Document





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

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
August 8, 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 August 8, 2018, Energy Transfer Partners, L.P. issued a press release announcing its financial and operating results for the second quarter ended June 30, 2018. 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:
August 8, 2018
By:
/s/ Thomas E. Long
 
 
 
Thomas E. Long
 
 
 
Chief Financial Officer



Exhibit


http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12397779&doc=3
ENERGY TRANSFER PARTNERS
REPORTS SECOND QUARTER RESULTS
Dallas – August 8, 2018Energy Transfer Partners, L.P. (NYSE: ETP) (“ETP” or the “Partnership”) today reported its financial results for the quarter ended June 30, 2018. For the three months ended June 30, 2018, net income was $602 million and Adjusted EBITDA was $2.05 billion. Adjusted EBITDA increased $506 million compared to the three months ended June 30, 2017, reflecting an increase of $320 million in Adjusted EBITDA from the crude oil transportation and services segment, as well as higher results from several of the other segments, as discussed in the segment results analysis below. Net income increased $306 million compared to the three months ended June 30, 2017, primarily due to increased operating income and equity in earnings of unconsolidated affiliates. Distributable Cash Flow attributable to partners, as adjusted, for the three months ended June 30, 2018 totaled $1.32 billion, an increase of $371 million compared to the three months ended June 30, 2017, primarily due to the increase in Adjusted EBITDA.
ETP’s other recent key accomplishments include the following:
In August 2018, ETP and Energy Transfer Equity, L.P. (“ETE”) entered into a merger agreement pursuant to which ETP will merge with a wholly-owned subsidiary of ETE, with ETP unitholders (other than ETE and its subsidiaries) receiving 1.28 ETE common units in exchange for each ETP common unit they own.  The transaction is expected to close in the fourth quarter of 2018, subject to the approval by a majority of the unaffiliated unitholders of ETP and other customary closing conditions.
In July 2018, ETP announced a quarterly distribution of $0.565 per unit ($2.260 annualized) on ETP common units for the quarter ended June 30, 2018.
In July 2018, ETP issued 17.8 million of its 7.625% Series D Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $445 million.
In July 2018, ETP placed into service Fractionator V, a 120,000 barrel per day fractionator located in Mont Belvieu, Texas that is fully subscribed under multiple, long-term fixed-fee contacts.
In June 2018, ETP issued $3.00 billion aggregate principal amount of senior notes and used the net proceeds to redeem outstanding senior notes, to repay borrowings outstanding under ETP’s revolving credit facility and for general partnership purposes.
In May 2018, ETP announced the receipt of approval to place the remaining portion of Phase 2 of the Rover pipeline in service effective June 1, 2018, allowing for use of 100 percent of Rover’s 3.25 Bcf per day mainline capacity.
In May 2018, ETP placed into service Red Bluff Express pipeline, a 1.4 Bcf per day natural gas pipeline that runs through the heart of the Delaware basin and connects the ETP Orla Plant and multiple third-party plants to ETP’s Waha Oasis Header.
As of June 30, 2018, ETP’s $5.00 billion revolving credit facilities had $3.61 billion of available capacity, and its leverage ratio, as defined by the credit agreement, was 3.87x.
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, August 9, 2018 to discuss the second quarter 2018 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’s operations include 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; 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 and the general partner of USA Compression Partners, LP (NYSE: USAC). On a consolidated

1



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 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, 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)
 
June 30, 2018
 
December 31, 2017
ASSETS
 
 
 
 
 
 
 
Current assets
$
6,547

 
$
6,528

 
 
 
 
Property, plant and equipment, net
59,776

 
58,437

 
 
 
 
Advances to and investments in unconsolidated affiliates
3,636

 
3,816

Other non-current assets, net
762

 
758

Intangible assets, net
4,988

 
5,311

Goodwill
2,861

 
3,115

Total assets
$
78,570

 
$
77,965

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
Current liabilities
$
6,641

 
$
6,994

 
 
 
 
Long-term debt, less current maturities
33,741

 
32,687

Non-current derivative liabilities
135

 
145

Deferred income taxes
2,917

 
2,883

Other non-current liabilities
1,079

 
1,084

 
 
 
 
Commitments and contingencies
 
 
 
Redeemable noncontrolling interests
21

 
21

 
 
 
 
Equity:
 
 
 
Total partners’ capital
27,865

 
28,269

Noncontrolling interest
6,171

 
5,882

Total equity
34,036

 
34,151

Total liabilities and equity
$
78,570

 
$
77,965


3



ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2018
 
2017 (a)
 
2018
 
2017 (a)
REVENUES
$
9,410

 
$
6,576

 
$
17,690

 
$
13,471

COSTS AND EXPENSES:
 
 
 
 
 
 
 
Cost of products sold
7,140

 
4,624

 
13,128

 
9,674

Operating expenses
627

 
539

 
1,231

 
1,031

Depreciation, depletion and amortization
588

 
557

 
1,191

 
1,117

Selling, general and administrative
112

 
120

 
224

 
230

Total costs and expenses
8,467

 
5,840

 
15,774

 
12,052

OPERATING INCOME
943

 
736

 
1,916

 
1,419

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest expense, net
(358
)
 
(336
)
 
(704
)
 
(668
)
Equity in earnings (losses) of unconsolidated affiliates
106

 
(61
)
 
34

 
12

Gain on Sunoco LP common unit repurchase

 

 
172

 

Loss on deconsolidation of CDM
(86
)
 

 
(86
)
 

Gains (losses) on interest rate derivatives
20

 
(25
)
 
72

 
(20
)
Other, net
46

 
61

 
106

 
80

INCOME BEFORE INCOME TAX EXPENSE
671

 
375

 
1,510

 
823

Income tax expense
69

 
79

 
29

 
134

NET INCOME
602

 
296

 
1,481

 
689

Less: Net income attributable to noncontrolling interest
170

 
94

 
334

 
156

NET INCOME ATTRIBUTABLE TO PARTNERS
432

 
202

 
1,147

 
533

Preferred Unitholders’ interest in net income
30

 

 
54

 

General Partner’s interest in net income
402

 
251

 
804

 
457

Class H Unitholder’s interest in net income

 

 

 
93

Common Unitholders’ interest in net income (loss)
$

 
$
(49
)
 
$
289

 
$
(17
)
NET INCOME (LOSS) PER COMMON UNIT:
 
 
 
 
 
 
 
Basic
$
(0.01
)
 
$
(0.04
)
 
$
0.23

 
$
(0.02
)
Diluted
$
(0.01
)
 
$
(0.04
)
 
$
0.23

 
$
(0.02
)
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
 
 
 
 
 
 
 
Basic
1,165.4

 
1,021.7

 
1,164.6

 
922.5

Diluted
1,165.4

 
1,021.7

 
1,169.4

 
922.5

(a)
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 three months and six months ended June 30, 2017.

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SUPPLEMENTAL INFORMATION
(Dollars and units in millions)
(unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2018
 
2017 (a)(b)
 
2018
 
2017 (a)(b)
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (c):
 
 
 
 
 
 
 
Net income
$
602

 
$
296

 
$
1,481

 
$
689

Interest expense, net
358

 
336

 
704

 
668

Income tax expense
69

 
79

 
29

 
134

Depreciation, depletion and amortization
588

 
557

 
1,191

 
1,117

Non-cash compensation expense
21

 
15

 
41

 
38

(Gains) losses on interest rate derivatives
(20
)
 
25

 
(72
)
 
20

Unrealized (gains) losses on commodity risk management activities
265

 
(34
)
 
352

 
(98
)
Gain on Sunoco LP common unit repurchase

 

 
(172
)
 

Loss on deconsolidation of CDM
86

 

 
86

 

Equity in (earnings) losses of unconsolidated affiliates
(106
)
 
61

 
(34
)
 
(12
)
Adjusted EBITDA related to unconsolidated affiliates
228

 
247

 
413

 
486

Other, net
(40
)
 
(37
)
 
(87
)
 
(52
)
Adjusted EBITDA (consolidated)
2,051

 
1,545

 
3,932

 
2,990

Adjusted EBITDA related to unconsolidated affiliates
(228
)
 
(247
)
 
(413
)
 
(486
)
Distributable cash flow from unconsolidated affiliates
141

 
123

 
266

 
267

Interest expense, net
(358
)
 
(336
)
 
(704
)
 
(668
)
Preferred unitholders’ distributions
(30
)
 

 
(54
)
 

Current income tax (expense) benefit
22

 
(12
)
 
22

 
(13
)
Maintenance capital expenditures
(116
)
 
(107
)
 
(204
)
 
(167
)
Other, net
5

 
12

 
8

 
27

Distributable Cash Flow (consolidated)
1,487

 
978

 
2,853

 
1,950

Distributable Cash Flow attributable to PennTex Midstream Partners, LP (“PennTex”) (100%) (d)

 

 

 
(19
)
Distributions from PennTex to ETP (d)

 

 

 
8

Distributable cash flow attributable to noncontrolling interest in other non-wholly-owned consolidated subsidiaries
(180
)
 
(57
)
 
(327
)
 
(80
)
Distributable Cash Flow attributable to the partners of ETP
1,307

 
921

 
2,526

 
1,859

Transaction-related expenses
10

 
25

 
14

 
32

Distributable Cash Flow attributable to the partners of ETP, as adjusted
$
1,317

 
$
946

 
$
2,540

 
$
1,891

 
 
 
 
 
 
 
 
Distributions to partners:
 
 
 
 
 
 
 
Limited Partners:
 
 
 
 
 
 
 
Common Units held by public
$
644

 
$
589

 
$
1,286

 
$
1,156

Common Units held by parent
15

 
15

 
31

 
30

General Partner interests and Incentive Distribution Rights (“IDRs”) held by parent
451

 
400

 
900

 
781

IDR relinquishments
(42
)
 
(162
)
 
(84
)
 
(319
)
Total distributions to be paid to partners
$
1,068

 
$
842

 
$
2,133

 
$
1,648

Common Units outstanding – end of period
1,166.4

 
1,092.6

 
1,166.4

 
1,092.6

Distribution coverage ratio (e)
1.23x

 
1.12x

 
1.19x

 
1.15x


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(a)
For the three and six months ended June 30, 2017, 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, 2017. As a result, the prior period amounts reported above reflect the following pro forma impacts:
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).
(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 three months and six months ended June 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. 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 business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.

6



Definition of Distributable Cash Flow
We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less distributions to preferred unitholders and maintenance capital expenditures. 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)
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.
(e)
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.

7



SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)
 
Three Months Ended
June 30,
 
2018
 
2017
Segment Adjusted EBITDA:
 
 
 
Intrastate transportation and storage
$
208

 
$
148

Interstate transportation and storage
330

 
262

Midstream
414

 
412

NGL and refined products transportation and services
461

 
388

Crude oil transportation and services
548

 
228

All other
90

 
107

 
$
2,051

 
$
1,545

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.
Following is a reconciliation of segment margin to operating income, as reported in the Partnership’s consolidated statements of operations:
 
Three Months Ended
June 30,
 
2018
 
2017
Intrastate transportation and storage
$
267

 
$
202

Interstate transportation and storage
328

 
207

Midstream
593

 
571

NGL and refined products transportation and services
587

 
516

Crude oil transportation and services
442

 
374

All other
57

 
76

Intersegment eliminations
(4
)
 
6

Total segment margin
2,270

 
1,952

 
 
 
 
Less:
 
 
 
Operating expenses
627

 
539

Depreciation, depletion and amortization
588

 
557

Selling, general and administrative
112

 
120

Operating income
$
943

 
$
736


8



Intrastate Transportation and Storage
 
Three Months Ended
June 30,
 
2018
 
2017
Natural gas transported (BBtu/d)
10,327

 
9,261

Revenues
$
813

 
$
753

Cost of products sold
546

 
551

Segment margin
267

 
202

Unrealized gains on commodity risk management activities
(8
)
 
(21
)
Operating expenses, excluding non-cash compensation expense
(51
)
 
(46
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(7
)
 
(5
)
Adjusted EBITDA related to unconsolidated affiliates
7

 
18

Segment Adjusted EBITDA
$
208

 
$
148

Transported volumes increased primarily due to favorable market pricing. In addition, beginning in April 2018, transported volumes also reflected Regency Intrastate Gas LP (“RIGS”) as a consolidated subsidiary. RIGS was previously reflected as an unconsolidated affiliate until ETP acquired the remaining interest in April 2018.
Segment Adjusted EBITDA. For the three months ended June 30, 2018 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 $47 million in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity;
a net increase of $5 million due to the consolidation of RIGS beginning in April 2018, as discussed above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $26 million, $6 million and $2 million, respectively, and a decrease of $13 million in Adjusted EBITDA related to unconsolidated affiliates;
an increase of $4 million in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, primarily due to higher demand on existing pipelines; and
an increase of $3 million in realized storage margin primarily due to higher realized derivative gains; partially offset by
a decrease of $2 million in retained fuel revenues as a result of lower natural gas pricing.
Interstate Transportation and Storage
 
Three Months Ended
June 30,
 
2018
 
2017
Natural gas transported (BBtu/d)
8,707

 
5,299

Natural gas sold (BBtu/d)
17

 
17

Revenues
$
328

 
$
207

Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(105
)
 
(67
)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(17
)
 
(7
)
Adjusted EBITDA related to unconsolidated affiliates
123

 
128

Other
1

 
1

Segment Adjusted EBITDA
$
330

 
$
262

Transported volumes reflected an increase of 1,748 BBtu/d as a result of the partial in service of the Rover pipeline; increases of 654 BBtu/d and 425 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to increased utilization of higher contracted capacity; an increase of 350 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale and deliveries into intrastate markets; and an increase of 200 BBtu/d on the Transwestern pipeline resulting from favorable opportunities in the midcontinent and Waha areas from the Permian supply basin.

9



Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:
an increase of $68 million from the partial in service of the Rover pipeline with increases of $105 million in revenues, $30 million in operating expenses and $7 million in selling, general and administrative expenses; and
an aggregate increase of $19 million in revenues, excluding the incremental revenue related to the Rover pipeline in service discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines, partially offset by $3 million of lower revenues on the Tiger pipeline due to a customer contract restructuring; partially offset by
an increase of $8 million in operating expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to higher maintenance project costs;
an increase of $3 million in selling, general and administrative expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to a reimbursement of legal fees and a franchise tax settlement received in 2017; and
a decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower sales of short-term firm capacity on Citrus.
Midstream
 
Three Months Ended
June 30,
 
2018
 
2017
Gathered volumes (BBtu/d)
11,576

 
10,961

NGLs produced (MBbls/d)
513

 
474

Equity NGLs (MBbls/d)
31

 
28

Revenues
$
1,874

 
$
1,615

Cost of products sold
1,281

 
1,044

Segment margin
593

 
571

Unrealized gains on commodity risk management activities

 
(3
)
Operating expenses, excluding non-cash compensation expense
(169
)
 
(152
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(20
)
 
(11
)
Adjusted EBITDA related to unconsolidated affiliates
9

 
7

Other
1

 

Segment Adjusted EBITDA
$
414

 
$
412

Gathered volumes and NGL production increased primarily due to increases in the Permian and Northeast regions, partially offset by smaller declines in other regions.
Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net effects of the following:
an increase of $17 million in fee-based margin due to growth in the Permian and Northeast regions, offset by declines in the South Texas, North Texas and midcontinent/Panhandle regions;
an increase of $6 million in non-fee-based margin primarily due to higher crude oil and NGL prices;
an increase of $2 million in non-fee-based margin due to increased throughput volume in the Permian region; and
an increase of $2 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by
an increase of $17 million in operating expenses primarily due to increases of $6 million in outside services, $5 million in materials, $2 million in employee costs and $2 million in ad valorem taxes; and
an increase of $9 million in selling, general and administrative expenses primarily due to a favorable impact recorded in the prior period from the adjustment of certain reserves in connection with contingent matters.

10



NGL and Refined Products Transportation and Services
 
Three Months Ended
June 30,
 
2018
 
2017
NGL transportation volumes (MBbls/d)
967

 
835

Refined products transportation volumes (MBbls/d)
637

 
643

NGL and refined products terminal volumes (MBbls/d)
789

 
767

NGL fractionation volumes (MBbls/d)
473

 
431

Revenues
$
2,568

 
$
1,779

Cost of products sold
1,981

 
1,263

Segment margin
587

 
516

Unrealized (gains) losses on commodity risk management activities
13

 
(4
)
Operating expenses, excluding non-cash compensation expense
(141
)
 
(125
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(17
)
 
(17
)
Adjusted EBITDA related to unconsolidated affiliates
19

 
18

Segment Adjusted EBITDA
$
461

 
$
388

NGL transportation volumes increased primarily from the Permian region resulting from a ramp up in production from existing customers. Refined products transportation volumes decreased slightly primarily due to lower throughput volumes from the Midwest region due to end user operational issues, partially offset by increased throughput volumes from the Southwest region due to increased demand.
NGL and refined products terminal volumes increased primarily due to more volumes loaded at our Nederland terminal as propane export demand increased, as well as higher refined products throughput volumes at our Eagle Point terminal, partially offset by lower throughput volumes at our Marcus Hook Industrial Complex primarily due to Mariner East 1 system downtime during the second quarter of 2018.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased primarily due to increased volumes from Permian producers.
Segment Adjusted EBITDA. For the three months ended June 30, 2018 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 impacts of the following:
an increase of $49 million in transportation margin due to a $43 million increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines, an $11 million increase resulting from a reclassification between our transportation and fractionation margins, a $4 million increase due to higher throughput on Mariner West and a $2 million increase on Mariner South primarily due to system downtime in the prior period. These increases were partially offset by an $11 million decrease resulting from lower throughput on Mariner East 1 due to system downtime in the second quarter of 2018;
an increase of $23 million in marketing margin (excluding a net change of $17 million in unrealized gains and losses) due to gains of $10 million from our butane blending operations, a $9 million increase from sales of domestic propane and other products at our Marcus Hook Industrial Complex and a $4 million increase from optimizing sales of purity product from our Mont Belvieu fractionators;
an increase of $11 million in fractionation and refinery services margin due to a $14 million increase resulting from higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility, a $6 million increase from blending gains as a result of improved market pricing and a $2 million increase from Mariner South as more cargoes were loaded at Mariner South. These increases were partially offset by an $11 million decrease resulting from a reclassification between our transportation and fractionation margins; and
an increase of $10 million in terminal services margin due to a $7 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018 and a $5 million increase at our Nederland terminal due to increased demand for propane exports. These increases were partially offset by a $2 million decrease due to the effect of Mariner East pipeline system downtime on our Marcus Hook Industrial Complex; partially offset by

11



an increase of $16 million in operating expenses primarily due to a $7 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, a $4 million increase in utilities and ad valorem taxes on the fractionators, and a $3 million increase in overhead costs; and
a decrease of $5 million in storage margin primarily due to the expiration and amendments to various NGL and refined products storage contracts.
Crude Oil Transportation and Services
 
Three Months Ended
June 30,
 
2018
 
2017
Crude transportation volumes (MBbls/d)
4,242

 
3,452

Crude terminals volumes (MBbls/d)
2,103

 
1,950

Revenues
$
4,803

 
$
2,465

Cost of products sold
4,361

 
2,091

Segment margin
442

 
374

Unrealized (gains) losses on commodity risk management activities
262

 
(2
)
Operating expenses, excluding non-cash compensation expense
(144
)
 
(114
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(20
)
 
(32
)
Adjusted EBITDA related to unconsolidated affiliates
8

 
2

Segment Adjusted EBITDA
$
548

 
$
228

Crude transportation volumes increased due to placing the Bakken pipeline in service in June 2017 as well as increased volumes on existing pipelines due to increased production in West Texas. Crude terminal volumes increased due to increased volumes delivered to our Nederland crude terminal from the Bakken pipeline and from increased West Texas production.
Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:
an increase of $332 million in segment margin (excluding unrealized losses on commodity risk management activities) due to a $193 million increase resulting primarily from placing our Bakken pipeline in service in the second quarter of 2017 as well as a $27 million increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets; a $100 million increase (excluding a net change of $264 million in unrealized gains and losses) from our crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets; and a $9 million increase in terminal fees primarily from ship loading fees at our Nederland facility as a result of increased exports;
a decrease of $12 million in selling, general and administrative expenses primarily due to higher professional fees recorded in the prior period; and
an increase of $6 million in Adjusted EBITDA related to unconsolidated affiliates due to a new contract at one of our joint ventures; partially offset by
an increase of $30 million in operating expenses due to a $13 million increase primarily resulting from placing our Bakken pipeline in service in the second quarter of 2017; a $3 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a $14 million increase from existing transportation assets due to increases of $7 million in utilities, $5 million in expense projects, $5 million in ad valorem taxes and $5 million in management fees, partially offset by decreases in environmental fees of $5 million and capacity leases of $3 million.

12



All Other
 
Three Months Ended
June 30,
 
2018
 
2017
Revenues
$
502

 
$
870

Cost of products sold
445

 
794

Segment margin
57

 
76

Unrealized gains on commodity risk management activities
(2
)
 
(4
)
Operating expenses, excluding non-cash compensation expense
(10
)
 
(31
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(19
)
 
(27
)
Adjusted EBITDA related to unconsolidated affiliates
62

 
76

Other and eliminations
2

 
17

Segment Adjusted EBITDA
$
90

 
$
107

Amounts reflected in our all other segment primarily include:
our equity method investment in limited partnership units of Sunoco LP consisting of 26.2 million and 43.5 million Sunoco LP common units, representing 31.8% and 43.7% of Sunoco LP’s total outstanding common units as of June 30, 2018 and June 30, 2017, respectively;
our natural gas marketing and compression operations. Subsequent to our contribution of CDM to USAC in April 2018, our all other segment includes our equity method investment in USAC consisting of 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests;
a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and
our investment in coal handling facilities.
Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of the following:
a decrease of $44 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in Sunoco LP resulting from the Partnership’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018; and
a decrease of $12 million due to the contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by
a decrease of $14 million in merger and acquisition expenses related to the Sunoco Logistics merger in 2017, partially offset by the CDM Contribution in 2018;
an increase of $12 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in PES;
an increase of $6 million from gains in power trading activities; and
an increase of $2 million in margin due to the expiration of a capacity contract commitment.

13



SUPPLEMENTAL INFORMATION ON LIQUIDITY
(In millions)
(unaudited)
 
Facility Size
 
Funds Available at June 30, 2018
 
Maturity Date
ETP Five-Year Revolving Credit Facility
$
4,000

 
$
2,605

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

 
1,000

 
November 30, 2018
 
$
5,000

 
$
3,605

 
 

14



SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions)
(unaudited)
 
Three Months Ended
June 30,
 
2018
 
2017
Equity in earnings (losses) of unconsolidated affiliates:
 
 
 
Citrus
$
33

 
$
30

FEP
13

 
13

MEP
8

 
10

Sunoco LP
16

 
(110
)
USAC
(2
)
 

Other
38

 
(4
)
Total equity in earnings (losses) of unconsolidated affiliates
$
106

 
$
(61
)
 
 
 
 
Adjusted EBITDA related to unconsolidated affiliates:
 
 
 
Citrus
$
85

 
$
88

FEP
18

 
19

MEP
20

 
21

Sunoco LP
39

 
83

USAC
21

 

Other
45

 
36

Total Adjusted EBITDA related to unconsolidated affiliates
$
228

 
$
247

 
 
 
 
Distributions received from unconsolidated affiliates:
 
 
 
Citrus
$
27

 
$
22

FEP
15

 
10

MEP
18

 
20

Sunoco LP
22

 
37

USAC
10

 

Other
21

 
30

Total distributions received from unconsolidated affiliates
$
113

 
$
119


15