- Net income attributable to partners of
$617 million, reflecting an increase over previous periods
primarily due to the impact of the Merger.
- Record Adjusted EBITDA of $2.67
billion, up 29 percent from the fourth quarter of 2017.
- Record Distributable Cash Flow
attributable to partners of $1.52 billion, up 29 percent from the
fourth quarter of 2017.
- Distribution coverage ratio of 1.90x,
yielding excess coverage of $716 million of Distributable Cash Flow
attributable to partners in excess of distributions.
- Reaffirms 2019 outlook for Adjusted
EBITDA of $10.6 billion to $10.8 billion and capital expenditures
of approximately $5 billion.
Energy Transfer LP (NYSE:ET) (“ET” or the “Partnership”)
today reported financial results for the quarter and year ended
December 31, 2018.
ET reported net income attributable to partners for the three
months ended December 31, 2018 of $617 million, an increase of
$366 million compared to the three months ended
December 31, 2017. For the prior period, net income
attributable to partners continues to reflect only the amount of
net income attributable to the legacy ETE partners prior to the
Merger, as discussed below.
Adjusted EBITDA for the three months ended December 31,
2018 was $2.67 billion, an increase of $592 million compared to the
three months ended December 31, 2017. Results were supported
by increases in all of the Partnership’s core operations, with
record operating performance in ET’s NGL, interstate and intrastate
businesses.
On a pro forma basis for the Merger, Distributable Cash Flow
attributable to partners, as adjusted, for the three months ended
December 31, 2018 was a record $1.52 billion, an increase of
$338 million compared to the three months ended December 31,
2017. The increase was primarily due to the increase in Adjusted
EBITDA.
Key accomplishments and current developments:
Strategic
- ET and Energy Transfer Operating, L.P.
(“ETO”, formerly Energy Transfer Partners, L.P. or “ETP”) completed
a simplification merger transaction on October 19, 2018 (the
“Merger”) whereby the publicly held common units of ETP were
exchanged for 1.28 common units of ET. Consequently, the former
common unitholders of ETP, along with the existing common
unitholders of ET, now comprise the current common unitholders of
ET.
Operational
- Frac VI, a 150,000 barrel per day
fractionator at Mont Belvieu, was placed in service in February
2019.
- Bakken Pipeline completed a successful
open season in January 2019 to bring the current system capacity to
570,000 barrels per day.
- The North Texas natural gas pipeline
160,000 MMBtu per day expansion was placed in service in January
2019.
- Mariner East 2, a 350-mile NGL
pipeline, was placed into service for both intrastate and
interstate service in December 2018.
- Construction of a 150,000 barrel per
day fractionator (Frac VII) at Mont Belvieu and Lone Star Express
352-mile NGL pipeline expansion were announced in November
2018.
Financial
- In January 2019, ET announced a
quarterly distribution of $0.305 per unit ($1.220 annualized) on ET
common units for the quarter ended December 31, 2018.
- In January 2019, ETO issued an
aggregate $4.00 billion principal amount of senior notes and used
the net proceeds to repay in full ET’s outstanding senior secured
term loan, redeem certain outstanding senior notes at maturity,
repay a portion of the borrowings outstanding under ET’s revolving
credit facility and for general partnership purposes.
- As of December 31, 2018, ETO’s
$6.00 billion revolving credit facilities had an aggregate $2.24
billion of available capacity, and ETO’s leverage ratio, as defined
by its credit agreement, was 3.38x.
Energy Transfer benefits from a portfolio of assets with
exceptional product and geographic diversity. The Partnership’s
multiple segments generate high-quality, balanced earnings with no
single segment contributing more than a quarter of the
Partnership’s consolidated Adjusted EBITDA in 2018. The great
majority of the Partnership’s segment margins are fee-based and
therefore have limited commodity price sensitivity.
Conference call information:
The Partnership has scheduled a conference call for 8:00 a.m.
Central Time, Thursday, February 21, 2019 to discuss its
fourth 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 the Partnership’s website for a limited
time.
Subsequent to the Merger, substantially all of the Partnership’s
cash flows are derived from distributions related to its investment
in ETO, whose cash flows are derived from its subsidiaries,
including ETO’s investments in the limited and general partner
interests in Sunoco LP and USA Compression Partners LP (“USAC”), as
well as its ownership of Lake Charles LNG Company, LLC (“Lake
Charles LNG”).
Energy Transfer LP (NYSE: ET) owns and operates one of
the largest and most diversified portfolios of energy assets in the
United States, with a strategic footprint in all of the major U.S.
production basins, ET is a publicly traded limited partnership with
core operations that 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. ET, through its ownership of Energy
Transfer Operating, L.P., formerly known as Energy Transfer
Partners, L.P., also owns the general partner interests, the
incentive distribution rights and 28.5 million common units of
Sunoco LP (NYSE: SUN), and the general partner interests and 39.7
million common units of USA Compression Partners, LP (NYSE: USAC).
For more information, visit the Energy Transfer LP website at
www.energytransfer.com.
Sunoco LP (NYSE: SUN) is a master limited partnership
that distributes motor fuel to approximately 10,000 convenience
stores, independent dealers, commercial customers and distributors
located in more than 30 states. SUN’s general partner is owned by
Energy Transfer Operating, L.P., a subsidiary of Energy Transfer LP
(NYSE: ET). For more information, visit the Sunoco LP website at
www.sunocolp.com.
USA Compression Partners, LP (NYSE: USAC) is a
growth-oriented Delaware limited partnership that is one
of the nation’s largest independent providers of compression
services in terms of total compression fleet horsepower. USAC
partners with a broad customer base composed of producers,
processors, gatherers and transporters of natural gas and crude
oil. USAC focuses on providing compression services to
infrastructure applications primarily in high-volume gathering
systems, processing facilities and transportation applications. For
more information, visit the USAC website at www.usacompression.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
LP AND SUBSIDIARIES
CONDENSED
CONSOLIDATED BALANCE SHEETS
(In millions) (unaudited)
December 31,2018
December 31,2017
ASSETS Current assets $ 6,750 $ 10,683 Property,
plant and equipment, net 66,963 61,088 Advances to and
investments in unconsolidated affiliates 2,642 2,705 Other
non-current assets, net 1,006 886 Intangible assets, net 6,000
6,116 Goodwill 4,885 4,768 Total assets $ 88,246
$ 86,246
LIABILITIES AND EQUITY Current
liabilities $ 9,310 $ 7,897 Long-term debt, less current
maturities 43,373 43,671 Non-current derivative liabilities 104 145
Deferred income taxes 2,926 3,315 Other non-current liabilities
1,184 1,217 Commitments and contingencies Redeemable
noncontrolling interests 499 21 Equity: Total partners’
capital (deficit) 20,559 (1,196 ) Noncontrolling interest 10,291
31,176 Total equity 30,850 29,980 Total
liabilities and equity $ 88,246 $ 86,246
ENERGY TRANSFER
LP AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data) (unaudited)
Three Months EndedDecember 31, Year EndedDecember 31, 2018
2017 2018 2017 REVENUES $ 13,573 $ 11,451 $ 54,087 $
40,523 COSTS AND EXPENSES: Cost of products sold 9,977 8,721 41,658
30,966 Operating expenses 809 704 3,089 2,644 Depreciation,
depletion and amortization 750 677 2,859 2,554 Selling, general and
administrative 187 119 702 599 Impairment losses 431 940
431 1,039 Total costs and expenses 12,154
11,161 48,739 37,802 OPERATING INCOME
1,419 290 5,348 2,721 OTHER INCOME (EXPENSE): Interest expense, net
of interest capitalized (544 ) (482 ) (2,055 ) (1,922 ) Equity in
earnings (losses) of unconsolidated affiliates 86 (84 ) 344 144
Impairment of investment in unconsolidated affiliate — (313 ) —
(313 ) Losses on extinguishments of debt (6 ) (64 ) (112 ) (89 )
Gains (losses) on interest rate derivatives (70 ) (9 ) 47 (37 )
Other, net (35 ) 73 62 206 INCOME (LOSS) FROM
CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) 850 (589
) 3,634 710 Income tax expense (benefit) from continuing operations
(2 ) (1,747 ) 4 (1,833 ) INCOME FROM CONTINUING OPERATIONS
852 1,158 3,630 2,543 Income (loss) from discontinued operations,
net of income taxes — 10 (265 ) (177 ) NET INCOME 852
1,168 3,365 2,366 Less: Net income attributable to noncontrolling
interest 220 917 1,632 1,412 Less: Net income attributable to
redeemable noncontrolling interests 15 — 39 —
NET INCOME ATTRIBUTABLE TO PARTNERS 617 251 1,694 954
Convertible Unitholders’ interest in income — 12 33 37 General
Partner’s interest in net income — — 3 2
Limited Partners’ interest in net income $ 617 $ 239
$ 1,658 $ 915 NET INCOME PER LIMITED PARTNER
UNIT: Basic $ 0.26 $ 0.22 $ 1.16 $ 0.85 Diluted $ 0.26 $ 0.22 $
1.15 $ 0.83 WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING: Basic
2,332.1 1,079.2 1,423.8 1,078.2 Diluted 2,339.4 1,151.5 1,461.4
1,150.8
ENERGY TRANSFER
LP AND SUBSIDIARIES
SUPPLEMENTAL
INFORMATION
(Dollars and units in millions) (unaudited)
Three Months EndedDecember 31, Year EndedDecember 31, 2018
2017 2018 2017
Reconciliation of net income to Adjusted
EBITDA and Distributable Cash Flow (a) (b): Net income $ 852 $
1,168 $ 3,365 $ 2,366 (Income) loss from discontinued operations —
(10 ) 265 177 Interest expense, net 544 482 2,055 1,922 Impairment
losses 431 940 431 1,039 Income tax expense (benefit) from
continuing operations (2 ) (1,747 ) 4 (1,833 ) Depreciation,
depletion and amortization 750 677 2,859 2,554 Non-cash
compensation expense 23 23 105 99 (Gains) losses on interest rate
derivatives 70 9 (47 ) 37 Unrealized (gains) losses on commodity
risk management activities (244 ) (37 ) 11 (59 ) Losses on
extinguishments of debt 6 64 112 89 Inventory valuation adjustments
135 (16 ) 85 (24 ) Impairment of investment in an unconsolidated
affiliate — 313 — 313 Equity in (earnings) losses of unconsolidated
affiliates (86 ) 84 (344 ) (144 ) Adjusted EBITDA related to
unconsolidated affiliates 152 162 655 716 Adjusted EBITDA from
discontinued operations — 44 (25 ) 223 Other, net 38 (79 )
(21 ) (155 ) Adjusted EBITDA (consolidated) 2,669 2,077 9,510 7,320
Adjusted EBITDA related to unconsolidated affiliates (152 ) (162 )
(655 ) (716 ) Distributable Cash Flow from unconsolidated
affiliates 95 102 407 431 Interest expense, net (544 ) (497 )
(2,057 ) (1,958 ) Subsidiary preferred unitholders’ distributions
(54 ) (12 ) (170 ) (12 ) Current income tax expense (7 ) (10 ) (472
) (39 ) Transaction-related income taxes — — 470 — Maintenance
capital expenditures (137 ) (157 ) (510 ) (479 ) Other, net 19
5 49 67 Distributable Cash Flow
(consolidated) 1,889 1,346 6,572 4,614 Distributable Cash Flow
attributable to Sunoco LP (100%) (115 ) (89 ) (446 ) (449 )
Distributions from Sunoco LP 43 68 166 259 Distributable Cash Flow
attributable to USAC (100%) (55 ) — (148 ) — Distributions from
USAC 21 — 73 — Distributable Cash Flow attributable to PennTex
Midstream Partners, LP (“PennTex”) (100%) (c) — — — (19 )
Distributions from PennTex to ETO (c) — — — 8 Distributable Cash
Flow attributable to noncontrolling interest in other
non-wholly-owned consolidated subsidiaries (294 ) (151 ) (874 )
(350 ) Distributable Cash Flow attributable to the partners of ET –
pro forma for the Merger (a) 1,489 1,174 5,343 4,063
Transaction-related expenses 27 4 52 57
Distributable Cash Flow attributable to the partners of ET, as
adjusted – pro forma for the Merger (a) $ 1,516 $ 1,178
$ 5,395 $ 4,120 Three
Months EndedDecember 31, Year EndedDecember 31, 2018 2017
2018 2017
Distributions to partners – pro forma for the
Merger (a): Limited Partners (d) $ 799 $ 708 $ 3,104 $ 2,669
General Partner 1 1 4 4 Total distributions to
be paid to partners $ 800 $ 709 $ 3,108 $
2,673 Common Units outstanding – end of period – pro forma for the
Merger (a) 2,619.4 2,532.5 2,619.4 2,532.5
Distribution coverage ratio – pro forma for the Merger (a)(b) 1.90x
1.66x 1.74x 1.54x
(a) The closing of the Merger
(as discussed above) has impacted the Partnership’s calculation of
Distributable Cash Flow attributable to partners, as well as the
number of ET Common Units outstanding and the amount of
distributions to be paid to partners. In order to provide
information on a comparable basis for pre-Merger and post-Merger
periods, the Partnership has included certain pro forma
information.
Pro forma Distributable Cash Flow attributable to partners
reflects the following merger related impacts:
- ETO is reflected as a wholly-owned
subsidiary and pro forma Distributable Cash Flow attributable to
partners reflects ETO’s consolidated Distributable Cash Flow (less
certain other adjustments, as follows).
- Distributions from Sunoco LP and USAC
include distributions to both ET and ETO.
- Distributions from PennTex are
separately included in Distributable Cash Flow attributable to
partners.
- Distributable Cash Flow attributable to
noncontrolling interest in our other non-wholly-owned subsidiaries
is subtracted from consolidated Distributable Cash Flow to
calculate Distributable Cash Flow attributable to partners.
Pro forma distributions to partners include actual distributions
to legacy ET partners, as well as pro forma distributions to legacy
ETO partners. Pro forma distributions to ETO partners are
calculated assuming (i) historical ETO common units converted under
the terms of the Merger and (ii) distributions on such converted
common units were paid at the historical rate paid on ET Common
Units.
Pro forma Common Units outstanding include actual Common Units
outstanding, in addition to Common Units assumed to be issued in
the Merger, which are based on historical ETO common units
converted under the terms of the Merger.
For the year ended December 31, 2017, the calculation of
Distributable Cash Flow and the amounts reflected for distributions
to partners and common units outstanding also reflect the pro forma
impacts of the Sunoco Logistics Merger as though the merger had
occurred on January 1, 2017.
(b) Adjusted EBITDA,
Distributable Cash Flow and distribution coverage ratio are
non-GAAP financial measures used by industry analysts, investors,
lenders, and rating agencies to assess the financial performance
and the operating results of ET’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, Distributable Cash Flow and distribution coverage
ratio, 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, Distributable Cash Flow and
distribution coverage ratio may not be consistent with similarly
titled measures of other companies and should be viewed in
conjunction with measurements that are computed in accordance with
GAAP, such as segment margin, operating income, net income, and
cash flow from operating activities.
Definition of Adjusted EBITDA
We define Adjusted EBITDA as total partnership earnings before
interest, taxes, depreciation, depletion, amortization and other
non-cash items, such as non-cash compensation expense, gains and
losses on disposals of assets, the allowance for equity funds used
during construction, unrealized gains and losses on commodity risk
management activities, non-cash impairment charges, losses on
extinguishments of debt and other non-operating income or expense
items. Unrealized gains and losses on commodity risk management
activities include unrealized gains and losses on commodity
derivatives and inventory fair value adjustments (excluding lower
of cost or market adjustments). Adjusted EBITDA reflects amounts
for less than wholly-owned subsidiaries based on 100% of the
subsidiaries’ results of operations and for unconsolidated
affiliates based on our proportionate ownership.
Adjusted EBITDA is used by management to determine our operating
performance and, along with other financial and volumetric data, as
internal measures for setting annual operating budgets, assessing
financial performance of our numerous 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 ET’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, other than ETO, 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 subsidiaries, but
Distributable Cash Flow attributable to partners reflects only the
amount of Distributable Cash Flow of such subsidiaries that is
attributable to our ownership interest.
For Distributable Cash Flow attributable to partners, as
adjusted, certain transaction-related and non-recurring expenses
that are included in net income are excluded.
Definition of Distribution Coverage Ratio
Distribution coverage ratio for a period is calculated as
Distributable Cash Flow attributable to partners, as adjusted,
divided by distributions expected to be paid to the partners of ET
in respect of such period.
(c) Beginning with the second
quarter of 2017, PennTex became a wholly-owned subsidiary of ETO.
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.
(d) Includes distributions to
unitholders who elected to participate in a plan to forgo a portion
of their future potential cash distributions on common units and
reinvest those distributions in ETE Series A convertible preferred
units representing limited partner interests in the Partnership.
The quarter ended March 31, 2018 was the final quarter of
participation in the plan.
ENERGY TRANSFER LP AND SUBSIDIARIES SUMMARY
ANALYSIS OF QUARTERLY RESULTS BY SEGMENT (Tabular dollar
amounts in millions) (unaudited)
As a result of the Merger in October
2018, our reportable segments were reevaluated and currently
reflect the following segments.
Three Months EndedDecember 31, 2018 2017
Segment
Adjusted EBITDA: Intrastate transportation and storage $ 306 $
146 Interstate transportation and storage 479 342 Midstream 402 393
NGL and refined products transportation and services 569 433 Crude
oil transportation and services 636 544 Investment in Sunoco LP 180
158 Investment in USAC 104 — All other (7 ) 61 Total Segment
Adjusted EBITDA $ 2,669 $ 2,077
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.
Following is a reconciliation of Segment Margin to operating
income, as reported in the Partnership’s consolidated statements of
operations:
Three Months EndedDecember 31, 2018 2017
Segment
Margin: Intrastate transportation and storage $ 350 $ 205
Interstate transportation and storage 495 317 Midstream 609 568 NGL
and refined products transportation and services 840 582 Crude oil
transportation and services 939 683 Investment in Sunoco LP 183 277
Investment in USAC 149 — All other 45 102 Intersegment eliminations
(14 ) (4 ) Total segment margin 3,596 2,730 Less: Operating
expenses 809 704 Depreciation, depletion and amortization 750 677
Selling, general and administrative 187 119 Impairment losses 431
940 Operating income $ 1,419 $ 290
Intrastate Transportation and
Storage
Three Months EndedDecember 31, 2018 2017 Natural gas
transported (BBtu/d) 11,708 8,944 Revenues $ 1,127 $ 741 Cost of
products sold 777 536 Segment margin 350 205
Unrealized (gains) losses on commodity risk management activities 5
(21 ) Operating expenses, excluding non-cash compensation expense
(48 ) (44 ) Selling, general and administrative expenses, excluding
non-cash compensation expense (7 ) (5 ) Adjusted EBITDA related to
unconsolidated affiliates 6 11 Segment Adjusted
EBITDA $ 306 $ 146
Transported volumes increased primarily due to favorable market
pricing spreads, as well as the impact of reflecting Regency
Intrastate Gas LP (“RIGS”) as a consolidated subsidiary. RIGS was
previously reflected as an unconsolidated affiliate until ETO
acquired the remaining interest in April 2018.
Segment Adjusted EBITDA. For the three months ended
December 31, 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 $154 million in realized
natural gas sales and other due to higher realized gains from
pipeline optimization activity; and
- a net increase of $13 million due to
the consolidation of RIGS beginning in April 2018, resulting in
increases in transportation fees, retained fuel revenues, operating
expenses, and selling, general and administrative expenses of $24
million, $2 million, $5 million and $2 million, respectively,
and a decrease of $6 million in Adjusted EBITDA related to
unconsolidated affiliates; partially offset by
- a decrease of $7 million in realized
storage margin primarily due to lower realized derivative gains;
and
- a decrease of $2 million in
transportation fees, excluding the impact of consolidating RIGS as
discussed above, primarily due to a non-recurring adjustment to a
transportation services agreement, partially offset by Red Bluff
Express coming online and new contracts.
Interstate Transportation and
Storage
Three Months EndedDecember 31, 2018 2017 Natural gas
transported (BBtu/d) 11,062 7,185 Natural gas sold (BBtu/d) 18 18
Revenues $ 495 $ 317 Operating expenses, excluding non-cash
compensation, amortization and accretion expenses (120 ) (80 )
Selling, general and administrative expenses, excluding non-cash
compensation, amortization and accretion expenses (8 ) (7 )
Adjusted EBITDA related to unconsolidated affiliates 118 115 Other
(6 ) (3 ) Segment Adjusted EBITDA $ 479 $ 342
Transported volumes reflected an increase of 2,223 BBtu/d as a
result of the initiation of service on the Rover pipeline;
increases of 506 BBtu/d and 475 BBtu/d on the Panhandle and
Trunkline pipelines, respectively, due to increased utilization of
higher contracted capacity; an increase of 309 BBtu/d on the Tiger
pipeline as a result of production increases in the Haynesville
Shale; and an increase of 264 BBtu/d on the Transwestern pipeline
as a result of favorable market opportunities in the West,
midcontinent, and Waha areas from the Permian supply basin.
Segment Adjusted EBITDA. For the three months ended
December 31, 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 $112 million associated
with the Rover pipeline with increases of $149 million in revenues,
$35 million in net operating expenses and $2 million in selling,
general and administrative expenses;
- an aggregate increase of $29 million in
revenues, excluding the incremental revenue related to the Rover
pipeline discussed above, primarily due to capacity sold at higher
rates on the Transwestern, Panhandle and Trunkline pipelines;
- an increase of $3 million in Adjusted
EBITDA related to unconsolidated affiliates primarily related to
higher sales of capacity on Citrus; and
- a decrease of $1 million in selling,
general and administrative expenses, excluding the incremental
expenses related to the Rover pipeline discussed above, primarily
due to a reduction in insurance reserves; partially offset by
- an increase of $5 million in operating
expenses, excluding the incremental expenses related to the Rover
pipeline discussed above, primarily due to system gas expenses and
increases in maintenance project costs due to scope and level of
activity.
Midstream
Three Months EndedDecember 31, 2018 2017 Gathered
volumes (BBtu/d) 12,827 11,525 NGLs produced (MBbls/d) 558 505
Equity NGLs (MBbls/d) 25 27 Revenues $ 1,781 $ 1,926 Cost of
products sold 1,172 1,358 Segment margin 609 568
Unrealized losses on commodity risk management activities — 3
Operating expenses, excluding non-cash compensation expense (193 )
(168 ) Selling, general and administrative expenses, excluding
non-cash compensation expense (22 ) (18 ) Adjusted EBITDA related
to unconsolidated affiliates 8 8 Segment Adjusted
EBITDA $ 402 $ 393
Gathered volumes and NGL production increased primarily due to
increases in the North Texas, Permian and Northeast regions,
partially offset by smaller declines in other regions.
Segment Adjusted EBITDA. For the three months ended
December 31, 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 $49 million in fee-based
margin due to growth in the North Texas, Permian and Northeast
regions, offset by declines in the Ark-La-Tex and
midcontinent/Panhandle regions; and
- an increase of $14 million in
non-fee-based margin due to increased throughput volume in the
North Texas and Permian regions; partially offset by
- a decrease of $25 million in
non-fee-based margin primarily due to lower NGL prices;
- an increase of $25 million in operating
expenses due to an increase of $8 million in materials, $6 million
in outside services, $6 million in ad valorem taxes and $5 million
in expense projects; and
- an increase of $4 million in selling,
general and administrative expenses due to a change in capitalized
overhead.
NGL and Refined Products Transportation
and Services
Three Months EndedDecember 31, 2018 2017 NGL
transportation volumes (MBbls/d) 1,115 963 Refined products
transportation volumes (MBbls/d) 601 618 NGL and refined products
terminal volumes (MBbls/d) 898 792 NGL fractionation volumes
(MBbls/d) 594 455 Revenues $ 2,946 $ 2,533 Cost of products sold
2,106 1,951 Segment margin 840 582 Unrealized gains
on commodity risk management activities (112 ) (28 ) Operating
expenses, excluding non-cash compensation expense (156 ) (120 )
Selling, general and administrative expenses, excluding non-cash
compensation expense (22 ) (15 ) Adjusted EBITDA related to
unconsolidated affiliates 19 14 Segment Adjusted
EBITDA $ 569 $ 433
NGL transportation volumes increased primarily due to increased
volumes from the Permian region resulting from a ramp up in
production from existing customers, higher throughput volumes on
Mariner West driven by end user facility constraints in the prior
period and higher throughput from Mariner South resulting from
increased export volumes. Refined products transportation volumes
decreased primarily due to the timing of turnarounds at third-party
refineries in the Midwest and Northeast regions.
NGL and refined products terminal volumes increased primarily
due to more volumes loaded at our Nederland terminal as export
demand increased, as well as higher throughput volumes at our
Marcus Hook Industrial Complex.
Average fractionated volumes at our Mont Belvieu, Texas
fractionation facility increased primarily due to increased volumes
from the Permian region, as well as an increase in fractionation
capacity as our fifth fractionator at Mont Belvieu came online in
July 2018.
Segment Adjusted EBITDA. For the three months ended
December 31, 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 $85 million in
transportation margin primarily due to a $70 million increase
resulting from higher producer volumes from the Permian region on
our Texas NGL pipelines, a $9 million increase due to higher
throughput volumes on Mariner West driven by end-user facility
constraints in the prior period, a $5 million increase due to
higher throughput volumes from the Barnett region, a
$4 million increase resulting from a reclassification between
our transportation and fractionation margins and a $3 million
increase due to higher throughput volumes on Mariner South as a
result of increased export volumes. These increases were partially
offset by a $6 million decrease resulting from the timing of
deficiency revenue recognition;
- an increase of $32 million in
fractionation and refinery services margin primarily due to a
$43 million increase resulting from the commissioning of our
fifth fractionator in July 2018 and higher NGL volumes from the
Permian region feeding our Mont Belvieu fractionation facility.
This increase was partially offset by a $5 million decrease in
blending gains as a result of less favorable market pricing, a
$4 million decrease resulting from a reclassification between
our transportation and fractionation margins and a $2 million
decrease from planned downtime at a customer facility that lowered
the supply to our refinery services facility;
- an increase of $28 million in marketing
margin due to a $31 million increase from our butane blending
operations and an $12 million increase in NGL sales from our
Marcus Hook Industrial Complex. These increases were partially
offset by a $15 million decrease from the timing of
optimization gains from our Mont Belvieu fractionators; and
- an increase of $26 million in terminal
services margin due to a $13 million increase from higher
throughput at our Marcus Hook Industrial Complex, an
$11 million increase resulting from a change in the
classification of certain customer reimbursements previously
recorded in operating expenses and a $2 million increase at
our Nederland terminal due to increased export demand; partially
offset by
- an increase of $36 million in operating
expenses primarily due to a $14 million increase in operating
costs primarily due to higher throughput on our NGL pipelines and
fractionators and the commissioning of our fifth fractionator in
July 2018, an $11 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 $3 million increase in costs relating to an outside
storage lease and a $3 million increase in certain allocated
overhead costs; and
- an increase of $7 million in selling,
general and administrative expenses due to a $6 million
increase in overhead costs allocated to the segment and
$1 million increase in legal fees.
Crude Oil Transportation and
Services
Three Months EndedDecember 31, 2018 2017 Crude
transportation volumes (MBbls/d) 4,330 3,872 Crude terminals
volumes (MBbls/d) 2,202 2,059 Revenues $ 4,346 $ 3,938 Cost of
products sold 3,407 3,255 Segment margin 939 683
Unrealized (gains) losses on commodity risk management activities
(132 ) 4 Operating expenses, excluding non-cash compensation
expense (150 ) (125 ) Selling, general and administrative expenses,
excluding non-cash compensation expense (22 ) (20 ) Adjusted EBITDA
related to unconsolidated affiliates 1 2 Segment
Adjusted EBITDA $ 636 $ 544
Crude transportation volumes increased due to placing the Bakken
pipeline in service in June 2017 as well as higher throughput on
existing pipelines due to increased production in West Texas. Crude
terminal volumes benefited from an increase in barrels delivered to
our Nederland crude terminal from the Bakken pipeline and from
increased West Texas production.
Segment Adjusted EBITDA. For the three months ended
December 31, 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 $120 million in segment
margin (excluding unrealized gains and losses on commodity risk
management activities) primarily due to the following: a
$102 million increase resulting from higher throughput on the
Bakken pipeline and a $125 million increase resulting from
higher throughput on our Texas crude pipeline system primarily due
to increased production from Permian producers. These increases
were partially offset by a $107 million decrease to segment
margin (excluding a net change of $136 million in unrealized
gains and losses on commodity risk management activities) from our
crude oil acquisition and marketing business; partially offset
by
- an increase of $25 million in operating
expenses due to a $23 million increase due to higher throughput
related expenses on existing assets and a $2 million increase from
the expansion of our Permian Express 3 pipeline in service in the
fourth quarter of 2018; and
- an increase of $2 million in selling,
general and administrative expenses primarily due to increases in
allocated shared service charges.
Investment in Sunoco LP
Three Months EndedDecember 31, 2018 2017 Revenues $
3,877 $ 2,959 Cost of products sold 3,694 2,682
Segment margin 183 277 Unrealized losses on commodity risk
management activities 5 2 Operating expenses, excluding non-cash
compensation expense (111 ) (113 ) Selling, general and
administrative, excluding non-cash compensation expense (36 ) (36 )
Inventory fair value adjustments 135 (16 ) Adjusted EBITDA from
discontinued operations — 44 Other, net 4 — Segment
Adjusted EBITDA $ 180 $ 158
The Investment in Sunoco LP segment reflects the consolidated
results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended
December 31, 2018 compared to the same period last year,
Segment Adjusted EBITDA related to our investment in Sunoco LP
increased due to the net impacts of the following:
- an increase of $60 million in
margin (excluding a $154 million change in inventory fair
value adjustments and unrealized losses on commodity risk
management activities) primarily due to increases in fuel margins
and fuel volumes; partially offset by
- a decrease of $44 million in
Adjusted EBITDA from discontinued operations primarily due to
Sunoco LP’s retail divestment in January 2018.
Investment in USAC
Three Months EndedDecember 31, 2018 2017 Revenues $
172 $ — Cost of products sold 23 — Segment margin 149 —
Operating expenses, excluding non-cash compensation expense (30 ) —
Selling, general and administrative, excluding non-cash
compensation expense (16 ) — Other, net 1 — Segment Adjusted
EBITDA $ 104 $ —
Amounts reflected above for the three months ended
December 31, 2018 represents the consolidated results of
operations for USAC. Changes between periods are due to the
consolidation of USAC beginning April 2, 2018.
All Other
Three Months EndedDecember 31, 2018 2017 Revenues $
630 $ 652 Cost of products sold 585 550 Segment
margin 45 102 Unrealized (gains) losses on commodity risk
management activities (11 ) 3 Operating expenses, excluding
non-cash compensation expense (6 ) (31 ) Selling, general and
administrative expenses, excluding non-cash compensation expense
(41 ) (28 ) Adjusted EBITDA related to unconsolidated affiliates —
12 Other and eliminations 6 3 Segment Adjusted EBITDA
$ (7 ) $ 61
Segment Adjusted EBITDA. For the three months ended
December 31, 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 $35 million due to the
contribution of CDM to USAC in April 2018, subsequent to which CDM
is reflected in the Investment in USAC segment;
- a decrease of $29 million due to merger
and acquisition expenses related to the Merger in 2018;
- a decrease of $13 million in Adjusted
EBITDA related to unconsolidated affiliates from our investment in
PES primarily due to our lower ownership in PES subsequent to its
reorganization, which resulted in PES no longer being reflected as
an affiliate beginning in the third quarter of 2018; and
- a decrease of $6 million due to a
decrease in power trading gains; partially offset by
- an increase of $5 million in joint
venture management fees; and
- an increase of $4 million from
transport fees and gains from storage and park and loan
activity.
ENERGY TRANSFER
LP AND SUBSIDIARIES
SUPPLEMENTAL
INFORMATION ON LIQUIDITY
(In millions) (unaudited) The following
table is a summary of ETO’s revolving credit facilities which
incurred certain changes in connection with the Merger. We
also have consolidated subsidiaries with revolving credit
facilities which are not included. Facility Size
Funds Available atDecember 31, 2018
Maturity Date ETO Five-Year Revolving Credit Facility $ 5,000 $
1,243 December 1, 2023 ETO 364-Day Revolving Credit Facility 1,000
1,000 November 30, 2019 $ 6,000 $ 2,243
ENERGY TRANSFER
LP AND SUBSIDIARIES
SUPPLEMENTAL
INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions) (unaudited)
The table below provides information on
an aggregated basis for our unconsolidated affiliates, which are
accounted for as equity method investments in the Partnership’s
financial statements for the periods presented.
Three Months EndedDecember 31, 2018 2017
Equity in
earnings (losses) of unconsolidated affiliates: Citrus $ 39 $
58 FEP 14 14 MEP 7 9 HPC (1)(2) — (185 ) Other 26 20
Total equity in earnings (losses) of unconsolidated affiliates $ 86
$ (84 )
Adjusted EBITDA related to unconsolidated
affiliates: Citrus $ 81 $ 74 FEP 18 19 MEP 19 22 HPC (2) — 6
Other 34 41 Total Adjusted EBITDA related to
unconsolidated affiliates $ 152 $ 162
Distributions received from unconsolidated affiliates:
Citrus $ 46 $ 43 FEP 18 19 MEP 8 8 HPC (2) — 13 Other 35 22
Total distributions received from unconsolidated affiliates
$ 107 $ 105
(1) For the three months ended December 31, 2017, equity in
earnings (losses) of unconsolidated affiliates includes the impact
of non-cash impairments recorded by HPC, which reduced the
Partnership’s equity in earnings by $185 million.
(2) The partnership previously owned a 49.99% interest in HPC,
which owns RIGS. In April 2018, we acquired the remaining 50.01%
interest in HPC. Prior to April 2018, HPC was reflected as an
unconsolidated affiliate in our financial statements; beginning in
April 2018, RIGS is reflected as a wholly-owned subsidiary in our
financial statements.
ENERGY TRANSFER
LP AND SUBSIDIARIES
SUPPLEMENTAL
INFORMATION ON NON-WHOLLY-OWNED JOINT VENTURE
SUBSIDIARIES
(In millions) (unaudited)
The table below provides information on
an aggregated basis for our non-wholly-owned joint venture
subsidiaries, which are reflected on a consolidated basis in our
financial statements. The table below excludes Sunoco LP and USAC,
which are non-wholly-owned subsidiaries that are publicly
traded.
Three Months EndedDecember 31, 2018 2017 Adjusted
EBITDA of non-wholly-owned subsidiaries (100%) (a) $ 669 $ 381 Our
proportionate share of Adjusted EBITDA of non-wholly-owned
subsidiaries (b) 351 212 Distributable Cash Flow of
non-wholly-owned subsidiaries (100%) (c) $ 626 $ 346 Our
proportionate share of Distributable Cash Flow of non-wholly-owned
subsidiaries (d) 332 194
Below is our ownership percentage of certain non-wholly-owned
subsidiaries:
Non-wholly-owned subsidiary: ET Percentage Ownership
(e) Bakken Pipeline 36.4 % Bayou Bridge 60.0 % Ohio River
System 75.0 % Permian Express Partners 87.7 % Rover 32.6 % Others
various
(a) Adjusted EBITDA of non-wholly-owned subsidiaries reflects
the total Adjusted EBITDA of our non-wholly-owned subsidiaries on
an aggregated basis. This is the amount of EBITDA included in our
consolidated non-GAAP measure of Adjusted EBITDA.
(b) Our proportionate share of Adjusted EBITDA of
non-wholly-owned subsidiaries reflects the amount of Adjusted
EBITDA of such subsidiaries (on an aggregated basis) that is
attributable to our ownership interest.
(c) Distributable Cash Flow of non-wholly-owned subsidiaries
reflects the total Distributable Cash Flow of our non-wholly-owned
subsidiaries on an aggregated basis.
(d) Our proportionate share of Distributable Cash Flow of
non-wholly-owned subsidiaries reflects the amount of Distributable
Cash Flow of such subsidiaries (on an aggregated basis) that is
attributable to our ownership interest. This is the amount of
Distributable Cash Flow included in our consolidated non-GAAP
measure of Distributable Cash Flow attributable to the partners of
ET.
(e) Our ownership reflects the total economic interest held by
us and our subsidiaries. In some cases, this percentage comprises
ownership interests held in (or by) multiple entities.
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Energy Transfer
Investor Relations:Bill Baerg, Brent Ratliff, Lyndsay
Hannah, 214-981-0795orMedia Relations:Vicki Granado,
214-840-5820
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