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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 21, 2018
Date of Report (Date of earliest event reported)
 
ENERGY TRANSFER PARTNERS, L.P.
(Exact name of Registrant as specified in its charter)
 
 
 
Delaware
1-31219
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))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company  ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨





Item 2.02. Results of Operations and Financial Condition.
On February 21, 2018, Energy Transfer Partners, L.P. issued a press release announcing its financial and operating results for the fourth quarter ended December 31, 2017. 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
 





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
 
 
 
 
Date:
February 21, 2018
By:
/s/ Thomas E. Long
 
 
 
Thomas E. Long
 
 
 
Chief Financial Officer



Exhibit


https://cdn.kscope.io/f4219cffa94f8ca6fcc6d43e919361de-etplogo2014a06.jpg
ENERGY TRANSFER PARTNERS
REPORTS FOURTH QUARTER RESULTS
Dallas – February 21, 2018 – Energy Transfer Partners, L.P. (NYSE: ETP) today reported its financial results for the quarter ended December 31, 2017. For the three months ended December 31, 2017 Energy Transfer Partners, L.P. (“ETP” or the “Partnership”) reported a net income of $1.10 billion, an increase of $1.43 billion compared to a net loss of $336 million for the same period last year primarily due to a deferred tax benefit resulting from the recent tax reform. Adjusted EBITDA for the three months ended December 31, 2017 totaled $1.94 billion, an increase of $453 million over the same period last year, reflecting significantly higher results from the midstream and crude oil transportation and services segments, as discussed in the segment results analysis below. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the three months ended December 31, 2017 totaled $1.20 billion, an increase of $240 million compared to the same period last year, primarily due to the increase in adjusted EBITDA.
ETP’s other recent key accomplishments include the following:
•
On February 14, 2018, ETP paid a quarterly distribution of $0.565 per unit ($2.26 annualized) on ETP Common Units for the quarter ended December 31, 2017. The Partnership’s distribution coverage ratio for the fourth quarter of 2017 was 1.30x.
•
ETP announced that Phase 1A and Phase 1B of the Rover pipeline were placed in service in August 2017 and December 2017, respectively.
•
In January 2018, ETP announced the entry into an agreement pursuant to which ETP will contribute certain compression assets to USA Compression Partners, LP for an aggregate consideration of $1.7 billion, consisting of $447 million in equity and $1.225 billion in cash. The transaction is subject to customary closing conditions and is expected to close in the first half of 2018.
•
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million.
•
As of December 31, 2017, ETP’s $5.00 billion revolving credit facilities had $2.34 billion of outstanding borrowings, and its leverage ratio, as defined by the credit agreement, was 3.96x.
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 22, 2018 to discuss the fourth quarter 2017 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 that owns and operates one of the largest and most diversified portfolios of energy assets in the United States. Strategically positioned in all of the major U.S. production basins, ETP owns and operates a geographically diverse portfolio of complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (NGL) and refined product transportation and terminalling assets; NGL fractionation assets; and various acquisition and marketing assets.  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.
Energy Transfer Equity, L.P. (NYSE:ETE) is a master limited partnership that 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).  ETE also owns Lake Charles LNG Company. On a consolidated basis, ETE’s family of companies owns and operates a diverse portfolio of natural gas, natural gas liquids, crude oil and refined products assets, as well as retail and wholesale motor fuel operations and LNG terminalling. For more information, visit the Energy Transfer Equity, L.P. website at www.energytransfer.com.
Forward-Looking Statements
This news release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results are discussed in the Partnership’s Annual Report on Form 10-K and other documents filed from time to

1


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
Energy Transfer
Investor Relations:
Lyndsay Hannah, Brent Ratliff, Helen Ryoo, 214-981-0795
or
Media Relations:
Vicki Granado, 214-840-5820

2


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(unaudited)
 
December 31,
 
2017
 
2016*
ASSETS
 
 
 
Current assets
$
6,528

 
$
5,643

 
 
 
 
Property, plant and equipment, net
58,437

 
50,917

 
 
 
 
Advances to and investments in unconsolidated affiliates
3,816

 
4,280

Other non-current assets, net
758

 
672

Intangible assets, net
5,311

 
4,696

Goodwill
3,115

 
3,897

Total assets
$
77,965

 
$
70,105

LIABILITIES AND EQUITY
 
 
 
Current liabilities
$
6,994

 
$
6,203

 
 
 
 
Long-term debt, less current maturities
32,687

 
31,741

Long-term notes payable – related party
—

 
250

Non-current derivative liabilities
145

 
76

Deferred income taxes
2,883

 
4,394

Other non-current liabilities
1,084

 
952

 
 
 
 
Commitments and contingencies
 
 
 
Series A Preferred Units
—

 
33

Redeemable noncontrolling interests
21

 
15

 
 
 
 
Equity:
 
 
 
Total partners’ capital
28,269

 
18,621

Noncontrolling interest
5,882

 
7,820

Total equity
34,151

 
26,441

Total liabilities and equity
$
77,965

 
$
70,105

*
During the fourth quarter of 2017, the Partnership changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories associated with the legacy Sunoco Logistics business were changed from the last-in, first-out (“LIFO”) method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.


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,
 
2017
 
2016*
 
2017
 
2016*
REVENUES
$
8,610

 
$
6,526

 
$
29,054

 
$
21,827

COSTS AND EXPENSES:
 
 
 
 
 
 
 
Cost of products sold
6,206

 
4,733

 
20,801

 
15,080

Operating expenses
567

 
480

 
2,170

 
1,839

Depreciation, depletion and amortization
619

 
517

 
2,332

 
1,986

Selling, general and administrative
99

 
122

 
434

 
348

Impairment losses
920

 
813

 
920

 
813

Total costs and expenses
8,411

 
6,665

 
26,657

 
20,066

OPERATING INCOME (LOSS)
199

 
(139
)
 
2,397

 
1,761

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest expense, net
(345
)
 
(336
)
 
(1,365
)
 
(1,317
)
Equity in earnings (losses) from unconsolidated affiliates
17

 
(201
)
 
156

 
59

Impairment of investment in an unconsolidated affiliate
(313
)
 
—

 
(313
)
 
(308
)
Gains on acquisitions
—

 
83

 
—

 
83

Losses on extinguishments of debt
(42
)
 
—

 
(42
)
 
—

Gains (losses) on interest rate derivatives
(9
)
 
167

 
(37
)
 
(12
)
Other, net
72

 
35

 
209

 
131

INCOME (LOSS) BEFORE INCOME TAX BENEFIT
(421
)
 
(391
)
 
1,005

 
397

Income tax benefit
(1,518
)
 
(55
)
 
(1,496
)
 
(186
)
NET INCOME (LOSS)
1,097

 
(336
)
 
2,501

 
583

Less: Net income attributable to noncontrolling interest
154

 
114

 
420

 
295

NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS
943

 
(450
)
 
2,081

 
288

General Partner’s interest in net income
263

 
208

 
990

 
948

Preferred Unitholders’ interest in net income
12

 
—

 
12

 
—

Class H Unitholder’s interest in net income
—

 
94

 
93

 
351

Class I Unitholder’s interest in net income
—

 
2

 
—

 
8

Common Unitholders’ interest in net income (loss)
$
668

 
$
(754
)
 
$
986

 
$
(1,019
)
NET INCOME (LOSS) PER COMMON UNIT:
 
 
 
 
 
 
 
Basic
$
0.57

 
$
(0.97
)
 
$
0.94

 
$
(1.38
)
Diluted
$
0.57

 
$
(0.97
)
 
$
0.93

 
$
(1.38
)
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
 
 
 
 
 
 
 
Basic
1,159.6

 
783.7

 
1,032.7

 
758.2

Diluted
1,162.9

 
783.7

 
1,037.8

 
758.2

*
During the fourth quarter of 2017, the Partnership changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories associated with the legacy Sunoco Logistics business were changed from the LIFO method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.



4


SUPPLEMENTAL INFORMATION
(Dollars and units in millions, except per unit amounts)
(unaudited)
 
Three Months Ended December 31,
 
Years Ended December 31,
 
2017
 
2016 (a)(b)
 
2017 (a)
 
2016 (a)(b)
Reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow (c):
 
 
 
 
 
 
 
Net income (loss)
$
1,097

 
$
(336
)
 
$
2,501

 
$
583

Interest expense, net
345

 
336

 
1,365

 
1,317

Gains on acquisitions
—

 
(83
)
 
—

 
(83
)
Impairment losses (d)
920

 
813

 
920

 
813

Income tax benefit
(1,518
)
 
(55
)
 
(1,496
)
 
(186
)
Depreciation, depletion and amortization
619

 
517

 
2,332

 
1,986

Non-cash compensation expense
17

 
20

 
74

 
80

(Gains) losses on interest rate derivatives
9

 
(167
)
 
37

 
12

Unrealized (gains) losses on commodity risk management activities
(39
)
 
35

 
(56
)
 
131

Losses on extinguishments of debt
42

 
—

 
42

 
—

Impairment of investments in unconsolidated affiliates (e)
313

 
—

 
313

 
308

Equity in (earnings) losses of unconsolidated affiliates (e)
(17
)
 
201

 
(156
)
 
(59
)
Adjusted EBITDA related to unconsolidated affiliates
219

 
235

 
984

 
946

Other, net
(69
)
 
(31
)
 
(148
)
 
(115
)
Adjusted EBITDA (consolidated)
1,938

 
1,485

 
6,712

 
5,733

Adjusted EBITDA related to unconsolidated affiliates
(219
)
 
(235
)
 
(984
)
 
(946
)
Distributable cash flow from unconsolidated affiliates
138

 
134

 
574

 
518

Interest expense, net
(345
)
 
(336
)
 
(1,365
)
 
(1,317
)
Preferred Unitholders’ distributions
(12
)
 
—

 
(12
)
 
—

Current income tax (expense) benefit
(13
)
 
40

 
(35
)
 
17

Maintenance capital expenditures
(143
)
 
(134
)
 
(429
)
 
(368
)
Other, net
(1
)
 
4

 
42

 
1

Distributable Cash Flow (consolidated)
1,343

 
958

 
4,503

 
3,638

Distributable Cash Flow attributable to PennTex (100%) (f)
—

 
(11
)
 
(19
)
 
(11
)
Distributions from PennTex to ETP (f)
—

 
8

 
8

 
16

Distributable cash flow attributable to noncontrolling interest in other consolidated subsidiaries
(151
)
 
(12
)
 
(350
)
 
(40
)
Distributable Cash Flow attributable to the partners of ETP
1,192

 
943

 
4,142

 
3,603

Transaction-related expenses
3

 
12

 
48

 
16

Distributable Cash Flow attributable to the partners of ETP, as adjusted
$
1,195

 
$
955

 
$
4,190

 
$
3,619

 
 
 
 
 
 
 
 
Distributions to the partners of ETP (g):
 
 
 
 
 
 
 
Limited Partners:
 
 
 
 
 
 
 
Common Units held by public
$
641

 
$
547

 
$
2,435

 
$
2,042

Common Units held by parent
16

 
14

 
61

 
20

General Partner interests
4

 
4

 
16

 
14

Incentive Distribution Rights (“IDRs”) held by parent
434

 
359

 
1,638

 
1,327

IDR relinquishments
(174
)
 
(145
)
 
(656
)
 
(423
)
Total distributions to be paid to partners
$
921

 
$
779

 
$
3,494

 
$
2,980

Common Units outstanding – end of period (g)(h)
1,164.1

 
1,050.1

 
1,164.1

 
1,050.1

Distribution coverage ratio (i)
1.30x

 
1.23x

 
1.20x

 
1.21x




5


(a)
For the years ended December 31, 2017 and 2016, the calculation of Distributable Cash Flow and the amounts reflected for distributions to partners and common units outstanding reflect the pro forma impacts of the Sunoco Logistics Merger as though the merger had occurred on January 1, 2016. As a result, the prior period amounts reported above differ from information previously reported by legacy ETP, as follows:
•
Distributable cash flow attributable to the partners of ETP includes amounts attributable to the partners of both legacy ETP and legacy Sunoco Logistics. Previously, the calculation of distributable cash flow attributable to the partners of ETP (as previously reported by legacy ETP) excluded the distributable cash flow attributable to Sunoco Logistics and only included distributions from legacy Sunoco Logistics to legacy ETP.
•
Distributable cash flow attributable to noncontrolling interest in other consolidated subsidiaries includes amounts attributable to the noncontrolling interests in the other consolidated subsidiaries of both legacy ETP and legacy Sunoco Logistics.
•
The transaction-related expenses adjustment in distributable cash flow attributable to the partners of ETP, as adjusted, includes amounts incurred by both legacy ETP and legacy Sunoco Logistics.
•
Distributions to limited partners include distributions paid on the common units of both legacy ETP and legacy Sunoco Logistics but exclude the following distributions in the prior periods on units that were cancelled in the merger, which comprise the following: (i) distributions paid by legacy Sunoco Logistics on its common units held legacy ETP and (ii) distributions paid by legacy ETP on its Class H units held by ETE.
•
Distributions on General Partner interests and incentive distribution rights are reflected on a pro forma basis, based on the pro forma cash distributions to limited partners and the current distribution waterfall per the limited partnership agreement (i.e., the legacy Sunoco Logistics distribution waterfall).
•
Common units outstanding for the pre-merger periods reflect (i) the legacy ETP common units outstanding at the end of the period multiplied by a factor of 1.5x and (ii) the legacy Sunoco Logistics common units outstanding at the end of the period minus 67.1 million legacy Sunoco Logistics common units held by ETP, which were cancelled in connection with the closing of the merger.
(b)
During the fourth quarter of 2017, the Partnership changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories associated with the legacy Sunoco Logistics business were changed from the LIFO method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported. Certain other prior period amounts have also been reclassified to conform to the current period presentation, including a reclassification between capitalized interest and AFUDC from the nine months ended September 30, 2017.
(c)
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 segment margin, operating income, net income, and cash flow from operating activities.
Definition of Adjusted EBITDA
We define Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, 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, non-cash impairment charges, losses on extinguishments of debt 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 our 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

6


business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.
Definition of Distributable Cash Flow
We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less maintenance capital expenditures and a proportionate amount of the distributions to be paid on our redeemable perpetual preferred units. Non-cash items include depreciation, depletion and amortization, non-cash compensation expense, amortization included in interest 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, non-cash impairment charges, losses on extinguishments of debt 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). For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investee’s distributable cash flow.
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 our subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to our partners, we have reported Distributable Cash Flow attributable to partners, 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 our partners 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 partners is net of distributions to be paid by the subsidiary to the noncontrolling interests.
For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related and non-recurring expenses that are included in net income are excluded.
(d)
During the three months ended December 31, 2017, we recorded goodwill impairments of $223 million related to the compression business, $229 million related to the entity that owns the general partner of Panhandle, $262 million related to the interstate transportation and storage segment, and $79 million related to the NGL and refined products transportation and services segment. In addition, impairment losses for the three months ended December 31, 2017 also include a $127 million impairment to the property, plant and equipment related to Sea Robin.
During the three months ended December 31, 2016, we recorded goodwill impairments of $638 million in the interstate transportation and storage segment and $32 million in the midstream segment. In addition, impairment losses for the three months ended December 31, 2016 also include a $133 million impairment to property, plant and equipment in the interstate transportation and storage segment.
(e)
For the three months ended December 31, 2017, impairment of investments in unconsolidated affiliates includes non-cash impairments of the Partnership’s investments in FEP and HPC of $141 million and $172 million, respectively, and equity in losses of affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
(f)
Beginning with the second quarter of 2017, PennTex became a wholly-owned subsidiary of ETP.  The amounts reflected above for PennTex relate only to the first quarter of 2017, and no distributable cash flow has been attributed to noncontrolling interests in PennTex subsequent to March 31, 2017.
(g)
Distributions on ETP Common Units and the number of ETP Common Units outstanding at the end of the period, both as reflected above, exclude amounts related to ETP Common Units held by subsidiaries of ETP.
(h)
Reflects the sum of (i) the ETP Common Units outstanding at the end of period multiplied by a factor of 1.5x and (ii) the Sunoco Logistics Common Units outstanding at end of period minus 67.1 million Sunoco Logistics Common Units held by ETP, which units were cancelled in connection with the closing of the merger.

7


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

8


SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)
 
Three Months Ended December 31,
 
2017
 
2016
Segment Adjusted EBITDA:
 
 
 
Intrastate transportation and storage
$
146

 
$
152

Interstate transportation and storage
298

 
269

Midstream
393

 
258

NGL and refined products transportation and services (1)
433

 
424

Crude oil transportation and services (1)
544

 
237

All other
124

 
145

 
$
1,938

 
$
1,485

(1) 
Subsequent to the Sunoco Logistics Merger, the Partnership’s reportable segments were revised. Amounts reflected in prior periods have been retrospectively adjusted to conform to the current reportable segment presentation for NGL and refined products transportation and services and crude oil transportation and services.
In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment Margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment Margin is similar to the GAAP measure of gross margin, except that Segment Margin excludes charges for depreciation, depletion and amortization.
In addition, for certain segments, the sections below include information on the components of Segment Margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of Segment Margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of Segment Margin are calculated consistent with the calculation of Segment Margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.

9


Following is a reconciliation of segment margin to operating income (loss), as reported in the Partnership’s consolidated statements of operations:
 
Three Months Ended
December 31,
 
2017
 
2016
Intrastate transportation and storage
$
205

 
$
191

Interstate transportation and storage
268

 
240

Midstream
568

 
448

NGL and refined products transportation and services
582

 
530

Crude oil transportation and services
683

 
307

All other
102

 
72

Intersegment eliminations
(4
)
 
5

Total segment margin
2,404

 
1,793

Less:
 
 
 
Operating expenses
567

 
480

Depreciation, depletion and amortization
619

 
517

Selling, general and administrative
99

 
122

Impairment losses
920

 
813

Operating income (loss)
$
199

 
$
(139
)










10


Intrastate Transportation and Storage
 
Three Months Ended December 31,
 
2017
 
2016
Natural gas transported (BBtu/d)
8,944

 
8,134

Revenues
$
741

 
$
756

Cost of products sold
536

 
565

Segment margin
205

 
191

Unrealized gains on commodity risk management activities
(21
)
 
(5
)
Operating expenses, excluding non-cash compensation expense
(44
)
 
(45
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(5
)
 
(5
)
Adjusted EBITDA related to unconsolidated affiliates
11

 
16

Segment Adjusted EBITDA
$
146

 
$
152

Transported volumes increased primarily due to higher demand for exports to Mexico, more favorable market pricing, and the addition of new pipelines to our intrastate pipeline system. These increases were partially offset by lower production volumes in the Barnett Shale region.
For the three months ended December 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impacts of the following:
•
a decrease of $13 million in transportation fees due to renegotiated contracts resulting in lower billed volumes. This decrease was offset by increased margin from optimization activity recorded in natural gas sales and other; and
•
a decrease of $5 million in adjusted EBITDA related to unconsolidated affiliates primarily due to a decrease of $7 million due to a reserve recorded pursuant to the bankruptcy filing of a transport customer on our Louisiana intrastate system and a decrease of $2 million due to lower demand volumes related to renegotiation of a contract on our Louisiana intrastate pipeline system, offset by an increase of $4 million related to two new joint venture pipelines placed in service in 2017; offset by
•
an increase of $9 million in natural gas sales and other (excluding net changes in unrealized gains and losses of $12 million) primarily due to higher realized gains from pipeline optimization activity; and
•
an increase of $2 million in storage margin (excluding net changes in unrealized gains and losses of $4 million related to fair value inventory adjustments and unrealized gains and losses on derivatives).

11


Interstate Transportation and Storage
 
Three Months Ended December 31,
 
2017
 
2016
Natural gas transported (BBtu/d)
7,185

 
5,322

Natural gas sold (BBtu/d)
18

 
17

Revenues
$
268

 
$
240

Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(76
)
 
(79
)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(13
)
 
(11
)
Adjusted EBITDA related to unconsolidated affiliates
115

 
118

Other
4

 
1

Segment Adjusted EBITDA
$
298

 
$
269

Transported volumes reflected increases of 812 BBtu/d due to the partial in-service of the Rover pipeline, 410 BBtu/d on the Tiger pipeline as a result of an increase in production in the Haynesville Shale and deliveries into third party storage and the intrastate markets, and 390 BBtu/d and 356 BBtu/d on the Trunkline and Panhandle pipelines, respectively, resulting from higher demand due to colder weather.
For the three months ended December 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net effect of the following:
•
a net increase of $28 million in revenues primarily due to additional revenues of $44 million from the placement in partial service of the Rover pipeline. This increase was partially offset by a decrease in reservation and gas parking and storage revenues of $13 million on the Panhandle and Trunkline pipelines due to lack of customer demand as a result of weak spreads. In addition, revenues on the Tiger pipeline decreased $3 million due to contract restructuring;
•
a decrease in operating expenses of $3 million primarily due to lower maintenance expense and lower leased storage expense due to expiration of a lease; and
•
an increase in other of $3 million primarily due to higher tax gross up income from reimbursable projects; offset by
•
a decrease in adjusted EBITDA from unconsolidated affiliates of $3 million primarily due to higher maintenance expense on Citrus and lower earnings from Midcontinent Express resulting from lower margins and higher ad valorem taxes.

12


Midstream
 
Three Months Ended December 31,
 
2017
 
2016
Gathered volumes (BBtu/d)
11,525

 
9,694

NGLs produced (MBbls/d)
502

 
431

Equity NGLs produced (MBbls/d)
27

 
29

Revenues
$
1,926

 
$
1,414

Cost of products sold
1,358

 
966

Segment margin
568

 
448

Unrealized losses on commodity risk management activities
3

 
15

Operating expenses, excluding non-cash compensation expense
(168
)
 
(168
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(18
)
 
(42
)
Adjusted EBITDA related to unconsolidated affiliates
8

 
5

Segment Adjusted EBITDA
$
393

 
$
258

Gathered volumes and NGL production increased primarily due to recent acquisitions, including PennTex, and gains in the Permian, Northeast and South Texas regions, partially offset by basin declines in the North Texas and Mid-Continent/Panhandle regions.
For the three months ended December 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:
•
an increase of $61 million (excluding net changes in unrealized gains and losses of $12 million) in non-fee based margin due to higher crude oil and NGL prices;
•
an increase of $40 million in fee-based revenue due to minimum volume commitments in the South Texas region as well as volume increases in the Permian, Northeast and South Texas regions. These increases were partially offset by volume declines in North Texas and the Mid-Continent/Panhandle regions;
•
an increase of $7 million in fee-based revenue due to recent acquisitions, including PennTex; and
•
a decrease of $24 million in selling, general and administrative expenses primarily due to certain reserves that were recorded in the fourth quarter of 2016.


13


NGL and Refined Products Transportation and Services
 
Three Months Ended
December 31,
 
2017
 
2016
NGL transportation volumes (MBbls/d)
963

 
791

Refined products transportation volumes (MBbls/d)
618

 
627

NGL and refined products terminal volumes (MBbls/d)
792

 
818

NGL fractionation volumes (MBbls/d)
455

 
394

Revenues
$
2,533

 
$
2,080

Cost of products sold
1,951

 
1,550

Segment margin
582

 
530

Unrealized (gains) losses on commodity risk management activities
(28
)
 
16

Operating expenses, excluding non-cash compensation expense
(120
)
 
(122
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(15
)
 
(15
)
Adjusted EBITDA related to unconsolidated affiliates
14

 
14

Other
—

 
1

Segment Adjusted EBITDA
$
433

 
$
424

NGL transportation volumes increased from the Permian, Barnett/East Texas, Eagle Ford, and Louisiana. Refined products transportation volumes decreased for the three months ended December 31, 2017 compared to the same period last year primarily due to lower volumes from our Midwest refineries.
NGL and refined products terminal volumes decreased for the three months ended December 31, 2017 as compared to the same period last year primarily due to the sale of one of our refined product terminals in April 2017.
Average volumes fractionated at our Mont Belvieu, Texas fractionation facility increased 19% for the three months ended December 31, 2017 compared to the same period last year primarily due to the commissioning of our fourth fractionator in October of 2016, which has a capacity of 120 MBbls/d, as well as increased producer volumes as mentioned above.
For the three months ended December 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to net impact of the following:
•
an increase in transportation margin of $33 million primarily due to increased throughput on our Texas NGL pipelines resulting from increased producer volumes as noted above and the ramp up of volumes on our Mariner East system;
•
an increase in fractionation and refinery services margin of $27 million (excluding changes in unrealized gains and losses of $1 million) primarily due to higher NGL volumes from most major producing regions feeding our Mont Belvieu fractionation facility as well as the placing in service of our fourth fractionator at Mont Belvieu, Texas, as noted above; and
•
an increase in terminal services margin of $10 million due to higher throughput volumes at our Marcus Hook and Nederland NGL terminals; offset by
•
a decrease in marketing margin of $56 million (excluding changes in unrealized gains and losses of $43 million) primarily due to the timing of the recognition of margin from optimization activities; and
•
a decrease in storage margin of $6 million primarily due to fewer stored volumes as a result of the expiration of various contracts.


14


Crude Oil Transportation and Services
 
Three Months Ended
December 31,
 
2017
 
2016
Crude Transportation Volumes (MBbls/d)
3,816

 
2,784

Crude Terminals Volumes (MBbls/d)
2,059

 
1,573

Revenues
$
3,938

 
$
2,393

Cost of products sold
3,255

 
2,086

Segment margin
683

 
307

Unrealized losses on commodity risk management activities
4

 
2

Operating expenses, excluding non-cash compensation expense
(125
)
 
(62
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(20
)
 
(14
)
Adjusted EBITDA related to unconsolidated affiliates
2

 
4

Segment Adjusted EBITDA
$
544

 
$
237

For the three months ended December 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the following:
•
an increase of $247 million resulting primarily from placing our Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas and the addition of certain joint venture crude transportation assets;
•
an increase of $57 million from existing transport assets due to increased volumes throughout the system;
•
an increase of $61 million in margin from our crude oil acquisition and marketing business; and
•
an increase of $12 million from Nederland terminal due to increased crude throughput fees and tank rentals; offset by
•
an increase of $63 million in operating expenses primarily due to an increase of $38 million resulting primarily from placing the Bakken Pipeline, as well as certain joint venture crude transportation assets in service in the first and second quarter of 2017, and an increase of $22 million from existing transport assets mainly due to higher utilities, line testing, environmental costs and maintenance dredging; and
•
an increase of $6 million in selling, general and administrative expenses primarily due to merger costs and legal fees.





15


All Other
 
Three Months Ended December 31,
 
2017
 
2016
Revenue
$
652

 
$
751

Cost of products sold
550

 
679

Segment margin
102

 
72

Unrealized losses on commodity risk management activities
3

 
7

Operating expenses, excluding non-cash compensation expense
(31
)
 
(22
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(21
)
 
(26
)
Adjusted EBITDA related to unconsolidated affiliates
69

 
77

Other
—

 
24

Elimination
2

 
13

Segment Adjusted EBITDA
$
124

 
$
145

Amounts reflected in our all other segment primarily include:
•
our equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, our investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, our investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units;
•
our natural gas marketing and compression operations;
•
a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and
•
our investment in coal handling facilities.
For the three months ended December 31, 2017 compared to the same period last year, Segment Adjusted EBITDA decreased primarily due to the net impact of the following:
•
a decrease of $24 million related to the termination of management fees paid by ETE that ended in 2016;
•
a decrease of $6 million in Adjusted EBITDA related to our investment in Sunoco LP; and
•
a decrease of $10 million in the mark-to-market of physical system gas and settled derivatives related to our marketing operation; partially offset by
•
an increase of $6 million in packaging and technical services revenue in the compression business; and
•
an increase of $6 million in power trading activities and increased trading margin from the liquidation of crude inventories.


16


SUPPLEMENTAL INFORMATION ON LIQUIDITY
(In millions)
(unaudited)
 
Facility Size
 
Funds Available at December 31, 2017
 
Maturity Date
ETP Five-Year Revolving Credit Facility
$
4,000

 
$
1,558

 
December 1, 2022
ETP 364-Day Revolving Credit Facility
1,000

 
950

 
November 30, 2018
 
$
5,000

 
$
2,508

 
 

17


SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions)
(unaudited)
 
Three Months Ended December 31,
 
2017
 
2016
Equity in earnings (losses) of unconsolidated affiliates:
 
 
 
Citrus
$
58

 
$
22

FEP
14

 
13

MEP
9

 
9

HPC(1)
(185
)
 
8

Sunoco LP(2)
101

 
(265
)
Other
20

 
12

Total equity in earnings (losses) of unconsolidated affiliates
$
17

 
$
(201
)
 
 
 
 
Adjusted EBITDA related to unconsolidated affiliates:
 
 
 
Citrus
$
74

 
$
78

FEP
19

 
19

MEP
22

 
21

HPC
6

 
16

Sunoco LP
57

 
63

Other
41

 
38

Total Adjusted EBITDA related to unconsolidated affiliates
$
219

 
$
235

 
 
 
 
Distributions received from unconsolidated affiliates:
 
 
 
Citrus
$
43

 
$
32

FEP
19

 
18

MEP
8

 
18

HPC
13

 
13

Sunoco LP
36

 
36

Other
22

 
20

Total distributions received from unconsolidated affiliates
$
141

 
$
137

(1) 
For the three months ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
(2) 
For the three months ended December 31, 2017 and 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $17 million and $277 million, respectively.

18