its recently announced acquisition of Susser Holdings Corporation (“Susser”) with Susser’s shareholders scheduled to vote on the acquisition at a meeting to be held on August 28, 2014.

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 8:30 a.m. Central Time, Thursday, August 7, 2014 to discuss the second quarter 2014 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 currently owns and operates approximately 35,000 miles of natural gas and natural gas liquids pipelines. ETP owns 100% of Panhandle Eastern Pipe Line Company, LP (the successor of Southern Union Company) and Sunoco, Inc., and a 70% interest in Lone Star NGL LLC, a joint venture that owns and operates natural gas liquids storage, fractionation and transportation assets. 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’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), approximately 30.8 million ETP common units, and approximately 50.2 million ETP Class H Units, which track 50% of the underlying economics of the general partner interest and the IDRs of Sunoco Logistics Partners L.P. (NYSE: SXL). ETE also owns the general partner and 100% of the IDRs of Regency Energy Partners LP (NYSE: RGP) and approximately 57.2 million RGP common units. The Energy Transfer family of companies owns 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), headquartered in Philadelphia, 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. SXL’s 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.

Contacts

Investor Relations:

Energy Transfer

Brent Ratliff

214-981-0700 (office)

Media Relations:

Vicki Granado

Granado Communications Group

214-599-8785 (office)

214-498-9272 (cell)

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(unaudited)



	June 30, 2014		December 31, 2013
ASSETS

CURRENT ASSETS	$	7,213	$	6,239

PROPERTY, PLANT AND EQUIPMENT, net	26,491		25,947

ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,850		4,436
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	—		17
GOODWILL	4,521		4,729
INTANGIBLE ASSETS, net	1,512		1,568
OTHER NON-CURRENT ASSETS, net	636		766
Total assets	$	44,223	$	43,702




LIABILITIES AND EQUITY

CURRENT LIABILITIES	$	7,515	$	6,067

LONG-TERM DEBT, less current maturities	16,220		16,451
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	69		54
DEFERRED INCOME TAXES	3,612		3,762
OTHER NON-CURRENT LIABILITIES	1,037		1,080

COMMITMENTS AND CONTINGENCIES
REDEEMABLE NONCONTROLLING INTERESTS	15		—

EQUITY:
Total partners’ capital	10,816		11,540
Noncontrolling interest	4,939		4,748
Total equity	15,755		16,288
Total liabilities and equity	$	44,223	$	43,702

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,
	2014			2013			2014			2013
REVENUES	$	13,029		$	11,551		$	25,261		$	22,405
COSTS AND EXPENSES:
Cost of products sold	11,636			10,229			22,502			19,823
Operating expenses	308			327			627			654
Depreciation and amortization	268			251			534			511
Selling, general and administrative	81			112			174			251
Total costs and expenses	12,293			10,919			23,837			21,239
OPERATING INCOME	736			632			1,424			1,166
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(217		)	(211		)	(436		)	(422		)
Equity in earnings of unconsolidated affiliates	57			37			136			109
Gain on sale of AmeriGas common units	93			—			163			—
Gains (losses) on interest rate derivatives	(46		)	39			(48		)	46
Other, net	(14		)	(4		)	(17		)	(1		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	609			493			1,222			898
Income tax expense from continuing operations	70			89			216			92
INCOME FROM CONTINUING OPERATIONS	539			404			1,006			806
Income from discontinued operations	42			9			66			31
NET INCOME	581			413			1,072			837
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	110			93			186			195
NET INCOME ATTRIBUTABLE TO PARTNERS	471			320			886			642
GENERAL PARTNER’S INTEREST IN NET INCOME	125			155			238			283
CLASS H UNITHOLDER’S INTEREST IN NET INCOME	51			—			100			—
COMMON UNITHOLDERS’ INTEREST IN NET INCOME	$	295		$	165		$	548		$	359
INCOME FROM CONTINUING OPERATIONS PER COMMON UNIT:
Basic	$	0.79		$	0.52		$	1.47		$	1.04
Diluted	$	0.79		$	0.52		$	1.47		$	1.04
NET INCOME PER COMMON UNIT:
Basic	$	0.92		$	0.53		$	1.67		$	1.08
Diluted	$	0.92		$	0.53		$	1.67		$	1.08
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
Basic	318.5			352.6			321.4			326.9
Diluted	319.5			353.8			322.4			328.1

SUPPLEMENTAL INFORMATION

(Tabular dollar amounts in millions)

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (a):
Net income	$	581		$	413		$	1,072		$	837
Interest expense, net of interest capitalized	217			211			436			422
Gain on sale of AmeriGas common units	(93		)	—			(163		)	—
Income tax expense from continuing operations	70			89			216			92
Depreciation and amortization	268			251			534			511
Non-cash compensation expense	13			10			27			24
(Gains) losses on interest rate derivatives	46			(39		)	48			(46		)
Unrealized (gains) losses on commodity risk management activities	1			(18		)	30			(37		)
LIFO valuation adjustment	(20		)	22			(34		)	(16		)
Equity in earnings of unconsolidated affiliates	(57		)	(37		)	(136		)	(109		)
Adjusted EBITDA related to unconsolidated affiliates	170			158			366			323
Other, net	(27		)	9			(21		)	24
Adjusted EBITDA (consolidated)	1,169			1,069			2,375			2,025
Adjusted EBITDA related to unconsolidated affiliates	(170		)	(158		)	(366		)	(323		)
Distributions from unconsolidated affiliates	92			102			173			197
Interest expense, net of interest capitalized	(217		)	(211		)	(436		)	(422		)
Amortization included in interest expense	(18		)	(24		)	(34		)	(47		)
Current income tax expense from continuing operations	(74		)	(24		)	(327		)	(19		)
Income tax expense related to the Trunkline LNG Transaction	6			—			277			—
Maintenance capital expenditures	(59		)	(121		)	(98		)	(172		)
Other, net	1			1			3			2
Distributable Cash Flow (consolidated)	730			634			1,567			1,241
Distributable Cash Flow attributable to Sunoco Logistics Partners L.P. (“Sunoco Logistics”) (100%)	(223		)	(184		)	(381		)	(379		)
Distributions from Sunoco Logistics to ETP	68			49			130			94
Distributions to ETE in respect of ETP Holdco Corporation (“Holdco”)	—			—			—			(50		)
Distributions to Regency Energy Partners LP (“Regency”) in respect of Lone Star (b)	(37		)	(16		)	(70		)	(39		)
Distributable Cash Flow attributable to the partners of ETP	$	538		$	483		$	1,246		$	867

Distributions to the partners of ETP:
Limited Partners:
Common Units held by public	$	282		$	246		$	550		$	487
Common Units held by ETE	29			89			58			178
Class H Units held by ETE Common Holdings, LLC (“ETE Holdings”) (c)	53			—			103			—
General Partner interests held by ETE	5			5			10			10
Incentive Distribution Rights (“IDRs”) held by ETE	178			183			346			363
IDR relinquishment related to previous transactions	(58		)	(55		)	(115		)	(86		)
Total distributions to be paid to the partners of ETP	$	489		$	468		$	952		$	952
Distributions credited to Holdco transactions (d)	—			—			—			(68		)
Net distributions to the partners of ETP	$	489		$	468		$	952		$	884
Distribution coverage ratio (e)	1.10x			1.03x			1.31x			0.98x

(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. Currently, Sunoco Logistics is the only such subsidiary.

•

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. Currently, Lone Star is such a subsidiary, as it is 30% owned by Regency, which is an unconsolidated affiliate. Prior to April 30, 2013, Holdco was also such a subsidiary, as ETE held a noncontrolling interest in Holdco.

The Partnership has presented Distributable Cash Flow in previous communications; however, the Partnership changed its calculation of this non-GAAP measure in recent periods and has revised amounts in prior periods to be consistent with the Partnership’s updated calculation of this measure.

Following is a summary of these changes:

•

Previously, the Partnership’s calculation of Distributable Cash Flow reflected the impact of amortization included in interest expense. Such amortization includes amortization of deferred financing costs, premiums or discounts on the issuance of long-term debt, and fair value adjustments on long-term debt assumed in acquisitions. The Partnership revised its calculation of Distributable Cash Flow to exclude the impact of such amortization. Management believes that this revised calculation is more useful and more accurately reflects the cash flows of the Partnership that are available for payment of distributions.

•

Previously, the Partnership’s calculation of Distributable Cash Flow reflected income tax expense from continuing operations, which included current and deferred income taxes. Current income tax expense represents the estimated taxes that will be payable or refundable for the current period, while deferred income taxes represent the estimated tax effects of tax carryforwards and the reversal of temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The Partnership revised its calculation of Distributable Cash Flow to reflect current income tax expense from continuing operations, rather than total income tax expense from continuing operations. Management believes that this revised calculation is more useful and more accurately reflects the cash flows of the Partnership that are available for payment of distributions.

Distributable Cash Flow previously reported for the three and six months ended June 30, 2013 has been revised to reflect these changes.


(b)	Cash distributions to Regency in respect of Lone Star consist of cash distributions paid in arrears on a quarterly basis. These amounts are in respect of the periods then ended, including payments made in arrears subsequent to period end.


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



	Three Months Ended			Six Months Ended
	June 30, 2014			June 30, 2014
General partner distributions and incentive distributions from Sunoco Logistics	$	43		$	82
	50.05		%	50.05		%
Share of Sunoco Logistics general partner and incentive distributions payable to Class H Unitholder	21			41
Incremental distributions payable to Class H Unitholder	32			62
Total Class H Unit distributions	$	53		$	103

Incremental distributions to the Class H Unitholder is based on the scheduled amounts through the first quarter of 2017, as set forth in Amendment No. 5 to ETP’s Amended and Restated Agreement of Limited Partnership.

(d)

For the six months ended June 30, 2013, net distributions to the partners of ETP excluded distributions paid in respect of the quarter ended March 31, 2013 on 49.5 million ETP Common Units issued to ETE as a portion of the consideration for ETP’s acquisition of ETE’s interest in Holdco on April 30, 2013. These newly issued ETP Common Units received cash distributions on May 15, 2013; however, such distributions were reduced from the total cash portion of the consideration paid to ETE in connection with the April 30, 2013 Holdco transaction.


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

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. 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 LIFO 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,
	2014		2013		Change
Segment Adjusted EBITDA:
Midstream	$	157	$	127	$	30
NGL transportation and services	141		77		64
Interstate transportation and storage	265		361		(96		)
Intrastate transportation and storage	110		112		(2		)
Investment in Sunoco Logistics	280		244		36
Retail marketing	136		97		39
All other	80		51		29
	$	1,169	$	1,069	$	100

Midstream



	Three Months Ended June 30,
	2014			2013			Change
Gathered volumes (MMBtu/d):
ETP legacy assets	2,851,414			2,531,076			320,338
Southern Union gathering and processing⁽¹⁾	—			529,327			(529,327		)
NGLs produced (Bbls/d):
ETP legacy assets	163,780			112,951			50,829
Southern Union gathering and processing⁽¹⁾	—			43,777			(43,777		)
Equity NGLs produced (Bbls/d):
ETP legacy assets	14,968			14,854			114
Southern Union gathering and processing⁽¹⁾	—			8,216			(8,216		)
Revenues	$	720		$	577		$	143
Cost of products sold	530			402			128
Gross margin	190			175			15
Unrealized gains on commodity risk management activities	—			(2		)	2
Operating expenses, excluding non-cash compensation expense	(29		)	(41		)	12
Selling, general and administrative expenses, excluding non-cash compensation expense	(4		)	(5		)	1
Segment Adjusted EBITDA	$	157		$	127		$	30


⁽¹⁾	Southern Union contributed its gathering and processing operations to Regency, resulting in the deconsolidation of those operations on April 30, 2013.

For the ETP legacy assets, the increases in gathered volumes, NGLs produced and equity NGLs produced during the three months ended June 30, 2014 compared to the same period last year were primarily due to increased production by our customers in the Eagle Ford Shale and a 400 MMcf/d increase in processing capacity. Volumes from Southern Union’s gathering and processing operations reflected the deconsolidation of those operations on April 30, 2013.

Segment Adjusted EBITDA for the midstream segment reflected an increase in gross margin as follows:



	Three Months Ended June 30,
	2014			2013			Change
Gathering and processing fee-based revenues	$	134		$	114		$	20
Non fee-based contracts and processing	59			64			(5		)
Other	(3		)	(3		)	—
Total gross margin	$	190		$	175		$	15

Midstream gross margin for the three months ended June 30, 2014 compared to the same period last year reflected increases in fee-based revenues of $20 million primarily due to increased production in the Eagle Ford Shale propelled mainly by a 400 MMcf/d increase in processing capacity from the same period last year. Excluding a $13 million reduction from the deconsolidation of Southern Union’s gathering and processing operations, non fee-based gross margin increased by $8 million due to operational efficiencies and a slightly better commodity price environment.

Segment Adjusted EBITDA for the midstream segment also was favorably impacted by lower operating expenses primarily due to the deconsolidation of Southern Union’s gathering and processing operations.

NGL Transportation and Services



	Three Months Ended June 30,
	2014			2013			Change
NGL transportation volumes (Bbls/d)	367,564			274,022			93,542
NGL fractionation volumes (Bbls/d)	191,255			98,915			92,340
Revenues	$	903		$	438		$	465
Cost of products sold	731			329			402
Gross margin	172			109			63
Unrealized gains on commodity risk management activities	—			(2		)	2
Operating expenses, excluding non-cash compensation expense	(29		)	(28		)	(1		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(4		)	(3		)	(1		)
Adjusted EBITDA related to unconsolidated affiliates	2			1			1
Segment Adjusted EBITDA	$	141		$	77		$	64

The increase in NGL transportation volumes for the three months ended June 30, 2014 compared to the same period last year reflected an increase of approximately 55,600 Bbls/d in volumes transported out of west Texas and the Eagle Ford Shale on our Lone Star NGL pipeline system. The remainder of the increase in volumes transported was primarily due to increases in NGL production from our Jackson processing plant and volumes destined for Mont Belvieu, Texas via our Justice pipeline. Average daily fractionated volumes increased for the three months ended June 30, 2014 compared to the same period last year due to the recent commissioning of our second 100,000 Bbls/d fractionator at Mont Belvieu, Texas in October 2013. These volumes include all physical and contractual volumes where we collected a fractionation fee.

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



	Three Months Ended June 30,
	2014		2013		Change
Transportation margin	$	69	$	45	$	24
Processing and fractionation margin	57		30		27
Storage margin	37		34		3
Other margin	9		—		9
Total gross margin	$	172	$	109	$	63

Transportation margin increased as a result of higher volumes transported from west Texas and the Eagle Ford Shale on our Lone Star pipeline system. This resulted in increased margin of $14 million for the three months ended June 30, 2014. An increase in NGL production, as discussed above, accounted for the remainder of the increase in transportation margin.

Processing and fractionation margin increased primarily due to higher volumes resulting from the startup of Lone Star’s second fractionator at Mont Belvieu, Texas in October 2013.

Other margin increased as a result of increased commercial optimization activities related to our fractionators, primarily due to the recent commissioning of the second fractionator at Mont Belvieu.

Interstate Transportation and Storage



	Three Months Ended June 30,
	2014			2013			Change
Natural gas transported (MMBtu/d)	5,594,099			6,204,788			(610,689		)
Natural gas sold (MMBtu/d)	15,733			16,795			(1,062		)
Revenues	$	249		$	357		$	(108	)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(67		)	(75		)	8
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(16		)	(19		)	3
Adjusted EBITDA related to unconsolidated affiliates	99			98			1
Segment Adjusted EBITDA	$	265		$	361		$	(96	)

Distributions from unconsolidated affiliates	$	58		$	55		$	3

For the three months ended June 30, 2014 compared to the same period last year, transported volumes decreased due to declines in supply on the Tiger pipeline, lower contracted capacity on the Trunkline pipeline, and lower contract utilization on the Transwestern pipeline.

Segment Adjusted EBITDA for the interstate transportation and storage segment decreased for the three months ended June 30, 2014 compared to the same period last year due to the deconsolidation of Trunkline LNG effective January 1, 2014, which reduced Segment Adjusted EBITDA by $47 million, and the recognition in the second quarter of 2013 of $52 million received in connection with the buyout of a customer contract.

Intrastate Transportation and Storage



	Three Months Ended June 30,
	2014			2013			Change
Natural gas transported (MMBtu/d)	9,069,215			9,654,524			(585,309		)
Revenues	$	712		$	623		$	89
Cost of products sold	551			447			104
Gross margin	161			176			(15		)
Unrealized gains on commodity risk management activities	(3		)	(12		)	9
Operating expenses, excluding non-cash compensation expense	(43		)	(47		)	4
Selling, general and administrative expenses, excluding non-cash compensation expense	(5		)	(5		)	—
Segment Adjusted EBITDA	$	110		$	112		$	(2	)

Transported volumes decreased for the three months ended June 30, 2014 compared to the same period last year primarily due to the reduction of volumes under certain long-term transportation contracts offset by increased volumes due to a more favorable pricing environment.

Segment Adjusted EBITDA for the intrastate transportation and storage segment decreased primarily due to a decrease in margin from lower transportation fees as a result of the reduction of volumes under certain long-term contracts. In addition, storage margin decreased due to a less favorable storage environment leading to a decline in the spreads between the spot and forward prices on natural gas we own in the Bammel storage facility.

Investment in Sunoco Logistics



	Three Months Ended June 30,
	2014			2013			Change
Revenues	$	4,821		$	4,311		$	510
Cost of products sold	4,517			4,023			494
Gross margin	304			288			16
Unrealized (gains) losses on commodity risk management activities	8			(1		)	9
Operating expenses, excluding non-cash compensation expense	(21		)	(25		)	4
Selling, general and administrative expenses, excluding non-cash compensation expense	(25		)	(29		)	4
Adjusted EBITDA related to unconsolidated affiliates	14			11			3
Segment Adjusted EBITDA	$	280		$	244		$	36

Distributions from unconsolidated affiliates	$	4		$	4		$	—

For the three months ended June 30, 2014 compared to the same period last year, Segment Adjusted EBITDA related to Sunoco Logistics increased due to the net impacts of the following:


•	An increase of $16 million from crude oil pipelines, primarily due to higher throughput;


•	An increase of $27 million from terminal facilities, primarily due to higher volumes and increased margins from refined products acquisition and marketing activities; and


•	An increase of $10 million from refined products pipelines, primarily due to operating results from Sunoco Logistics’ Mariner West project; partially offset by


•	A decrease of $17 million from crude oil acquisition and marketing activities, primarily due to lower crude margins, the impact from which was partially offset by $5 million from increased crude volumes resulting from higher market demand and expansion in the crude oil trucking fleet.

Retail Marketing



	Three Months Ended June 30,
	2014			2013			Change
Total retail gasoline outlets, end of period	5,152			4,974			178
Total company-operated outlets, end of period	568			440			128
Gasoline and diesel throughput per company-operated site (gallons/month)	197,824			204,320			(6,496		)
Revenues	$	5,568		$	5,291		$	277
Cost of products sold	5,260			5,087			173
Gross margin	308			204			104
Unrealized gains on commodity risk management activities	(1		)	—			(1		)
Operating expenses, excluding non-cash compensation expense	(124		)	(106		)	(18		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(28		)	(23		)	(5		)
LIFO valuation adjustment	(20		)	22			(42		)
Adjusted EBITDA related to unconsolidated affiliates	1			1			—
Other	—			(1		)	1
Segment Adjusted EBITDA	$	136		$	97		$	39

Segment Adjusted EBITDA for the retail marketing segment increased for the three months ended June 30, 2014 compared to the same period last year primarily due to recent acquisitions and a favorable impact from increased fuel margins.

All Other



	Three Months Ended June 30,
	2014			2013			Change
Revenues	$	721		$	485		$	236
Cost of products sold	710			466			244
Gross margin	11			19			(8		)
Unrealized gains on commodity risk management activities	(3		)	(1		)	(2		)
Operating expenses, excluding non-cash compensation expense	3			(5		)	8
Selling, general and administrative expenses, excluding non-cash compensation expense	(2		)	(20		)	18
Adjusted EBITDA related to discontinued operations	—			23			(23		)
Adjusted EBITDA related to unconsolidated affiliates	55			49			6
Other	19			(11		)	30
Elimination	(3		)	(3		)	—
Segment Adjusted EBITDA	$	80		$	51		$	29

Distributions from unconsolidated affiliates	$	28		$	40		$	(12	)

Amounts reflected in our all other segment primarily include:


•	our investment in AmeriGas;


•	our natural gas compression operations;


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


•	our investment in Regency related to the Regency common and Class F units received by Southern Union in exchange for the contribution of its interest in Southern Union Gathering Company, LLC to Regency on April 30, 2013; and


•	our natural gas marketing operations.

For the three months ended June 30, 2014 compared to the same period last year, Segment Adjusted EBITDA increased due to the net impact of the following:


•	an increase of $19 million in management fees, as further described below;


•	a favorable impact of approximately $10 million due to costs associated with certain Sunoco activities that were included in the all other Segment Adjusted EBITDA in the prior year;


•	favorable results from our commodity marketing business of $5 million;


•	an increase of $6 million in Adjusted EBITDA related to unconsolidated affiliates, primarily due to higher earnings from our investments in PES and Regency, including the impact of only recording a partial period of earnings from Regency beginning on April 30, 2013;


•	a refund of insurance premiums of $6 million included in the three months ended June 30, 2014;


•	Southern Union corporate expenses of $3 million that were no longer included in the all other segment subsequent to the merger of Southern Union, PEPL Holdings and Panhandle in January 2014; offset by


•	Adjusted EBITDA related to discontinued operations of $23 million in the prior period related to Southern Union’s local distribution operations that were sold in 2013.

In connection with the Trunkline LNG Transaction, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Trunkline LNG’s regasification facility and the development of a liquefaction project at Trunkline 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, 2014 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 decrease in cash distributions from unconsolidated affiliates was primarily due to a decrease in cash distributions from our ownership in AmeriGas of $13 million as a result of selling a portion of these interests in 2013 and 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) during the six months ended June 30, 2014:



	Growth		Maintenance			Total
Midstream	$	297	$	9		$	306
NGL transportation and services⁽¹⁾	175		8			183
Interstate transportation and storage	20		27			47
Intrastate transportation and storage	67		14			81
Investment in Sunoco Logistics	1,092		31			1,123
Retail marketing	34		18			52
All other (including eliminations)	5		(9		)	(4		)
Total capital expenditures	$	1,690	$	98		$	1,788


⁽¹⁾	Includes 100% of Lone Star’s capital expenditures, a portion of which are funded through capital contributions from Regency related to its 30% interest in Lone Star.

We currently expect capital expenditures (net of contributions in aid of construction costs) for the full year 2014 to be within the following ranges:



	Growth				Maintenance
	Low		High		Low		High
Midstream	$	600	$	650	$	10	$	15
NGL transportation and services⁽¹⁾	360		380		20		25
Interstate transportation and storage	80		100		100		110
Intrastate transportation and storage	150		160		25		30
Investment in Sunoco Logistics	1,900		2,100		65		75
Retail marketing	130		150		50		60
All other (including eliminations)	110		120		10		20
Total capital expenditures	$	3,330	$	3,660	$	280	$	335


⁽¹⁾	Includes 100% of Lone Star’s capital expenditures. We expect to receive capital contributions from Regency related to its 30% interest in Lone Star of between $85 million and $110 million.

SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES

(In millions)

(unaudited)



	Three Months Ended June 30,
	2014			2013			Change
Equity in earnings (losses) of unconsolidated affiliates:
AmeriGas	$	(8	)	$	(20	)	$	12
Citrus	26			24			2
FEP	13			14			(1		)
Regency	1			2			(1		)
PES	18			13			5
Other	7			4			3
Total equity in earnings of unconsolidated affiliates	$	57		$	37		$	20

Proportionate share of interest, depreciation, amortization, non-cash items and taxes:
AmeriGas	$	13		$	36		$	(23	)
Citrus	55			55			—
FEP	5			5			—
Regency	24			14			10
PES	7			5			2
Other	9			6			3
Total proportionate share of interest, depreciation, amortization, non-cash items and taxes	$	113		$	121		$	(8	)

Adjusted EBITDA related to unconsolidated affiliates:
AmeriGas	$	5		$	16		$	(11	)
Citrus	81			79			2
FEP	18			19			(1		)
Regency	25			16			9
PES	25			18			7
Other	16			10			6
Total Adjusted EBITDA related to unconsolidated affiliates	$	170		$	158		$	12

Distributions received from unconsolidated affiliates:
AmeriGas	$	11		$	24		$	(13	)
Citrus	41			39			2
FEP	16			16			—
Regency	15			15			—
Other	9			8			1
Total distributions received from unconsolidated affiliates	$	92		$	102		$	(10	)

Energy Transfer Inactive 8-KReports Second Quarter Results