0001012569-14-000031.txt : 20140806 0001012569-14-000031.hdr.sgml : 20140806 20140806171134 ACCESSION NUMBER: 0001012569-14-000031 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20140806 ITEM INFORMATION: Results of Operations and Financial Condition ITEM INFORMATION: Financial Statements and Exhibits FILED AS OF DATE: 20140806 DATE AS OF CHANGE: 20140806 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Energy Transfer Partners, L.P. CENTRAL INDEX KEY: 0001012569 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 731493906 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-11727 FILM NUMBER: 141020810 BUSINESS ADDRESS: STREET 1: 3738 OAK LAWN AVENUE CITY: DALLAS STATE: TX ZIP: 75219 BUSINESS PHONE: 214-981-0700 MAIL ADDRESS: STREET 1: 3738 OAK LAWN AVENUE CITY: DALLAS STATE: TX ZIP: 75219 FORMER COMPANY: FORMER CONFORMED NAME: ENERGY TRANSFER PARTNERS LP DATE OF NAME CHANGE: 20040405 FORMER COMPANY: FORMER CONFORMED NAME: HERITAGE PROPANE PARTNERS L P DATE OF NAME CHANGE: 19960424 8-K 1 etpq214er8-k.htm 8-K ETP Q214 ER 8-K




UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
August 6, 2014
Date of Report (Date of earliest event reported)
 
ENERGY TRANSFER PARTNERS, L.P.
(Exact name of Registrant as specified in its charter)
 
 
 
Delaware
1-11727
73-1493906
(State or other jurisdiction of incorporation)
(Commission File Number)
(IRS Employer Identification No.)

3738 Oak Lawn Avenue,
Dallas, Texas 75219 
(Address of principal executive offices) (Zip Code)

(214) 981-0700
(Registrant’s telephone number, including area code)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
¨
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
¨
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
¨
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
¨
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))




Item 2.02. Results of Operations and Financial Condition.
On August 6, 2014, Energy Transfer Partners, L.P. (the “Partnership”) issued a press release announcing its financial and operating results for the second quarter ended June 30, 2014. A copy of this press release is furnished as Exhibit 99.1 to this report and is incorporated herein by reference.
In accordance with General Instruction B.2 of Form 8-K, the information set forth in this Item 2.02 and in the attached exhibit shall be deemed to be “furnished” and not be deemed to be “filed” for purposes of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits. In accordance with General Instruction B.2 of Form 8-K, the information set forth in the attached Exhibit 99.1 is deemed to be “furnished” and shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act.
Exhibit Number
 
Description of the Exhibit
99.1
 
Energy Transfer Partners, L.P. Press Release dated August 6, 2014




SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Energy Transfer Partners, L.P.
By:    Energy Transfer Partners GP, L.P., its general partner
By:     Energy Transfer Partners, L.L.C., its general partner

By:      /s/ Martin Salinas, Jr.
Martin Salinas, Jr.
Chief Financial Officer
Dated: August 6, 2014




EXHIBIT INDEX
Exhibit Number
 
Description of the Exhibit
99.1
 
Energy Transfer Partners, L.P. Press Release dated August 6, 2014


 EX-99.1 2 etper-06x30x2014xex991.htm ETP PRESS RELEASE DATED AUGUST 6, 2014 ETP ER-06-30-2014-Ex 99.1


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

1


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)

2


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


3


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


4


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


5


(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.

6


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.

7


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


8


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.

9


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.

10


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.

11


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.

12


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.

13


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.

14


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
)

15
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