Market Overview

Energy Transfer Partners Reports Second Quarter Results

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Energy 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 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.

       
 

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
 
         

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.
 
         

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)  

1.23

x

 

1.12

x

 

1.19

x

 

1.15

x

 

(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.

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.

   

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
 
 

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.

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.

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
  • 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.

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.
           

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
 
   

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  
 

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