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Form 8-K Energy Transfer Partners For: Feb 24

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February 24, 2016 5:26 PM EST




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
February 24, 2016
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.)

8111 Westchester Drive, Suite 600,
Dallas, Texas 75225
(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 February 24, 2016, Energy Transfer Partners, L.P. (the “Partnership”) issued a press release announcing its financial and operating results for the fourth quarter ended December 31, 2015. 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 February 24, 2016




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/ Thomas E. Long
Thomas E. Long
Chief Financial Officer
Dated: February 24, 2016




EXHIBIT INDEX
Exhibit Number
 
Description of the Exhibit
99.1
 
Energy Transfer Partners, L.P. Press Release dated February 24, 2016




ENERGY TRANSFER PARTNERS
REPORTS FOURTH QUARTER RESULTS
Dallas – February 24, 2016 – Energy Transfer Partners, L.P. (NYSE: ETP) today reported its financial results for the quarter ended December 31, 2015. Adjusted EBITDA for Energy Transfer Partners, L.P. (“ETP” or the “Partnership”) for the three months ended December 31, 2015 totaled $1.36 billion, a decrease of $168 million compared to the same period last year. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the three months ended December 31, 2015 totaled $959 million, an increase of $165 million over the same period last year. Income from continuing operations for the three months ended December 31, 2015 was $21 million, an increase of $264 million over the same period last year.
Adjusted EBITDA for ETP for the year ended December 31, 2015 totaled $5.71 billion, an increase of $4 million compared to last year. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the year ended December 31, 2015 totaled $3.45 billion, an increase of $196 million over last year. Income from continuing operations for the year ended December 31, 2015 was $1.52 billion, an increase of $286 million over last year.
In January 2016, ETP announced a quarterly distribution of $1.055 per unit ($4.22 annualized) on ETP Common Units for the quarter ended December 31, 2015.
ETP’s other recent key accomplishments include the following:
•
In December 2015, ETP announced that the Lake Charles LNG Project has received approval from the FERC to site, construct and operate a natural gas liquefaction and export facility in Lake Charles, Louisiana. On February 15, 2016, Royal Dutch Shell plc completed its acquisition of BG Group plc. Final investment decisions from Royal Dutch Shell plc and Lake Charles LNG Export Company, LLC, a subsidiary of ETP and Energy Transfer Equity, L.P. (“ETE”), are expected to be made in 2016, with construction to start immediately following an affirmative investment decision and first LNG export anticipated about four years later.
•
In November 2015, ETP and Sunoco LP announced ETP’s contribution to Sunoco LP of the remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP will pay ETP $2.03 billion in cash, subject to certain working capital adjustments, and will issue to ETP 5.7 million Sunoco LP common units. The transaction will be effective January 1, 2016, and is expected to close in March 2016.
•
As of December 31, 2015, ETP’s $3.75 billion revolving credit facility had $1.36 billion of outstanding borrowings, and its leverage ratio, as defined by the credit agreement, was 4.50x.
•
In the fourth quarter of 2015, ETP issued 6.7 million common units through its at-the-market equity program, generating net proceeds of $293 million.
An analysis of ETP’s segment results and other supplementary data is provided after the financial tables shown below. ETP has scheduled a conference call for 8:00 a.m. Central Time, Thursday, February 25, 2016 to discuss the fourth quarter 2015 results. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfer.com and will also be available for replay on ETP’s website for a limited time.
Energy Transfer Partners, L.P. (NYSE: ETP) is a master limited partnership owning and operating one of the largest and most diversified portfolios of energy assets in the United States. ETP’s subsidiaries include Panhandle Eastern Pipe Line Company, LP (the successor of Southern Union Company) and Lone Star NGL LLC, which owns and operates natural gas liquids storage, fractionation and transportation assets. In total, ETP currently owns and operates more than 62,500 miles of natural gas and natural gas liquids pipelines. ETP also owns the general partner, 100% of the incentive distribution rights, and approximately 67.1 million common units in Sunoco Logistics Partners L.P. (NYSE: SXL), which operates a geographically diverse portfolio of crude oil and refined products pipelines, terminalling and crude oil acquisition and marketing assets. Additionally, ETP owns fuel distribution and retail marketing assets and approximately 36% of the limited partner interests in Sunoco LP (formerly Susser Petroleum Partners LP) (NYSE: SUN), a wholesale fuel distributor and convenience store operator. ETP’s general partner is owned by Energy Transfer Equity, L.P. (NYSE: ETE). For more information, visit the Energy Transfer Partners, L.P. website at www.energytransfer.com.

1


Energy Transfer Equity, L.P. (NYSE: ETE) is a master limited partnership which owns the general partner and 100% of the incentive distribution rights (IDRs) of Energy Transfer Partners, L.P. (NYSE: ETP) and Sunoco LP(NYSE: SUN) and approximately 2.6 million ETP Common Units, approximately 81 million ETP Class H Units, which track 90% of the underlying economics of the general partner interest and the IDRs of Sunoco Logistics Partners L.P. (NYSE: SXL), and 100 ETP Class I Units. On a consolidated basis, ETE’s family of companies owns and operates approximately 71,000 miles of natural gas, natural gas liquids, refined products, and crude oil pipelines. For more information, visit the Energy Transfer Equity, L.P. website at www.energytransfer.com.
Sunoco Logistics Partners L.P. (NYSE: SXL), headquartered in Newtown Square, Pennsylvania, is a master limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary crude oil, refined products, and natural gas liquids pipeline, terminalling and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, refined products, and natural gas liquids. Sunoco Logistics’ general partner is a consolidated subsidiary of Energy Transfer Partners, L.P. (NYSE: ETP). For more information, visit the Sunoco Logistics Partners L.P. website at www.sunocologistics.com.
Forward-Looking Statements
This press release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results are discussed in the Partnerships’ Annual Reports on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. The 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 website at www.energytransfer.com.
Contacts
Investor Relations:
Energy Transfer
Brent Ratliff
214-981-0700 (office)
Energy Transfer
Lyndsay Hannah
214-840-5477 (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,
 
2015
 
2014
ASSETS
 
 
 
Current assets
$
4,698

 
$
6,029

 
 
 
 
Property, plant and equipment, net
45,087

 
38,907

 
 
 
 
Advances to and investments in unconsolidated affiliates
5,003

 
3,760

Non-current derivative assets
—

 
10

Other non-current assets, net
536

 
644

Intangible assets, net
4,421

 
5,526

Goodwill
5,428

 
7,642

Total assets
$
65,173

 
$
62,518

LIABILITIES AND EQUITY
 
 
 
Current liabilities
$
4,121

 
$
6,585

 
 
 
 
Long-term debt, less current maturities
28,553

 
24,831

Long-term notes payable – related party
233

 
—

Non-current derivative liabilities
137

 
154

Deferred income taxes
4,082

 
4,331

Other non-current liabilities
968

 
1,258

 
 
 
 
Commitments and contingencies
 
 
 
Series A Preferred Units
33

 
33

Redeemable noncontrolling interests
15

 
15

 
 
 
 
Equity:
 
 
 
Total partners’ capital
20,836

 
12,070

Noncontrolling interest
6,195

 
5,153

Predecessor equity
—

 
8,088

Total equity
27,031

 
25,311

Total liabilities and equity
$
65,173

 
$
62,518


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,
 
2015
 
2014
 
2015
 
2014
REVENUES
$
5,825

 
$
13,427

 
$
34,292

 
$
55,475

COSTS AND EXPENSES:
 
 
 
 
 
 
 
Cost of products sold
4,237

 
11,591

 
27,029

 
48,414

Operating expenses
498

 
696

 
2,261

 
2,059

Depreciation, depletion and amortization
478

 
463

 
1,929

 
1,669

Selling, general and administrative
86

 
148

 
475

 
520

Impairment losses
339

 
370

 
339

 
370

Total costs and expenses
5,638

 
13,268

 
32,033

 
53,032

OPERATING INCOME
187

 
159

 
2,259

 
2,443

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest expense, net
(312
)
 
(297
)
 
(1,291
)
 
(1,165
)
Equity in earnings from unconsolidated affiliates
81

 
67

 
469

 
332

Gain on sale of AmeriGas common units
—

 
—

 
—

 
177

Losses on extinguishments of debt
—

 
(25
)
 
(43
)
 
(25
)
Losses on interest rate derivatives
(4
)
 
(84
)
 
(18
)
 
(157
)
Other, net
(34
)
 
24

 
22

 
(12
)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
(82
)
 
(156
)
 
1,398

 
1,593

Income tax expense (benefit) from continuing operations
(103
)
 
87

 
(123
)
 
358

INCOME (LOSS) FROM CONTINUING OPERATIONS
21

 
(243
)
 
1,521

 
1,235

Income (loss) from discontinued operations
—

 
(2
)
 
—

 
64

NET INCOME (LOSS)
21

 
(245
)
 
1,521

 
1,299

Less: Net income (loss) attributable to noncontrolling interest
(25
)
 
(103
)
 
157

 
116

Less: Net loss attributable to predecessor
—

 
(250
)
 
(34
)
 
(153
)
NET INCOME ATTRIBUTABLE TO PARTNERS
46

 
108

 
1,398

 
1,336

General Partner’s interest in net income
285

 
140

 
1,064

 
513

Class H Unitholder’s interest in net income
74

 
58

 
258

 
217

Class I Unitholder’s interest in net income
14

 
—

 
94

 
—

Common Unitholders’ interest in net income (loss)
$
(327
)
 
$
(90
)
 
$
(18
)
 
$
606

INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT:
 
 
 
 
 
 
 
Basic
$
(0.68
)
 
$
(0.27
)
 
$
(0.09
)
 
$
1.58

Diluted
$
(0.68
)
 
$
(0.27
)
 
$
(0.10
)
 
$
1.58

NET INCOME (LOSS) PER COMMON UNIT:
 
 
 
 
 
 
 
Basic
$
(0.68
)
 
$
(0.28
)
 
$
(0.09
)
 
$
1.77

Diluted
$
(0.68
)
 
$
(0.28
)
 
$
(0.10
)
 
$
1.77

WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
 
 
 
 
 
 
 
Basic
485.1

 
351.2

 
432.8

 
331.5

Diluted
485.5

 
351.2

 
435.4

 
332.8


4


SUPPLEMENTAL INFORMATION
(Dollars and units in millions, except per unit amounts)
(unaudited)
 
Three Months Ended December 31,
 
Years Ended December 31,
 
2015
 
2014
 
2015
 
2014
Reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow (a):
 
 
 
 
 
 
 
Net income (loss)
$
21

 
$
(245
)
 
$
1,521

 
$
1,299

Interest expense, net of interest capitalized
312

 
297

 
1,291

 
1,165

Gain on sale of AmeriGas common units
—

 
—

 
—

 
(177
)
Impairment losses
339

 
370

 
339

 
370

Income tax expense (benefit) from continuing operations (b)
(103
)
 
87

 
(123
)
 
358

Depreciation, depletion and amortization
478

 
463

 
1,929

 
1,669

Non-cash compensation expense
20

 
18

 
79

 
68

Losses on interest rate derivatives
4

 
84

 
18

 
157

Unrealized (gains) losses on commodity risk management activities
(7
)
 
(113
)
 
65

 
(112
)
Inventory valuation adjustments
120

 
456

 
104

 
473

Losses on extinguishments of debt
—

 
25

 
43

 
25

Equity in earnings of unconsolidated affiliates
(81
)
 
(67
)
 
(469
)
 
(332
)
Adjusted EBITDA related to unconsolidated affiliates
226

 
164

 
937

 
748

Other, net
31

 
(11
)
 
(20
)
 
(1
)
Adjusted EBITDA (consolidated)
1,360

 
1,528

 
5,714

 
5,710

Adjusted EBITDA related to unconsolidated affiliates
(226
)
 
(164
)
 
(937
)
 
(748
)
Distributable cash flow from unconsolidated affiliates (c)
214

 
119

 
682

 
482

Interest expense, net of interest capitalized
(312
)
 
(297
)
 
(1,291
)
 
(1,165
)
Amortization included in interest expense
(6
)
 
(12
)
 
(36
)
 
(60
)
Current income tax (expense) benefit from continuing operations (b)
283

 
(70
)
 
325

 
(407
)
Transaction-related income taxes (d)
(51
)
 
15

 
(51
)
 
396

Maintenance capital expenditures
(177
)
 
(184
)
 
(485
)
 
(444
)
Other, net
1

 
2

 
12

 
7

Distributable Cash Flow (consolidated)
1,086

 
937

 
3,933

 
3,771

Distributable Cash Flow attributable to Sunoco Logistics Partners L.P. (“Sunoco Logistics”) (100%)
(245
)
 
(177
)
 
(879
)
 
(750
)
Distributions from Sunoco Logistics to ETP
118

 
81

 
413

 
285

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

 
(52
)
 
(68
)
 
(56
)
Distributions from Sunoco LP to ETP (e)
—

 
10

 
24

 
18

Distributable cash flow attributable to noncontrolling interest in Edwards Lime Gathering LLC
(5
)
 
(5
)
 
(20
)
 
(19
)
Distributable Cash Flow attributable to the partners of ETP
954

 
794

 
3,403

 
3,249

Transaction-related expenses
5

 
—

 
42

 
—

Distributable Cash Flow attributable to the partners of ETP, as adjusted
$
959

 
$
794

 
$
3,445

 
$
3,249

 
 
 
 
 
 
 
 
Distributions to the partners of ETP (f):
 
 
 
 
 
 
 
Limited Partners:
 
 
 
 
 
 
 
Common units held by public
$
512

 
$
321

 
$
1,970

 
$
1,179

Common units held by ETE
3

 
31

 
54

 
119

Class H Units held by ETE (g)
77

 
60

 
263

 
219

General Partner interests held by ETE
8

 
5

 
31

 
21

Incentive Distribution Rights (“IDRs”) held by ETE
324

 
208

 
1,261

 
754

IDR relinquishments net of Class I Unit distributions
(28
)
 
(68
)
 
(111
)
 
(250
)
Total distributions to be paid to the partners of ETP
$
896

 
$
557

 
$
3,468

 
$
2,042

Common Units outstanding – end of period
505.6

 
355.5

 
505.6

 
355.5

Distribution coverage ratio (h)
1.07x

 
1.43x

 
0.99x

 
1.59x

 
 
 
 
 
 
 
 
Distributable Cash Flow per Common Unit (i)
$
1.19

 
$
1.68

 
$
4.62

 
$
7.56


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, including (i) for unconsolidated affiliates with publicly traded equity interests, distributions paid or expected to be paid for the periods presented and (ii) for unconsolidated affiliates that are under common control of ETP’s parent, ETP’s proportionate share of the distributable cash flow of the investee.
Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.
On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ETP’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among ETP’s subsidiaries, the Distributable Cash Flow generated by ETP’s subsidiaries may not be available to be distributed to the partners of ETP. In order to reflect the cash flows available for distributions to the partners of ETP, ETP has reported Distributable Cash Flow attributable to the partners of ETP, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:
•
For subsidiaries with publicly traded equity interests, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to the partners of ETP includes distributions to be received by the parent company with respect to the periods presented.
•
For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, but Distributable Cash Flow attributable to the partners of ETP is net of distributions to be paid by the subsidiary to the noncontrolling interests.
For Distributable Cash Flow attributable to the partners of ETP, as adjusted, certain transaction-related and non-recurring expenses that are included in net income are excluded.

6


(b)
For the three and twelve months ended December 31, 2015, the Partnership’s effective income tax rate decreased from the prior year primarily due to lower earnings among the Partnership’s consolidated corporate subsidiaries. The three and twelve months ended December 31, 2015 also reflect a benefit of $24 million of net state tax benefit attributable to statutory state rate changes resulting from the Regency Merger and sale of Susser to Sunoco LP, as well as a favorable impact of $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015. For the three and twelve months ended December 31, 2014, the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $87 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes.
The three months ended December 31, 2015 reflect current income tax benefits of $80 million due to lower earnings among the Partnership’s consolidated corporate subsidiaries, $120 million due to the retroactive re-enactment of bonus depreciation, and $24 million attributable to the reversal of an income tax reserve for certain amended tax returns that had been filed claiming previously disallowed Pennsylvania net operating loss deductions. Additionally, the three months ended December 31, 2015 also reflect a $51 million current income tax benefit related to the funding of Sunoco, Inc.’s pension plan obligations, which benefit has been excluded from Distributable Cash Flow, as discussed in note (d) below.
(c)
For the three months ended December 31, 2015, distributable cash flow from unconsolidated affiliates includes distributions to be paid by Sunoco LP with respect to the fourth quarter of 2015, as well as the Partnership’s share of the distributable cash flow of Sunoco LLC for the fourth quarter of 2015. For the year ended December 31, 2015, distributable cash flow from unconsolidated affiliates includes distributions to be paid by Sunoco LP with respect to the third and fourth quarters of 2015, as well as the Partnership’s share of the distributable cash flow of Sunoco LLC for the third and fourth quarters of 2015.
(d)
For the three months ended December 31, 2015, transaction-related income taxes reflect a $51 million current income tax benefit related to the funding of Sunoco, Inc.’s pension plan obligations, which amount is reflected in “Current income tax (expense) benefit from continuing operations.”
Transaction-related income taxes primarily included income tax expense related to the Lake Charles LNG Transaction. For the three months and 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.
(e)
Amounts related to Sunoco LP reflect the periods through June 30, 2015, subsequent to which Sunoco LP was deconsolidated and is now reflected as an equity method investment.
(f)
Distributions on ETP Common Units, as reflected above, exclude cash distributions on Partnership common units held by subsidiaries of ETP.
(g)
Distributions on the Class H Units for the three months and years ended December 31, 2015 and 2014 were calculated as follows:
 
Three Months Ended December 31,
 
Years Ended December 31,
 
2015
 
2014
 
2015
 
2014
General partner distributions and incentive distributions from Sunoco Logistics
$
86

 
$
54

 
$
293

 
$
185

 
90.05
%
 
50.05
%
 
90.05
%
 
50.05
%
Share of Sunoco Logistics general partner and incentive distributions payable to Class H Unitholder
77

 
27

 
263

 
93

Incremental distributions payable to Class H Unitholder
—

 
33

 
—

 
126

Total Class H Unit distributions
$
77

 
$
60

 
$
263

 
$
219

*
Incremental distributions previously paid to the Class H Unitholder were eliminated in Amendment No. 9 to ETP’s Amended and Restated Agreement of Limited Partnership effective in the first quarter of 2015.
(h)
Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to the partners of ETP, as adjusted, divided by net distributions expected to be paid to the partners of ETP in respect of such period.

7


(i)
The Partnership defines Distributable Cash Flow per Common Unit for a period as the quotient of Distributable Cash Flow attributable to the partners of ETP, as adjusted, net of distributions related to the Class H Units, Class I Units and the General Partner and IDR interests, divided by the weighted average number of Common Units outstanding.
Similar to Distributable Cash Flow as described above, Distributable Cash Flow per Common Unit is a significant liquidity measure used by the Partnership’s senior management to compare net cash flows generated by the Partnership to the distributions the Partnership expects to pay to its unitholders. Using this measure, the Partnership’s management can compare Distributable Cash Flow attributable to the partners of ETP, as adjusted, among different periods on a per-unit basis.
Distributable Cash Flow per Common Unit is calculated as follows:
 
Three Months Ended December 31,
 
Years Ended December 31,
 
2015
 
2014
 
2015
 
2014
Distributable Cash Flow attributable to the partners of ETP, as adjusted
$
959

 
$
794

 
$
3,445

 
$
3,249

Less:
 
 
 
 
 
 
 
Class H Units held by ETE
(77
)
 
(60
)
 
(263
)
 
(219
)
General Partner interests held by ETE
(8
)
 
(5
)
 
(31
)
 
(21
)
IDRs held by ETE
(324
)
 
(208
)
 
(1,261
)
 
(754
)
IDR relinquishments net of Class I Unit distributions
28

 
68

 
111

 
250

 
$
578

 
$
589

 
$
2,001

 
$
2,505

Weighted average Common Units outstanding – basic
485.1

 
351.2

 
432.8

 
331.5

Distributable Cash Flow per Common Unit
$
1.19

 
$
1.68

 
$
4.62

 
$
7.56


8


SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)
Our segment results are 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,
 
2015
 
2014
Segment Adjusted EBITDA:
 
 
 
Midstream
$
264

 
$
360

Liquids transportation and services
222

 
159

Interstate transportation and storage
283

 
307

Intrastate transportation and storage
122

 
120

Investment in Sunoco Logistics
317

 
237

Retail marketing
119

 
295

All other
33

 
50

 
$
1,360

 
$
1,528


9


Midstream
 
Three Months Ended December 31,
 
2015
 
2014
Gathered volumes (MMBtu/d):
10,051,612

 
9,531,307

NGLs produced (Bbls/d):
443,741

 
376,724

Equity NGLs produced (Bbls/d):
29,437

 
30,656

Revenues
$
1,289

 
$
1,599

Cost of products sold
840

 
993

Gross margin
449

 
606

Unrealized gains on commodity risk management activities
—

 
(76
)
Operating expenses, excluding non-cash compensation expense
(183
)
 
(156
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(8
)
 
(16
)
Adjusted EBITDA related to unconsolidated affiliates
6

 
2

Segment Adjusted EBITDA
$
264

 
$
360

Gathered volumes and NGLs produced increased during the three months ended December 31, 2015 compared to the same period last year primarily due the King Ranch acquisition, as well as increased gathering and processing capacities in the Eagle Ford Shale, Permian Basin and Cotton Valley regions.
Segment Adjusted EBITDA for the midstream segment reflected a decrease in gross margin as follows:
 
Three Months Ended December 31,
 
2015
 
2014
Gathering and processing fee-based revenues
$
393

 
$
382

Non fee-based contracts and processing
56

 
224

Total gross margin
$
449

 
$
606

For the three months ended December 31, 2015 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:
•
lower natural gas prices and lower NGL prices resulted in lower non-fee based margins of $22 million and $51 million, respectively;
•
a decrease of $19 million due to realized gains on derivatives in the prior year; and
•
an increase of $27 million in operating expenses primarily due to assets recently placed in service, including the Rebel system in west Texas, the King Ranch system in south Texas, as well as the Dubberly plant in north Louisiana; partially offset by
•
an increase of $11 million in fee-based revenues due to increased production and increased capacity from assets placed in service in the Eagle Ford Shale, Permian Basin and Cotton Valley, partially offset by volume declines in the North Texas and Mid-Continent/Panhandle regions; and
•
a decrease of $8 million in general and administrative expenses primarily due to a reduction in employee-related cost.


10


Liquids Transportation and Services
 
Three Months Ended December 31,
 
2015
 
2014
Liquids transportation volumes (Bbls/d)
473,656

 
393,743

NGL fractionation volumes (Bbls/d)
249,566

 
204,565

Revenues
$
972

 
$
982

Cost of products sold
716

 
770

Gross margin
256

 
212

Unrealized (gains) losses on commodity risk management activities
6

 
(11
)
Operating expenses, excluding non-cash compensation expense
(38
)
 
(38
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(4
)
 
(5
)
Adjusted EBITDA related to unconsolidated affiliates
2

 
1

Segment Adjusted EBITDA
$
222

 
$
159

NGL transportation volumes increased due to increases from the Eagle Ford, Permian, and Southeast Texas producing regions, offset by decreases from North Texas. Additionally, we commissioned a crude transportation pipeline in the fourth quarter of 2014 that transported approximately 44,000 Bbls/d for the three months ended December 31, 2015.
Segment Adjusted EBITDA for the liquids transportation and services segment reflected an increase in gross margin as follows:
 
Three Months Ended December 31,
 
2015
 
2014
Transportation margin
$
104

 
$
100

Processing and fractionation margin
79

 
66

Storage margin
48

 
44

Other margin
25

 
2

Total gross margin
$
256

 
$
212

For the three months ended December 31, 2015 compared to the same period last year, Segment Adjusted EBITDA related to our liquids transportation and services segment increased due to the net impacts of the following:
•
an increase of $4 million in transportation margin primarily due to higher volumes transported out of the Permian and the Eagle Ford producing regions. Increased volumes from the Eagle Ford region led to increases in margin of $3 million for the three months ended December 31, 2015;
•
an increase of $6 million in processing and fractionation margin (excluding changes in unrealized gains of $7 million) due to a $15 million increase in fees from the Mariner South export terminal which ramped up starting in April of 2015, offset by a reduction of $8 million in margin associated with our off-gas fractionator in Geismar, Louisiana for the three months ended December 31, 2015 as NGL and olefins market prices decreased significantly for the comparable period;
•
an increase of $4 million in storage margin due to a $3 million increase in fee-based storage margin for the three months ended December 31, 2015 as a result of favorable market conditions and a specific contract negotiated in connection with the Mariner South LPG export project. In addition, non-fee based storage margin increased $1 million for the three months ended December 31, 2015 due to gains recognized on the withdrawal of inventory from our caverns;
•
an increase of $48 million in other margin (excluding changes in unrealized losses of $25 million) primarily due to the withdrawal and sale of physical storage volumes; and
•
a decrease of $1 million in selling, general and administrative expenses primarily due to lower employee-related costs.

11


Interstate Transportation and Storage
 
Three Months Ended December 31,
 
2015
 
2014
Natural gas transported (MMBtu/d)
5,739,157

 
6,125,616

Natural gas sold (MMBtu/d)
18,665

 
15,643

Revenues
$
258

 
$
267

Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(83
)
 
(72
)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(9
)
 
(16
)
Adjusted EBITDA related to unconsolidated affiliates
117

 
117

Other
—

 
11

Segment Adjusted EBITDA
$
283

 
$
307

 
 
 
 
Distributions from unconsolidated affiliates
$
75

 
$
80

Transported volumes decreased primarily due to a managed contract roll off to facilitate the transfer of one of the pipelines that was taken out of service in advance of being repurposed from natural gas service to crude oil service. The decrease was partially offset by increased deliveries on the Transwestern pipeline due to sustained cooling demand in the Phoenix market and increased customer demand in New Mexico.
Segment Adjusted EBITDA for the interstate transportation and storage segment decreased primarily due to a $9 million decrease in revenues due to the expiration of a transportation rate schedule on the Transwestern pipeline and $8 million due to a managed contract roll off to facilitate the transfer of one of the pipelines that was taken out of service in advance of being repurposed from natural gas service to crude oil service. These decreases were partially offset by sales of capacity at higher rates on the Panhandle, Trunkline and Transwestern pipelines.
The decrease in cash distributions from unconsolidated affiliates reflected a decrease in cash distributions from Citrus due to slightly higher cash taxes on Citrus for the three months ended December 31, 2015.
Intrastate Transportation and Storage
 
Three Months Ended December 31,
 
2015
 
2014
Natural gas transported (MMBtu/d)
7,926,907

 
8,485,823

Revenues
$
503

 
$
610

Cost of products sold
327

 
446

Gross margin
176

 
164

Unrealized gains on commodity risk management activities
(23
)
 
(4
)
Operating expenses, excluding non-cash compensation expense
(42
)
 
(49
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(4
)
 
(6
)
Adjusted EBITDA related to unconsolidated affiliates
15

 
15

Segment Adjusted EBITDA
$
122

 
$
120

Transported volumes decreased compared to the same period last year primarily due to lower production volume, mostly in the Barnett Shale region, partially offset by increased volumes related to significant new long-term transportation contracts.

12


For the three months ended December 31, 2015 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:
•
an increase of $6 million in transportation fees margin (excluding changes in unrealized loss of $1 million), primarily due to increased revenue from renegotiated and newly initiated long-term fixed-capacity fee contracts on our Houston Pipeline system;
•
a decrease of $7 million in operating expenses primarily due to a decrease in fuel consumption expense driven by a decrease in fuel market prices; and
•
a decrease of $2 million in selling, general and administrative expenses primarily due to lower employee-related costs; partially offset by
•
a decrease of $3 million in storage margin (excluding changes in unrealized gains of $14 million), primarily due to the timing of the movement of market prices;
•
a decrease of $2 million (excluding changes in unrealized gains of $7 million) due to a decrease from the purchase and sale of natural gas on our system;
•
a decrease of $8 million in retained fuel revenues (excluding changes in unrealized loss of $1 million) due to significantly lower market prices. The average spot price at the Houston Ship Channel location for the twelve month period ending December 31, 2015 decreased by $1.76, or 41%, to $2.57 as compared to $4.32 for the prior year period.
Investment in Sunoco Logistics
 
Three Months Ended December 31,
 
2015
 
2014
Revenue
$
2,305

 
$
3,875

Cost of products sold(1)
2,067

 
3,812

Gross margin
238

 
63

Unrealized (gains) losses on commodity risk management activities
13

 
(3
)
Operating expenses, excluding non-cash compensation expense(1)
(42
)
 
(63
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(24
)
 
(32
)
Inventory valuation adjustments
118

 
258

Adjusted EBITDA related to unconsolidated affiliates
14

 
13

Other
—

 
1

Segment Adjusted EBITDA
$
317

 
$
237

(1) 
Prior period expenses have been recast to conform to Sunoco Logistics’ current presentation.
For the three months ended December 31, 2015 compared to the same period last year, Segment Adjusted EBITDA related to Sunoco Logistics increased due to the following:
•
an increase of $9 million from crude oil pipelines, primarily due to the commencement of operations on the Permian Express 2 pipeline in the third quarter of 2015. Higher contributions from crude oil terminals also contributed to the increase. These positive factors were partially offset by decreased margins related to crude oil acquisition and marketing activities which were negatively impacted by narrowing crude oil differentials compared to the same period last year;
•
an increase of $36 million from NGL pipelines, primarily due to improved contributions from NGLs pipelines which was driven by the Mariner South and Mariner East 1 pipeline projects which commenced operations in late 2014. Increased results from the Nederland and Marcus Hook NGLs terminals also contributed to the increase. These positive factors were partially offset by decreased margins related to NGLs acquisition and marketing activities; and
•
an increase of $35 million from refined products pipelines, primarily due to increased contributions which was largely attributable to the Allegheny Access pipeline which commenced operations in the first quarter of 2015. Results related to the refined products terminals and acquisition and marketing activities improved compared to the prior year period. Adjusted EBITDA related to refined products joint venture interest also contributed to the increase.


13


Retail Marketing
 
Three Months Ended December 31,
 
2015
 
2014
Motor fuel outlets and convenience stores, end of period:
 
 
 
Retail
438

 
1,251

Third-party wholesale
—

 
5,399

Total
438

 
6,650

Total motor fuel gallons sold (in millions):
 
 
 
Retail
266

 
608

Third-party wholesale
—

 
1,304

Total
266

 
1,912

Motor fuel gross profit (cents/gallon):
 
 
 
Retail
24.1

 
37.4

Third-party wholesale
—

 
13.0

Volume-weighted average for all gallons
24.1

 
20.7

Merchandise sales (in millions)
$
143

 
$
489

Retail merchandise margin %
25.6
%
 
30.1
%
 
 
 
 
Revenue
$
777

 
$
5,920

Cost of products sold
655

 
5,493

Gross margin
122

 
427

Unrealized gains on commodity risk management activities
—

 
(7
)
Operating expenses, excluding non-cash compensation expense
(95
)
 
(283
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(4
)
 
(41
)
Inventory valuation adjustments
2

 
198

Adjusted EBITDA related to unconsolidated affiliates
94

 
1

Segment Adjusted EBITDA
$
119

 
$
295

The results reflected above include Sunoco LP for the three months ended December 31, 2014.
For the three months ended December 31, 2015 compared to the same period last year, Segment Adjusted EBITDA related to our retail marketing segment decreased due to the net impacts of the following:
•
a decrease of $57 million due to the deconsolidation of Sunoco LP as a result of the sale of Sunoco LP’s general partner interest and incentive distribution rights to ETE effective July 1, 2015;
•
a decrease of $140 million due to unfavorable fuel margins and $15 million due to unfavorable volumes in the retail and wholesale channels; and
•
a decrease of $7 million in margins as 2014 benefited from favorable regional market conditions for ethanol; partially offset by
•
an increase of $19 million in merchandise margins and $9 million from other retail and wholesale margins;
•
a favorable impact of $8 million from recent acquisitions; and
•
a decrease of $7 million in expenses primarily due to one-time acquisition costs in 2014.

14


All Other
 
Three Months Ended December 31,
 
2015
 
2014
Revenue
$
853

 
$
949

Cost of products sold
748

 
868

Gross margin
105

 
81

Unrealized gains on commodity risk management activities
(3
)
 
(12
)
Operating expenses, excluding non-cash compensation expense
(24
)
 
(31
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(31
)
 
(28
)
Adjusted EBITDA related to unconsolidated affiliates
(20
)
 
17

Other
19

 
17

Elimination
(13
)
 
6

Segment Adjusted EBITDA
$
33

 
$
50

 
 
 
 
Distributions from unconsolidated affiliates
$
43

 
$
3

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 Coal Handling, an entity that owns and operates end-user coal handling facilities; and
•
our investment in AmeriGas until August 2014.
Segment Adjusted EBITDA decreased primarily due to lower earnings driven by the impact of weaker refining crack spreads on 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, 2015 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 increase in cash distributions from unconsolidated affiliates was due to an increase of $42 million in cash distributions from our ownership in PES.

15


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, 2015:
 
Growth
 
Maintenance
 
Total
Direct(1):
 
 
 
 
 
Midstream
$
2,055

 
$
117

 
$
2,172

Liquids transportation and services(2)
2,091

 
18

 
2,109

Interstate transportation and storage(2)
741

 
119

 
860

Intrastate transportation and storage
74

 
31

 
105

Retail marketing(3)
259

 
63

 
322

All other (including eliminations)
337

 
46

 
383

Total direct capital expenditures
5,557

 
394

 
5,951

Indirect(1):
 
 
 
 
 
Investment in Sunoco Logistics
2,042

 
84

 
2,126

Investment in Sunoco LP(4)
83

 
7

 
90

Total indirect capital expenditures
2,125

 
91

 
2,216

Total capital expenditures
$
7,682

 
$
485

 
$
8,167

(1) 
Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.
(2) 
Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects.
(3) 
The retail marketing segment includes our wholly-owned retail marketing operations.
(4) 
Investment in Sunoco LP includes capital expenditures for the period prior to deconsolidation on July 1, 2015.
We currently expect capital expenditures for the full year 2016 to be within the following ranges:
 
Growth
 
Maintenance
 
Low
 
High
 
Low
 
High
Direct(1):
 
 
 
 
 
 
 
Midstream
$
1,200

 
$
1,250

 
$
110

 
$
120

Liquids transportation and services
 
 
 
 
 
 
 
NGL
1,150

 
1,200

 
25

 
30

Crude(3)
1,275

 
1,325

 
—

 
—

Interstate transportation and storage(2)(3)
375

 
415

 
140

 
145

Intrastate transportation and storage(2)
10

 
20

 
35

 
40

All other (including eliminations)
65

 
75

 
20

 
25

Total direct capital expenditures
4,075

 
4,285

 
330

 
360

Indirect(1):
 
 
 
 
 
 
 
Investment in Sunoco Logistics
2,600

 
2,800

 
75

 
85

Total projected capital expenditures
$
6,675

 
$
7,085

 
$
405

 
$
445

(1) 
Indirect capital expenditures comprise those funded by our publicly traded subsidiary; all other capital expenditures are reflected as direct capital expenditures.
(2) 
Net of amounts forecasted to be financed at the asset level with non-recourse debt of approximately $325 million.
(3) 
Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects.

16


SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions)
(unaudited)
 
Three Months Ended December 31,
 
2015
 
2014
Equity in earnings (losses) of unconsolidated affiliates:
 
 
 
Citrus
$
20

 
$
20

FEP
14

 
14

PES
(25
)
 
10

MEP
12

 
13

HPC
8

 
3

AmeriGas
(5
)
 
(2
)
Sunoco, LLC
3

 
—

Sunoco LP
85

 
—

Other
(31
)
 
9

Total equity in earnings of unconsolidated affiliates
$
81

 
$
67

 
 
 
 
Adjusted EBITDA related to unconsolidated affiliates(1):
 
 
 
Citrus
$
73

 
$
72

FEP
19

 
19

PES
(16
)
 
17

MEP
25

 
26

HPC
15

 
9

Sunoco, LLC
38

 
—

Sunoco LP
56

 
—

Other
16

 
21

Total Adjusted EBITDA related to unconsolidated affiliates
$
226

 
$
164

 
 
 
 
Distributions received from unconsolidated affiliates:
 
 
 
Citrus
$
37

 
$
42

FEP
18

 
19

PES
42

 
—

MEP
20

 
19

HPC
11

 
13

Sunoco LP
39

 
—

Other
12

 
10

Total distributions received from unconsolidated affiliates
$
179

 
$
103

(1) 
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

17

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