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 EndedJune 30, Six Months EndedJune 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 EndedJune 30, Six Months EndedJune 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 EndedJune 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 EndedJune 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 EndedJune 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 EndedJune 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 EndedJune 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 EndedJune 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 EndedJune 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 EndedJune 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 atJune 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 EndedJune 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
View source
version on businesswire.com: https://www.businesswire.com/news/home/20180808005797/en/
Energy TransferInvestor Relations:Lyndsay Hannah, Brent
Ratliff, 214-981-0795orMedia Relations:Vicki Granado,
214-840-5820
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