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PEPL 2.18.15 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

Date of Report (Date of earliest event reported): February 18, 2015


PANHANDLE EASTERN PIPE LINE COMPANY, LP
(Exact name of registrant as specified in its charter)



Delaware
1-2921
44-0382470
(State or other jurisdiction of incorporation)
(Commission File Number)
(I.R.S. Employer
Identification No.)

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

Registrant’s telephone number, including area code: (214) 981-0700


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 7.01. Regulation FD Disclosure.

On February 18, 2015, Energy Transfer Partners, L.P. (“ETP”), the entity which owns 100% of ETP Holdco Corporation, which indirectly owns 100% of the equity interests of Panhandle Eastern Pipe Line Company, LP (the “Company”), issued a press release after market close announcing its financial and operating results, including certain financial results of the Company, for the fourth quarter ended December 31, 2014. A copy of ETP’s 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 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.


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 February 18, 2015




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 thereunto duly authorized.

 
 
 
 
PANHANDLE EASTERN PIPE LINE COMPANY, LP
 
(Registrant)
Date: February 18, 2015
By:
/s/ Martin Salinas, Jr.
 
Martin Salinas, Jr.
 
Chief Financial Officer (duly authorized to sign on behalf of the registrant)




EXHIBIT INDEX

Exhibit Number
Description of the Exhibit
99.1
Energy Transfer Partners, L.P. Press Release dated February 18, 2015



ETP-12.31.2014-Ex 99.1


ENERGY TRANSFER PARTNERS
REPORTS FOURTH QUARTER RESULTS
Dallas – February 18, 2015 – Energy Transfer Partners, L.P. (NYSE: ETP) today reported its financial results for the quarter ended December 31, 2014. Adjusted EBITDA for Energy Transfer Partners, L.P. (“ETP” or the “Partnership”) for the three months ended December 31, 2014 totaled $1.28 billion, an increase of $296 million over the same period last year. Distributable Cash Flow attributable to the partners of ETP for the three months ended December 31, 2014 totaled $623 million, an increase of $141 million over the same period last year. Distributable Cash Flow per Common Unit was $1.19 for the three months ended December 31, 2014, an overall increase of 34% from the same period last year. Income from continuing operations for the three months ended December 31, 2014 was $36 million, an increase of $498 million over the same period last year, including the impact of a $689 million non-cash goodwill impairment in 2013.
In January 2015, ETP announced that its Board of Directors approved an increase in its quarterly distribution to $0.9950 per unit ($3.98 annualized) on ETP Common Units for the quarter ended December 31, 2014, representing an increase of $0.30 per Common Unit on an annualized basis, or 8.2%, compared to the fourth quarter of 2013. For the quarter ended December 31, 2014, ETP’s distribution coverage ratio was 1.12x.
ETP’s other recent key accomplishments include the following:
•
In January 2015, ETP and Regency Energy Partners LP (“Regency”) announced their entry into a definitive merger agreement pursuant to which ETP will acquire Regency. Under the terms of the definitive merger agreement, holders of Regency common units will receive 0.4066 ETP Common Units for each Regency common unit. Regency unitholders will also receive at closing an additional $0.32 per common unit in the form of ETP Common Units (based on the price for ETP Common Units prior to the merger closing). The transaction is expected to close in the second quarter of 2015.
•
In January 2015, ETP’s affiliate Rover Pipeline LLC (“Rover”) signed a contract with Vector Pipeline (“Vector”) and its affiliates for firm transportation capacity to deliver gas to markets in Michigan and the Union Gas Dawn Hub in Ontario, Canada as part of the Rover pipeline project. The capacity arrangement with Vector eliminates the need to build 110 miles of pipeline through Michigan and will eliminate the Canadian construction entirely.
•
As a result of AE–Midco Rover, LLC’s (“AE–Midco”) recent exercise of its option to increase its equity ownership interest in Rover, AE–Midco (and an affiliate of AE–Midco) will own 35% of Rover and ETP will own 65%.
•
In December 2014, ETP and Energy Transfer Equity, L.P. (“ETE”) announced the final terms of a transaction, whereby ETE will transfer 30.8 million ETP Common Units, ETE’s 45% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline (collectively, the “Bakken pipeline project”), and $879 million in cash (less amounts funded prior to closing by ETE for capital expenditures for the Bakken pipeline project) in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics. In addition, ETE and ETP agreed to reduce the IDR subsidies that ETE previously agreed to provide to ETP, with such reductions occurring in 2015 and 2016. This transaction is expected to close in March 2015.
•
In November 2014, ETP and Regency announced that Lone Star NGL LLC (“Lone Star”) will construct a 533 mile, 24- and 30-inch NGL pipeline from the Permian Basin to Mont Belvieu, Texas and convert Lone Star’s existing West Texas 12-inch NGL pipeline into crude oil/condensate service. The new pipeline and conversion projects, estimated to cost between $1.5 billion and $1.8 billion, are expected to be operational by the third quarter of 2016 and the first quarter of 2017, respectively.
•
As of December 31, 2014, ETP’s $2.5 billion revolving credit facility had $570 million of outstanding borrowings, and its leverage ratio, as defined by the credit agreement, was 3.87x. In February 2015, ETP amended its revolving credit facility to increase the capacity to $3.75 billion.
An analysis of ETP’s segment results and other supplementary data is provided after the financial tables shown below. ETP has scheduled a conference call for 8:00 a.m. Central Time, Thursday, February 19, 2015 to discuss the fourth 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.

1


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 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 owns 100% of Sunoco, Inc. and 100% of Susser Holdings Corporation. Additionally, ETP owns the general partner, 100% of the incentive distribution rights and approximately 43% of the limited partner interests in Sunoco LP (formerly Susser Petroleum Partners LP) (NYSE: SUN), a wholesale fuel distributor and convenience store operator. ETP’s general partner is owned by ETE. For more information, visit the Energy Transfer Partners, L.P. web site at www.energytransfer.com.
Energy Transfer Equity, L.P. (NYSE: ETE) is a master limited partnership which owns the general partner and 100% of the incentive distribution rights (IDRs) of Energy Transfer Partners, L.P. (NYSE: ETP), 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. On a consolidated basis, ETE’s family of companies own and operate 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.
Sunoco LP (NYSE: SUN) is a master limited partnership that primarily distributes motor fuel to convenience stores, independent dealers, commercial customers and distributors. Sunoco LP also operates more than 150 convenience stores and retail fuel sites. Sunoco LP’s general partner is owned by Energy Transfer Partners, L.P. (NYSE: ETP). For more information, visit the Sunoco LP web site at www.sunocolp.com.
Forward-Looking Statements
This press release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results are discussed in the Partnerships’ 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)
 
December 31,
 
2014
 
2013
ASSETS
 
 
 
 
 
 
 
CURRENT ASSETS
$
5,439

 
$
6,239

 
 
 
 
PROPERTY, PLANT AND EQUIPMENT, net
29,743

 
25,947

 
 
 
 
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES
3,840

 
4,436

NON-CURRENT PRICE RISK MANAGEMENT ASSETS
—

 
17

GOODWILL
6,419

 
4,729

INTANGIBLE ASSETS, net
2,087

 
1,568

OTHER NON-CURRENT ASSETS, net
693

 
766

Total assets
$
48,221

 
$
43,702

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
CURRENT LIABILITIES
$
6,040

 
$
6,067

 
 
 
 
LONG-TERM DEBT, less current maturities
18,332

 
16,451

NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES
138

 
54

DEFERRED INCOME TAXES
4,226

 
3,762

OTHER NON-CURRENT LIABILITIES
1,206

 
1,080

 
 
 
 
COMMITMENTS AND CONTINGENCIES
 
 
 
REDEEMABLE NONCONTROLLING INTERESTS
15

 
—

 
 
 
 
EQUITY:
 
 
 
Total partners’ capital
12,070

 
11,540

Noncontrolling interest
6,194

 
4,748

Total equity
18,264

 
16,288

Total liabilities and equity
$
48,221

 
$
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 December 31,
 
Years Ended December 31,
 
2014
 
2013
 
2014
 
2013
REVENUES
$
12,279

 
$
12,032

 
$
51,158

 
$
46,339

COSTS AND EXPENSES:
 
 
 
 
 
 
 
Cost of products sold
10,914

 
10,727

 
45,540

 
41,204

Operating expenses
558

 
384

 
1,636

 
1,441

Depreciation and amortization
307

 
268

 
1,130

 
1,032

Selling, general and administrative
117

 
115

 
377

 
432

Goodwill impairment
—

 
689

 
—

 
689

Total costs and expenses
11,896

 
12,183

 
48,683

 
44,798

OPERATING INCOME (LOSS)
383

 
(151
)
 
2,475

 
1,541

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest expense, net of interest capitalized
(212
)
 
(217
)
 
(860
)
 
(849
)
Equity in earnings of unconsolidated affiliates
29

 
35

 
234

 
172

Gain on sale of AmeriGas common units
—

 
—

 
177

 
87

Gains (losses) on interest rate derivatives
(84
)
 
(2
)
 
(157
)
 
44

Non-operating environmental remediation
—

 
(168
)
 
—

 
(168
)
Other, net
7

 
(1
)
 
(25
)
 
5

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
123

 
(504
)
 
1,844

 
832

Income tax expense (benefit) from continuing operations
87

 
(42
)
 
355

 
97

INCOME (LOSS) FROM CONTINUING OPERATIONS
36

 
(462
)
 
1,489

 
735

Income (loss) from discontinued operations
(2
)
 
(11
)
 
64

 
33

NET INCOME (LOSS)
34

 
(473
)
 
1,553

 
768

LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST
(74
)
 
68

 
217

 
312

NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS
108

 
(541
)
 
1,336

 
456

GENERAL PARTNER’S INTEREST IN NET INCOME
140

 
77

 
513

 
506

CLASS H UNITHOLDER’S INTEREST IN NET INCOME
58

 
48

 
217

 
48

COMMON UNITHOLDERS’ INTEREST IN NET INCOME (LOSS)
$
(90
)
 
$
(666
)
 
$
606

 
$
(98
)
INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT:
 
 
 
 
 
 
 
Basic
$
(0.27
)
 
$
(1.87
)
 
$
1.58

 
$
(0.23
)
Diluted
$
(0.27
)
 
$
(1.87
)
 
$
1.58

 
$
(0.23
)
NET INCOME (LOSS) PER COMMON UNIT:
 
 
 
 
 
 
 
Basic
$
(0.28
)
 
$
(1.90
)
 
$
1.77

 
$
(0.18
)
Diluted
$
(0.28
)
 
$
(1.90
)
 
$
1.77

 
$
(0.18
)
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
 
 
 
 
 
 
 
Basic
351.2

 
345.1

 
331.5

 
343.4

Diluted
351.2

 
345.1

 
332.8

 
343.4


4


SUPPLEMENTAL INFORMATION
(Tabular dollar amounts in millions)
(unaudited)
 
Three Months Ended December 31,
 
Years Ended December 31,
 
2014
 
2013
 
2014
 
2013
Reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow (a):
 
 
 
 
 
 
 
Net income (loss)
$
34

 
$
(473
)
 
$
1,553

 
$
768

Interest expense, net of interest capitalized
212

 
217

 
860

 
849

Gain on sale of AmeriGas common units
—

 
—

 
(177
)
 
(87
)
Goodwill impairment
—

 
689

 
—

 
689

Income tax expense (benefit) from continuing operations (b)
87

 
(42
)
 
355

 
97

Depreciation and amortization
307

 
268

 
1,130

 
1,032

Non-cash compensation expense
16

 
11

 
58

 
47

(Gains) losses on interest rate derivatives
84

 
2

 
157

 
(44
)
Unrealized gains on commodity risk management activities
(37
)
 
(6
)
 
(23
)
 
(51
)
Inventory valuation adjustments
456

 
19

 
473

 
(3
)
Non-operating environmental remediation
—

 
168

 
—

 
168

Equity in earnings of unconsolidated affiliates
(29
)
 
(35
)
 
(234
)
 
(172
)
Adjusted EBITDA related to unconsolidated affiliates
145

 
155

 
674

 
629

Other, net
7

 
13

 
3

 
31

Adjusted EBITDA (consolidated)
1,282

 
986

 
4,829

 
3,953

Adjusted EBITDA related to unconsolidated affiliates
(145
)
 
(155
)
 
(674
)
 
(629
)
Distributions from unconsolidated affiliates
84

 
123

 
348

 
464

Interest expense, net of interest capitalized
(212
)
 
(217
)
 
(860
)
 
(849
)
Amortization included in interest expense
(13
)
 
(17
)
 
(61
)
 
(80
)
Current income tax expense from continuing operations
(69
)
 
(4
)
 
(402
)
 
(49
)
Transaction-related income taxes (c)
15

 
—

 
396

 
—

Maintenance capital expenditures
(147
)
 
(109
)
 
(343
)
 
(343
)
Other, net
3

 
—

 
5

 
4

Distributable Cash Flow (consolidated)
798

 
607

 
3,238

 
2,471

Distributable Cash Flow attributable to Sunoco Logistics Partners L.P. (“Sunoco Logistics”) (100%)
(177
)
 
(157
)
 
(750
)
 
(660
)
Distributions from Sunoco Logistics to ETP
81

 
57

 
285

 
204

Distributable Cash Flow attributable to Sunoco LP (100%)
(52
)
 
—

 
(56
)
 
—

Distributions from Sunoco LP to ETP
10

 
—

 
18

 
—

Distributions to ETE in respect of ETP Holdco Corporation (“Holdco”)
—

 
—

 
—

 
(50
)
Distributions to Regency in respect of Lone Star (d)
(37
)
 
(25
)
 
(150
)
 
(87
)
Distributable Cash Flow attributable to the partners of ETP
$
623

 
$
482

 
$
2,585

 
$
1,878

 
 
 
 
 
 
 
 
Distributions to the partners of ETP:
 
 
 
 
 
 
 
Limited Partners (e):
 
 
 
 
 
 
 
Common units held by public
$
321

 
$
263

 
$
1,179

 
$
997

Common units held by ETE
31

 
45

 
119

 
268

Class H Units held by ETE Common Holdings, LLC (“ETE Holdings”) (f)
60

 
54

 
219

 
105

General Partner interests held by ETE
5

 
5

 
21

 
20

Incentive Distribution Rights (“IDRs”) held by ETE
208

 
173

 
754

 
701

IDR relinquishment related to previous transactions
(68
)
 
(57
)
 
(250
)
 
(199
)
Total distributions to be paid to the partners of ETP
557

 
483

 
2,042

 
1,892

Distributions credited to Holdco transactions (g)
—

 
—

 
—

 
(68
)
Net distributions to the partners of ETP
$
557

 
$
483

 
$
2,042

 
$
1,824

Distribution coverage ratio (h)
1.12x

 
1.00x

 
1.27x

 
1.03x

 
 
 
 
 
 
 
 
Distributable Cash Flow per Common Unit (i)
$
1.19

 
$
0.89

 
$
5.55

 
$
3.64


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.
•
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.
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

6


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 months and year ended December 31, 2013 has been revised to reflect this change.
(b)
Income tax expense is based on the earnings of our taxable subsidiaries. For the three months ended December 31, 2014, our effective income tax rate was substantially higher primarily due to non-cash inventory valuation adjustments recognized by subsidiaries other than our taxable subsidiaries.
(c)
Translation-related income taxes primarily included income tax expense related to the Lake Charles LNG Transaction. For the year ended December 31, 2014, amounts previously reported for each of the interim periods have been adjusted to reflect income taxes related to other transactions, which amounts had not previously been reflected in the calculation of Distributable Cash Flow for such interim periods.
(d)
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.
(e)
Distributions on ETP Common Units, as reflected above, exclude cash distributions on ETP Common Units held by subsidiaries of ETP.
(f)
Distributions on the Class H Units for the three months and years ended December 31, 2014 and 2013 were calculated as follows:
 
Three Months Ended December 31,
 
Years Ended December 31,
 
2014
 
2013
 
2014
 
2013
General partner distributions and incentive distributions from Sunoco Logistics
$
54

 
$
35

 
$
185

 
$
67

 
50.05
%
 
50.05
%
 
50.05
%
 
50.05
%
Share of Sunoco Logistics general partner and incentive distributions payable to Class H Unitholder
27

 
18

 
93

 
34

Incremental distributions payable to Class H Unitholder
33

 
36

 
126

 
71

Total Class H Unit distributions
$
60

 
$
54

 
$
219

 
$
105

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.
(g)
For the three months and year ended December 31, 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.
(h)
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.
(i)
The Partnership defines Distributable Cash Flow per Common Unit for a period as the quotient of Distributable Cash Flow attributable to the partners of ETP, net of distributions related to the Class H Units and the General Partner and IDR interests, divided by the weighted average number of Common Units outstanding.
Similar to Distributable Cash Flow, as described above, Distributable Cash Flow per Common Unit is a significant liquidity measure used by the Partnership’s senior management to compare net cash flows generated by the Partnership to the

7


distributions the Partnership expects to pay to its unitholders. Using this measure, the Partnership’s management can compare Distributable Cash Flow among different periods on a per-unit basis.
Distributable Cash Flow per Common Unit is calculated as follows:
 
Three Months Ended December 31,
 
Years Ended December 31,
 
2014
 
2013
 
2014
 
2013
Distributable Cash Flow attributable to the partners of ETP
$
623

 
$
482

 
$
2,585

 
$
1,878

Less:
 
 
 
 
 
 
 
Class H Units held by ETE Holdings
(60
)
 
(54
)
 
(219
)
 
(105
)
General Partner interests held by ETE
(5
)
 
(5
)
 
(21
)
 
(20
)
IDRs held by ETE
(208
)
 
(173
)
 
(754
)
 
(701
)
IDR relinquishment related to previous transactions
68

 
57

 
250

 
199

 
$
418

 
$
307

 
$
1,841

 
$
1,251

Weighted average Common Units outstanding – basic
351.2

 
345.1

 
331.5

 
343.4

Distributable Cash Flow per Common Unit
$
1.19

 
$
0.89

 
$
5.55

 
$
3.64


8


SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)
Our segment results were presented based on the measure of Segment Adjusted EBITDA. The tables below identify the components of Segment Adjusted EBITDA, which was calculated as follows:
•
Gross margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
•
Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate gross margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
•
Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
•
Adjusted EBITDA related to unconsolidated affiliates. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA.
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Segment Adjusted EBITDA:
 
 
 
 
 
Midstream
$
166

 
$
129

 
$
37

Liquids transportation and services
159

 
94

 
65

Interstate transportation and storage
281

 
301

 
(20
)
Intrastate transportation and storage
105

 
112

 
(7
)
Investment in Sunoco Logistics
237

 
210

 
27

Retail marketing
295

 
91

 
204

All other
39

 
49

 
(10
)
 
$
1,282

 
$
986

 
$
296


9


Midstream
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Gathered volumes (MMBtu/d):
3,460,944

 
2,447,559

 
1,013,385

NGLs produced (Bbls/d):
201,620

 
119,878

 
81,742

Equity NGLs produced (Bbls/d):
15,105

 
11,036

 
4,069

Revenues
$
723

 
$
563

 
$
160

Cost of products sold
518

 
400

 
118

Gross margin
205

 
163

 
42

Unrealized gains on commodity risk management activities
—

 
(2
)
 
2

Operating expenses, excluding non-cash compensation expense
(33
)
 
(31
)
 
(2
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(6
)
 
(4
)
 
(2
)
Other
—

 
3

 
(3
)
Segment Adjusted EBITDA
$
166

 
$
129

 
$
37

Gathered volumes, NGLs produced and equity NGLs produced increased primarily due to increased production by our customers in the Eagle Ford Shale and increased volumes resulting from an increase of 320 MMcf/d in processing capacity at our Jackson and Rebel processing plants since last year.
Segment Adjusted EBITDA for the midstream segment reflected an increase in gross margin as follows:
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Gathering and processing fee-based revenues
$
160

 
$
122

 
$
38

Non fee-based contracts and processing
45

 
41

 
4

Total gross margin
$
205

 
$
163

 
$
42

Midstream gross margin reflected an increase in fee-based revenues of $38 million primarily due to increased production and increased capacity from assets recently placed in service in the Eagle Ford Shale and the Permian Basin.

10


Liquids Transportation and Services
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Liquids transportation volumes (Bbls/d)
442,428

 
280,905

 
161,523

NGL fractionation volumes (Bbls/d)
213,710

 
125,275

 
88,435

Revenues
$
982

 
$
776

 
$
206

Cost of products sold
770

 
643

 
127

Gross margin
212

 
133

 
79

Unrealized gains on commodity risk management activities
(11
)
 
—

 
(11
)
Operating expenses, excluding non-cash compensation expense
(38
)
 
(37
)
 
(1
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(5
)
 
(3
)
 
(2
)
Adjusted EBITDA related to unconsolidated affiliates
1

 
1

 
—

Segment Adjusted EBITDA
$
159

 
$
94

 
$
65

The increase in liquids transportation volumes was primarily due to an increase in NGL production from our Jackson processing plant and volumes transported on our wholly-owned pipelines to our Mont Belvieu, Texas facilities of 72,000 Bbls/d. Volumes transported from west Texas and the Eagle Ford Shale on our Lone Star pipeline system increased 59,000 Bbls/d and the remainder was due to volumes transported on our wholly-owned Rio Bravo crude oil pipeline, which was placed in service in October 2014. Average daily fractionated volumes increased due to the 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 liquids transportation and services segment reflected an increase in gross margin as follows:
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Transportation margin
$
100

 
$
52

 
$
48

Processing and fractionation margin
66

 
40

 
26

Storage margin
44

 
38

 
6

Other margin
2

 
3

 
(1
)
Total gross margin
$
212

 
$
133

 
$
79

Transportation margin increased primarily due to higher volumes transported from west Texas and the Eagle Ford Shale on our Lone Star pipeline system and increases in NGL production from our processing plants that connect to various fractionators via our wholly-owned pipelines.
Processing and fractionation margin increased primarily due to the startup of Lone Star’s second fractionator at Mont Belvieu, Texas in October 2013.
Storage margin increased primarily due to increased throughput activity.

11


Interstate Transportation and Storage
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Natural gas transported (MMBtu/d)
6,171,259

 
6,405,185

 
(233,926
)
Natural gas sold (MMBtu/d)
15,643

 
19,244

 
(3,601
)
Revenues
$
267

 
$
317

 
$
(50
)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(72
)
 
(91
)
 
19

Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(16
)
 
(14
)
 
(2
)
Adjusted EBITDA related to unconsolidated affiliates
91

 
89

 
2

Other
11

 
—

 
11

Segment Adjusted EBITDA
$
281

 
$
301

 
$
(20
)
 
 
 
 
 
 
Distributions from unconsolidated affiliates
$
61

 
$
83

 
$
(22
)
Transported volumes decreased primarily due to lower contract utilization on the Panhandle and Trunkline pipelines, which was the result of higher utilization in the prior period attributable to colder weather. The decrease in transported volumes also reflected lower gas supply into the Sea Robin pipeline due to producer maintenance related outages. These decreases in volumes transported were partially offset by higher volumes transported on the Tiger pipeline due to increased demand as a result of colder weather in the Midwest.
Segment Adjusted EBITDA for the interstate transportation and storage segment decreased primarily due to the deconsolidation of Lake Charles LNG effective January 1, 2014, which reduced Segment Adjusted EBITDA by $48 million. This decrease was partially offset by an $8 million increase in reservation revenues and the recognition of an $11 million keep-whole payment from our FEP joint venture partner.
The decrease in cash distributions from unconsolidated affiliates reflected a decrease in cash distributions from Citrus due to slightly higher maintenance capital requirements and the timing of settlement of certain working capital items.
Intrastate Transportation and Storage
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Natural gas transported (MMBtu/d)
8,485,823

 
8,919,220

 
(433,397
)
Revenues
$
610

 
$
592

 
$
18

Cost of products sold
446

 
415

 
31

Gross margin
164

 
177

 
(13
)
Unrealized gains on commodity risk management activities
(4
)
 
(9
)
 
5

Operating expenses, excluding non-cash compensation expense
(49
)
 
(51
)
 
2

Selling, general and administrative expenses, excluding non-cash compensation expense
(6
)
 
(5
)
 
(1
)
Segment Adjusted EBITDA
$
105

 
$
112

 
$
(7
)
Transported volumes decreased compared to the same period last year primarily due to slightly lower production by producers connected to our pipelines partially offset by increased volumes due to a more favorable pricing environment.
Intrastate transportation and storage gross margin decreased primarily due to a decline in the spreads between the spot and forward prices on natural gas we own in the Bammel storage facility. The decrease in storage margin was partially offset by higher transportation fees due to increased rates and a slight increase in natural gas sales.

12


Investment in Sunoco Logistics
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Revenue
$
3,875

 
$
4,288

 
$
(413
)
Cost of products sold
3,802

 
4,040

 
(238
)
Gross margin
73

 
248

 
(175
)
Unrealized (gains) losses on commodity risk management activities
(3
)
 
11

 
(14
)
Operating expenses, excluding non-cash compensation expense
(73
)
 
(31
)
 
(42
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(32
)
 
(19
)
 
(13
)
Inventory valuation adjustments
258

 
—

 
258

Adjusted EBITDA related to unconsolidated affiliates
13

 
10

 
3

Other
1

 
(9
)
 
10

Segment Adjusted EBITDA
$
237

 
$
210

 
$
27

Segment Adjusted EBITDA related to Sunoco Logistics increased due to an increase of $40 million from terminal facilities, primarily due to higher volumes and increased margins from refined products and NGL acquisition and marketing activities. The increase was partially offset by a decrease of $17 million from crude oil pipelines.
Retail Marketing
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Retail gasoline outlets, end of period:
 
 
 
 


Total
6,650

 
5,112

 
1,538

Company-operated
1,251

 
513

 
738

Motor fuel sales:
 
 
 
 
 
Total gallons (in millions)
1,912

 
1,304

 
608

Company-operated (gallons/month per site)
162,993

 
193,901

 
(30,908
)
Motor fuel gross profit (cents per gallon):
 
 
 
 
 
Total
20.7

 
10.2

 
10.5

Company-operated
37.4

 
25.7

 
11.7

Merchandise sales
$
489

 
$
152

 
$
337

 
 
 
 
 
 
Revenue
$
5,920

 
$
5,201

 
$
719

Cost of products sold
5,493

 
4,961

 
532

Gross margin
427

 
240

 
187

Unrealized gains on commodity risk management activities
(7
)
 
(2
)
 
(5
)
Operating expenses, excluding non-cash compensation expense
(283
)
 
(140
)
 
(143
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(41
)
 
(26
)
 
(15
)
Inventory valuation adjustments
198

 
19

 
179

Adjusted EBITDA related to unconsolidated affiliates
1

 
—

 
1

Segment Adjusted EBITDA
$
295

 
$
91

 
$
204


13


The results reflected above include Sunoco LP.
Retail marketing gross margin increased due to the net impacts of the following:
•
increases of $268 million and $10 million from the acquisitions of Susser in August 2014 and Tigermarket in May 2014, respectively;
•
an increase of $98 million from strong retail gasoline and diesel margins; partially offset by
•
a decrease of $10 million due to unfavorable results in non-retail margins; and
•
unfavorable impacts of $179 million related to non-cash inventory valuation adjustments.
Segment Adjusted EBITDA for the retail marketing segment also reflected an increase in operating expenses and in selling, general and administrative expenses primarily due to the recent acquisitions mentioned above.
All Other
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Revenue
$
512

 
$
725

 
$
(213
)
Cost of products sold
504

 
693

 
(189
)
Gross margin
8

 
32

 
(24
)
Unrealized gains on commodity risk management activities
(12
)
 
(4
)
 
(8
)
Operating expenses, excluding non-cash compensation expense
(3
)
 
(9
)
 
6

Selling, general and administrative expenses, excluding non-cash compensation expense
(11
)
 
(35
)
 
24

Adjusted EBITDA related to discontinued operations
—

 
1

 
(1
)
Adjusted EBITDA related to unconsolidated affiliates
40

 
57

 
(17
)
Other
18

 
7

 
11

Elimination
(1
)
 
—

 
(1
)
Segment Adjusted EBITDA
$
39

 
$
49

 
$
(10
)
 
 
 
 
 
 
Distributions from unconsolidated affiliates
$
15

 
$
34

 
$
(19
)
Amounts reflected in our all other segment primarily include:
•
our natural gas marketing and compression operations;
•
an approximate 33% non-operating interest in PES, a refining joint venture;
•
our investment in Regency common and Class F units, which were received by Southern Union (now Panhandle) in exchange for the contribution of its interest in Southern Union Gathering Company, LLC to Regency on April 30, 2013; and
•
our investment in AmeriGas until August 2014.
Segment Adjusted EBITDA decreased primarily due lower earnings from our investment in AmeriGas partially offset by higher management fees, as further discussed below, and higher earnings from our investment in PES.
In connection with the Lake Charles LNG Transaction, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. These fees were reflected in “Other” in the “All other” segment and for the three months ended December 31, 2014 were 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 a decrease of $19 million in cash distribution from our ownership in AmeriGas as a result of selling our interests in AmeriGas during 2014.

14


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 year ended December 31, 2014:
 
Growth
 
Maintenance
 
Total
Direct(1):
 
 
 
 
 
Midstream
$
652

 
$
15

 
$
667

Liquids transportation and services(2)
406

 
21

 
427

Interstate transportation and storage
301

 
110

 
411

Intrastate transportation and storage
133

 
36

 
169

Retail marketing(3)
104

 
73

 
177

All other (including eliminations)
28

 
7

 
35

Total direct capital expenditures
1,624

 
262

 
1,886

Indirect(1):
 
 
 
 
 
Investment in Sunoco Logistics
2,434

 
76

 
2,510

Investment in Sunoco LP
77

 
5

 
82

Total indirect capital expenditures
2,511

 
81

 
2,592

Total capital expenditures
$
4,135

 
$
343

 
$
4,478

(1) 
Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.
(2) 
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.
(3) 
The retail marketing segment includes the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures incurred by Susser and Sunoco LP are reflected beginning on the acquisition date of August 29, 2014 and are broken out between direct and indirect amounts. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary.
We currently expect capital expenditures for the full year 2015 to be within the following ranges:
 
Growth
 
Maintenance
 
Low
 
High
 
Low
 
High
Direct(1):
 
 
 
 
 
 
 
Midstream
$
550

 
$
650

 
$
10

 
$
15

Liquids transportation and services(2)(3)
2,500

 
2,600

 
20

 
25

Interstate transportation and storage(3)
1,000

 
1,100

 
125

 
130

Intrastate transportation and storage
30

 
40

 
30

 
35

Retail marketing(4)
185

 
235

 
80

 
100

All other (including eliminations)
20

 
25

 
10

 
20

Total direct capital expenditures
4,285

 
4,650

 
275

 
325

Indirect(1):
 
 
 
 
 
 
 
Investment in Sunoco Logistics
1,800

 
2,200

 
70

 
90

Investment in Sunoco LP(4)
165

 
215

 
15

 
25

Total indirect capital expenditures
1,965

 
2,415

 
85

 
115

Total projected capital expenditures
$
6,250

 
$
7,065

 
$
360

 
$
440

(1) 
Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.
(2) 
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 $350 million and $400 million.
(3) 
Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects.
(4) 
The retail marketing segment includes the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary.

15


SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions)
(unaudited)
 
Three Months Ended December 31,
 
 
 
2014
 
2013
 
Change
Equity in earnings (losses) of unconsolidated affiliates:
 
 
 
 
 
Citrus
$
20

 
$
21

 
$
(1
)
FEP
14

 
14

 
—

Regency
(19
)
 
(2
)
 
(17
)
PES
10

 
(28
)
 
38

AmeriGas
(2
)
 
26

 
(28
)
Other
6

 
4

 
2

Total equity in earnings of unconsolidated affiliates
$
29

 
$
35

 
$
(6
)
 
 
 
 
 
 
Adjusted EBITDA related to unconsolidated affiliates:
 
 
 
 
 
Citrus
$
72

 
$
70

 
$
2

FEP
19

 
18

 
1

Regency
22

 
24

 
(2
)
PES
17

 
(21
)
 
38

AmeriGas
—

 
53

 
(53
)
Other
15

 
11

 
4

Total Adjusted EBITDA related to unconsolidated affiliates
$
145

 
$
155

 
$
(10
)
 
 
 
 
 
 
Distributions received from unconsolidated affiliates:
 
 
 
 
 
Citrus
$
42

 
$
65

 
$
(23
)
FEP
19

 
18

 
1

Regency
16

 
15

 
1

AmeriGas
—

 
19

 
(19
)
Other
7

 
6

 
1

Total distributions received from unconsolidated affiliates
$
84

 
$
123

 
$
(39
)

16