Energy Transfer 8K Reports First Quarter Results | SEC 6 May 14

ENERGY TRANSFER PARTNERS

REPORTS FIRST QUARTER RESULTS

Dallas – May 6, 2014 – Energy Transfer Partners, L.P. (NYSE: ETP) today reported its financial results for the quarter ended March 31, 2014. Adjusted EBITDA for Energy Transfer Partners, L.P. (“ETP”) for the three months ended March 31, 2014 totaled $1.21 billion, an increase of $250 million over the same period last year. Distributable Cash Flow attributable to the partners of ETP for the three months ended March 31, 2014 totaled $629 million, an increase of $253 million over the same period last year. Income from continuing operations for the three months ended March 31, 2014 was $467 million, an increase of $65 million over the same period last year. Results for the first quarter of 2014 were favorably impacted by continued growth expansion of our asset platform, an increase in customer demand and an increase in commodity prices.

For the quarter ended March 31, 2014, ETP’s distribution coverage ratio was 1.36x, which represents a significant increase in distribution coverage over recent periods. In April, ETP announced that its Board of Directors approved an increase in its quarterly distribution to $0.935 per unit ($3.74 annualized) on ETP Common Units for the quarter ended March 31, 2014, representing an increase of $0.06 per Common Unit on an annualized basis compared to the fourth quarter of 2013.

ETP’s other key accomplishments to date in 2014 include the following:


•	In January 2014, ETP sold 9.2 million AmeriGas Partners, L.P. (“AmeriGas”) common units for net proceeds of $381 million.


•	In February 2014, ETP redeemed 18.7 million ETP Common Units in connection with the transfer to Energy Transfer Equity, L.P. (“ETE”) of Trunkline LNG Company, LLC (“Trunkline LNG”), the entity that owns a LNG regasification facility in Lake Charles, Louisiana (the “Trunkline LNG Transaction”).


•	On April 27, 2014, ETP entered into a definitive merger agreement whereby ETP plans to acquire Susser Holdings Corporation in a unit and cash transaction for total consideration valued at approximately $1.8 billion.

•

Trunkline LNG Export, LLC, an entity owned jointly by ETP and ETE, and Trunkline LNG filed an application with the Federal Energy Regulatory Commission (“FERC”), seeking authorization for the proposed new liquefaction facilities and modifications to Trunkline LNG’s existing terminal to facilitate the storage and subsequent export of LNG (the “Liquefaction Project”). In addition, Trunkline Gas Company, LLC, a subsidiary of ETP, filed a certificate application with the FERC for the modification and expansion of the Trunkline Gas Pipeline to accommodate volumes of inlet gas contracted for by BG Group in conjunction with the Liquefaction Project. The FERC filings represent the culmination of significant front-end engineering design efforts for the Liquefaction Project and pre-filing consultations with the FERC and other federal, state and local agencies that have been underway since mid-2012. Approval of these applications is requested from the FERC by April 1, 2015.

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, Wednesday, May 7, 2014 to discuss the first 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 33.5 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 26.3 million RGP common units. The Energy Transfer family of companies owns more than 61,000 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 and refined product pipeline, terminalling, and acquisition and marketing assets. 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 Partnerships’ Annual Reports on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. The Partnerships undertake 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)



	March 31, 2014		December 31, 2013
ASSETS

CURRENT ASSETS	$	7,069	$	6,239

PROPERTY, PLANT AND EQUIPMENT, net	25,578		25,947

ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,160		4,436
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	1		17
GOODWILL	4,507		4,729
INTANGIBLE ASSETS, net	1,502		1,568
OTHER NON-CURRENT ASSETS, net	772		766
Total assets	$	43,589	$	43,702




LIABILITIES AND EQUITY

CURRENT LIABILITIES	$	7,491	$	6,067

LONG-TERM DEBT, less current maturities	16,191		16,451
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	39		54
DEFERRED INCOME TAXES	3,599		3,762
OTHER NON-CURRENT LIABILITIES	1,053		1,080

COMMITMENTS AND CONTINGENCIES

EQUITY:
Total partners’ capital	10,438		11,540
Noncontrolling interest	4,778		4,748
Total equity	15,216		16,288
Total liabilities and equity	$	43,589	$	43,702

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit data)

(unaudited)



	Three Months Ended March 31,
	2014			2013
REVENUES	$	12,232		$	10,854
COSTS AND EXPENSES:
Cost of products sold	10,866			9,594
Operating expenses	319			327
Depreciation and amortization	266			260
Selling, general and administrative	93			139
Total costs and expenses	11,544			10,320
OPERATING INCOME	688			534
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(219		)	(211		)
Equity in earnings of unconsolidated affiliates	79			72
Gain on sale of AmeriGas common units	70			—
Gains (losses) on interest rate derivatives	(2		)	7
Other, net	(3		)	3
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	613			405
Income tax expense from continuing operations	146			3
INCOME FROM CONTINUING OPERATIONS	467			402
Income from discontinued operations	24			22
NET INCOME	491			424
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	76			102
NET INCOME ATTRIBUTABLE TO PARTNERS	415			322
GENERAL PARTNER’S INTEREST IN NET INCOME	113			128
CLASS H UNITHOLDER’S INTEREST IN NET INCOME	49			—
COMMON UNITHOLDERS’ INTEREST IN NET INCOME	$	253		$	194
INCOME FROM CONTINUING OPERATIONS PER COMMON UNIT:
Basic	$	0.69		$	0.60
Diluted	$	0.69		$	0.60
NET INCOME PER COMMON UNIT:
Basic	$	0.76		$	0.63
Diluted	$	0.76		$	0.63
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
Basic	324.5			300.8
Diluted	325.5			301.8

SUPPLEMENTAL INFORMATION

(Tabular dollar amounts in millions)

(unaudited)



	Three Months Ended March 31,
	2014			2013
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (a):
Net income	$	491		$	424
Interest expense, net of interest capitalized	219			211
Gain on sale of AmeriGas common units	(70		)	—
Income tax expense from continuing operations	146			3
Depreciation and amortization	266			260
Non-cash compensation expense	14			14
(Gains) losses on interest rate derivatives	2			(7		)
Unrealized (gains) losses on commodity risk management activities	29			(19		)
LIFO valuation adjustment	(14		)	(38		)
Equity in earnings of unconsolidated affiliates	(79		)	(72		)
Adjusted EBITDA related to unconsolidated affiliates	196			165
Other, net	6			15
Adjusted EBITDA (consolidated)	1,206			956
Adjusted EBITDA related to unconsolidated affiliates	(196		)	(165		)
Distributions from unconsolidated affiliates	81			95
Interest expense, net of interest capitalized	(219		)	(211		)
Amortization included in interest expense	(16		)	(23		)
Income tax expense from continuing operations	(146		)	(3		)
Income tax expense related to the Trunkline LNG Transaction	85			—
Maintenance capital expenditures	(39		)	(51		)
Other, net	2			1
Distributable Cash Flow (consolidated)	758			599
Distributable Cash Flow attributable to Sunoco Logistics Partners L.P. (“Sunoco Logistics”) (100%)	(158		)	(195		)
Distributions from Sunoco Logistics to ETP	62			45
Distributions to ETE in respect of ETP Holdco Corporation (“Holdco”)	—			(50		)
Distributions to Regency Energy Partners LP (“Regency”) in respect of Lone Star (b)	(33		)	(23		)
Distributable Cash Flow attributable to the partners of ETP	$	629		$	376

Distributions to the partners of ETP:
Limited Partners:
Common Units held by public	$	268		$	241
Common Units held by ETE	29			45
Class H Units held by ETE Common Holdings, LLC (“ETE Holdings”) (c)	50			—
General Partner interests held by ETE	5			5
Incentive Distribution Rights (“IDRs”) held by ETE	168			156
IDR relinquishment related to previous transactions	(57		)	(31		)
Total distributions to be paid to the partners of ETP	$	463		$	416
Distribution coverage ratio (d)	1.36x			0.90x

(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 and unrealized gains and losses on commodity risk management activities. 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 the quarter ended December 31, 2013. 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. Beginning with the quarter ended December 31, 2013, the Partnership’s calculation

of Distributable Cash Flow excludes the impact of such amortization. Management believes that this revised calculation is more useful to and more accurately reflects the cash flows of the Partnership that are available for payment of distributions.


(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 months ended March 31, 2014 were calculated as follows:



General partner distributions and incentive distributions from Sunoco Logistics	$	39
	50.05		%
Share of Sunoco Logistics general partner and incentive distributions payable to Class H Unitholder	20
Incremental distributions payable to Class H Unitholder	30
Total Class H Unit distributions	$	50

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)	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 March 31,
	2014		2013		Change
Segment Adjusted EBITDA:
Midstream	$	126	$	87	$	39
NGL transportation and services	128		80		48
Interstate transportation and storage	300		297		3
Intrastate transportation and storage	177		132		45
Investment in Sunoco Logistics	208		236		(28		)
Retail marketing	109		37		72
All other	158		87		71
	$	1,206	$	956	$	250

Midstream



	Three Months Ended March 31,
	2014			2013			Change
Gathered volumes (MMBtu/d):
ETP legacy assets	2,558,851			2,334,283			224,568
Southern Union gathering and processing⁽¹⁾	—			480,339			(480,339		)
NGLs produced (Bbls/d):
ETP legacy assets	136,818			96,775			40,043
Southern Union gathering and processing⁽¹⁾	—			39,681			(39,681		)
Equity NGLs produced (Bbls/d):
ETP legacy assets	12,106			9,744			2,362
Southern Union gathering and processing⁽¹⁾	—			7,206			(7,206		)
Revenues	$	653		$	600		$	53
Cost of products sold	493			437			56
Gross margin	160			163			(3		)
Operating expenses, excluding non-cash compensation expense	(28		)	(57		)	29
Selling, general and administrative expenses, excluding non-cash compensation expense	(6		)	(19		)	13
Segment Adjusted EBITDA	$	126		$	87		$	39


⁽¹⁾	On April 30, 2013, Southern Union contributed its gathering and processing operations to Regency and, as a result, Southern Union’s gathering and processing operations were deconsolidated 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 March 31, 2014 compared to the same period last year were primarily due to increased capacity from assets recently placed in service and increased production by our customers in the Eagle Ford Shale area. The increase in gathered volumes for ETP’s legacy assets was partially offset by lower volumes on our Louisiana system due to wellhead shut-ins as a result of the unseasonably cold winter.

Segment Adjusted EBITDA for midstream for the three months ended March 31, 2014 was favorably impacted by increased capacity from assets recently placed in service and increased production in the Eagle Ford Shale, which resulted in a $34 million increase in fee-based revenues. This increase was offset by the deconsolidation of Southern Union’s gathering and processing operations, which also was the primary driver for the decreases in operating expenses and selling, general and administrative expenses.

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



	Three Months Ended March 31,
	2014		2013			Change
Gathering and processing fee-based revenues	$	123	$	97		$	26
Non fee-based contracts and processing	37		67			(30		)
Other	—		(1		)	1
Total gross margin	$	160	$	163		$	(3	)

Midstream gross margin for the three months ended March 31, 2014 compared to the same period last year reflected increases in fee-based revenues of $34 million due to increased production in the Eagle Ford Shale propelled mainly by an 800 MMcf/d increase in processing capacity from the same period last year. Lower volumes on our Louisiana assets and the deconsolidation of Southern Union’s gathering and processing operations had an unfavorable impact of $4 million and $5 million, respectively. Non fee-based gross margin decreased primarily due to the deconsolidation of Southern Union’s gathering and processing operations.

NGL Transportation and Services



	Three Months Ended March 31,
	2014			2013			Change
NGL transportation volumes (Bbls/d)	417,831			274,030			143,801
NGL fractionation volumes (Bbls/d)	156,898			86,703			70,195
Revenues	$	830		$	365		$	465
Cost of products sold	671			257			414
Gross margin	159			108			51
Unrealized losses on commodity risk management activities	1			—			1
Operating expenses, excluding non-cash compensation expense	(28		)	(22		)	(6		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(5		)	(7		)	2
Adjusted EBITDA related to unconsolidated affiliates	1			1			—
Segment Adjusted EBITDA	$	128		$	80		$	48

For the three months ended March 31, 2014 compared to the same period last year, NGL transportation volumes increased on our wholly-owned and joint venture NGL pipelines primarily due to increased volumes originating from West Texas being transported on our Gateway pipeline and an increase in NGL production from the 800 MMcf/d of processing capacity added in our midstream segment over the last twelve months. Average daily fractionated volumes increased due to the recent commissioning of two 100,000 Bbls/d fractionators at Mont Belvieu, Texas. These volumes include all physical and contractual volumes where we collected a fractionation fee.

Segment Adjusted EBITDA for the NGL transportation and services segment increased for the three months ended March 31, 2014 compared to the same period last year primarily due to higher gross margin, as discussed below, partially offset by higher operating expenses from new assets placed in service.

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



	Three Months Ended March 31,
	2014		2013		Change
Transportation margin	$	59	$	41	$	18
Processing and fractionation margin	49		34		15
Storage margin	40		32		8
Other margin	11		1		10
Total gross margin	$	159	$	108	$	51

Transportation margin increased as a result of higher volumes transported from West Texas on our Gateway pipeline. This resulted in increased margin of $8 million for the three months ended March 31, 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 primarily due to higher NGL prices as a result of weather conditions for the three months ended March 31, 2014.

Interstate Transportation and Storage



	Three Months Ended March 31,
	2014			2013			Change
Natural gas transported (MMBtu/d)	7,315,078			7,033,804			281,274
Natural gas sold (MMBtu/d)	15,783			16,768			(985		)
Revenues	$	298		$	324		$	(26	)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(71		)	(78		)	7
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(14		)	(29		)	15
Adjusted EBITDA related to unconsolidated affiliates	87			80			7
Segment Adjusted EBITDA	$	300		$	297		$	3

Distributions from unconsolidated affiliates	$	50		$	41		$	9

Segment Adjusted EBITDA for the interstate transportation and storage segment increased for the three months ended March 31, 2014 compared to the same period last year due to increased revenues from our pipelines offset by the impact of the deconsolidation of Trunkline LNG. We experienced an increase in parking and short-term firm revenues as well as an increase in usage revenues as a result of higher customer demand driven by colder weather. These favorable variances were offset by the deconsolidation of Trunkline LNG effective January 1, 2014. Revenues for Trunkline LNG were $53 million for the three months ended March 31, 2013. Operating expenses decreased as a result of lower utility costs on the Transwestern pipeline and the deconsolidation of Trunkline LNG effective January 1, 2014. Additionally, selling, general and administrative expenses decreased for the three months ended March 31, 2014 compared to the same period last year primarily due to decreases in employee-related costs of $7 million, professional fees of $4 million and the deconsolidation of Trunkline LNG.

Intrastate Transportation and Storage



	Three Months Ended March 31,
	2014			2013			Change
Natural gas transported (MMBtu/d)	9,399,267			9,733,480			(334,213		)
Revenues	$	934		$	684		$	250
Cost of products sold	734			490			244
Gross margin	200			194			6
Unrealized (gains) losses on commodity risk management activities	27			(12		)	39
Operating expenses, excluding non-cash compensation expense	(42		)	(42		)	—
Selling, general and administrative expenses, excluding non-cash compensation expense	(7		)	(8		)	1
Adjusted EBITDA related to unconsolidated affiliates	(1		)	—			(1		)
Segment Adjusted EBITDA	$	177		$	132		$	45

Segment Adjusted EBITDA for the intrastate transportation and storage segment increased primarily due an increase in margin realized from withdrawing natural gas from our Bammel storage facility, net of non-cash adjustments, and an increase in retained fuel revenues due to higher average natural gas spot prices.

Investment in Sunoco Logistics



	Three Months Ended March 31,
	2014			2013			Change
Revenues	$	4,477		$	3,512		$	965
Cost of products sold	4,210			3,224			986
Gross margin	267			288			(21		)
Unrealized gains on commodity risk management activities	(1		)	(3		)	2
Operating expenses, excluding non-cash compensation expense	(32		)	(26		)	(6		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(34		)	(30		)	(4		)
Adjusted EBITDA related to unconsolidated affiliates	8			7			1
Segment Adjusted EBITDA	$	208		$	236		$	(28	)

Distributions from unconsolidated affiliates	$	2		$	3		$	(1	)

Segment Adjusted EBITDA for the investment in Sunoco Logistics segment decreased due to lower crude oil margins in Sunoco Logistics’ crude oil acquisition and marketing operations of $100 million driven by contracted crude differentials compared to the prior year. This decrease was partially offset by an increase in Sunoco Logistics’ crude oil pipeline operations of $32 million primarily attributable to expansion projects supporting the demand for West Texas crude oil. Also offsetting the decrease were higher refined products acquisition and marketing volumes and differentials, as well as increased throughput volumes for Sunoco Logistics’ terminal facilities operations. Sunoco Logistics’ Mariner West natural gas liquids pipeline project, which commenced operations in the fourth quarter of 2013, also contributed to the offset.

Sunoco Logistics’ operating expenses increased for the three months ended March 31, 2014 compared to the same period last year primarily due to increased utility expenses associated with higher throughput volumes and increased environmental remediation costs.

Retail Marketing



	Three Months Ended March 31,
	2014			2013			Change
Total retail gasoline outlets, end of period	5,122			4,979			143
Total company-operated outlets, end of period	529			439			90
Gasoline and diesel throughput per company-operated site (gallons/month)	178,448			187,000			(8,552		)
Revenues	$	5,011		$	5,222		$	(211	)
Cost of products sold	4,756			5,036			(280		)
Gross margin	255			186			69
Unrealized losses on commodity risk management activities	3			—			3
Operating expenses, excluding non-cash compensation expense	(116		)	(98		)	(18		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(20		)	(15		)	(5		)
LIFO valuation adjustment	(14		)	(38		)	24
Adjusted EBITDA related to unconsolidated affiliates	1			2			(1		)
Segment Adjusted EBITDA	$	109		$	37		$	72

Segment Adjusted EBITDA for the retail marketing segment increased for the three months ended March 31, 2014 compared to the same period last year primarily due to favorable supply, wholesale and trading margin of $31 million and additional margin of $26 million as a result of the Mid-Atlantic Convenience Stores (“MACS”) acquisition in October 2013. Additionally, favorable New York Harbor ethanol prices resulted in increased margin of $22 million and a tight supply resulted in favorable retail distillate

margin of $11 million. The favorable impact of these variances on margin was partially offset by an increase in operating expenses of $18 million primarily driven by the MACS acquisition in October 2013.

All Other



	Three Months Ended March 31,
	2014			2013			Change
Revenues	$	591		$	631		$	(40	)
Cost of products sold	564			625			(61		)
Gross margin	27			6			21
Unrealized gains on commodity risk management activities	(1		)	(4		)	3
Operating expenses, excluding non-cash compensation expense	(5		)	(6		)	1
Selling, general and administrative expenses, excluding non-cash compensation expense	(11		)	(19		)	8
Adjusted EBITDA related to discontinued operations	27			40			(13		)
Adjusted EBITDA related to unconsolidated affiliates	102			76			26
Other	19			—			19
Elimination	—			(6		)	6
Segment Adjusted EBITDA	$	158		$	87		$	71

Distributions from unconsolidated affiliates	$	26		$	50		$	(24	)

Amounts reflected above 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.

The increase in gross margin for the three months ended March 31, 2014 compared to the same period last year was primarily due to favorable results from our commodity marketing businesses.

Selling, general and administrative expenses include corporate expenses as well as amounts related to natural gas compression operations and natural gas marketing operations.

Adjusted EBITDA related to discontinued operations for the three months ended March 31, 2014 related to a marketing business that was sold effective April 1, 2014. Amounts for the three months ended March 31, 2013 related to the operations of Southern Union's local distribution operations.

Adjusted EBITDA related to unconsolidated affiliates increased for the three months ended March 31, 2014 primarily from our investment in Regency, which was included beginning in April 2013. Additional information related to unconsolidated affiliates is provided below in “Supplemental Information on Unconsolidated Affiliates.”

“Other” includes certain management fees from ETE. 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 are reflected as an offset to operating expenses of $6 million and selling, general and administrative expenses of $13 million in the consolidated statements of operations.

The decrease in cash distributions from unconsolidated affiliates was primarily due to no cash distributions from our ownership in PES in the first quarter of 2014 compared to $25 million in cash distributions in the first quarter of 2013 and a decrease in cash distributions from our ownership in AmeriGas of $13 million as a result of selling a portion of these interests in July 2013 and

January 2014. Partially offsetting these decreases was cash distributions from our investment in Regency of $15 million for the three months ended March 31, 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 three months ended March 31, 2014:



	Growth		Maintenance			Total
Midstream	$	130	$	3		$	133
NGL transportation and services⁽¹⁾	86		2			88
Interstate transportation and storage	10		(2		)	8
Intrastate transportation and storage	11		5			16
Investment in Sunoco Logistics	465		18			483
Retail marketing	12		6			18
All other (including eliminations)	4		7			11
Total capital expenditures	$	718	$	39		$	757


⁽¹⁾	We received $27 million in capital contributions from Regency related to their 30% share of Lone Star.

We currently expect capital expenditures for the full year 2014 to be within the following ranges:



	Growth				Maintenance
	Low		High		Low		High
Midstream	$	400	$	420	$	10	$	15
NGL transportation and services⁽¹⁾	290		310		20		25
Interstate transportation and storage	50		60		110		120
Intrastate transportation and storage	150		160		20		25
Investment in Sunoco Logistics	1,650		1,750		65		75
Retail marketing	125		155		50		60
All other (including eliminations)	80		90		10		20
Total capital expenditures	$	2,745	$	2,945	$	285	$	340


⁽¹⁾	We expect to receive capital contributions from Regency related to their 30% share of Lone Star of between $85 million and $110 million.

SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES

(In millions)

(unaudited)



	Three Months Ended March 31,
	2014			2013			Change
Equity in earnings (losses) of unconsolidated affiliates:
AmeriGas	$	34		$	63		$	(29	)
Citrus	18			14			4
FEP	14			13			1
Regency	(7		)	—			(7		)
PES	17			(22		)	39
Other	3			4			(1		)
Total equity in earnings of unconsolidated affiliates	$	79		$	72		$	7

Proportionate share of interest, depreciation, amortization, non-cash items and taxes:
AmeriGas	$	17		$	34		$	(17	)
Citrus	50			48			2
FEP	5			5			—
Regency	34			—			34
PES	6			1			5
Other	5			5			—
Total proportionate share of interest, depreciation, amortization, non-cash items and taxes	$	117		$	93		$	24

Adjusted EBITDA related to unconsolidated affiliates:
AmeriGas	$	51		$	97		$	(46	)
Citrus	68			62			6
FEP	19			18			1
Regency	27			—			27
PES	23			(21		)	44
Other	8			9			(1		)
Total Adjusted EBITDA related to unconsolidated affiliates	$	196		$	165		$	31

Distributions received from unconsolidated affiliates:
AmeriGas	$	11		$	24		$	(13	)
Citrus	34			24			10
FEP	16			17			(1		)
Regency	15			—			15
PES	—			25			(25		)
Other	5			5			—
Total distributions received from unconsolidated affiliates	$	81		$	95		$	(14	)

Energy Transfer Inactive 8-KReports First Quarter Results