Energy Transfer Partners, L.P. (NYSE: ETP) today reported
its financial results for the quarter ended December 31, 2015.
Adjusted EBITDA for Energy Transfer Partners, L.P. (“ETP” or the
“Partnership”) for the three months ended December 31, 2015
totaled $1.36 billion, a decrease of $168 million
compared to the same period last year. Distributable Cash Flow
attributable to the partners of ETP, as adjusted, for the three
months ended December 31, 2015 totaled $959 million, an
increase of $165 million over the same period last year.
Income from continuing operations for the three months ended
December 31, 2015 was $21 million, an increase of
$264 million over the same period last year.
Adjusted EBITDA for ETP for the year ended December 31,
2015 totaled $5.71 billion, an increase of $4 million compared to
last year. Distributable Cash Flow attributable to the partners of
ETP, as adjusted, for the year ended December 31, 2015 totaled
$3.45 billion, an increase of $196 million over last year. Income
from continuing operations for the year ended December 31,
2015 was $1.52 billion, an increase of $286 million over last
year.
In January 2016, ETP announced a quarterly distribution of
$1.055 per unit ($4.22 annualized) on ETP Common Units for the
quarter ended December 31, 2015.
ETP’s other recent key accomplishments include the
following:
- In December 2015, ETP announced that
the Lake Charles LNG Project has received approval from the FERC to
site, construct and operate a natural gas liquefaction and export
facility in Lake Charles, Louisiana. On February 15, 2016, Royal
Dutch Shell plc completed its acquisition of BG Group plc. Final
investment decisions from Royal Dutch Shell plc and Lake Charles
LNG Export Company, LLC, a subsidiary of ETP and Energy Transfer
Equity, L.P. (“ETE”), are expected to be made in 2016, with
construction to start immediately following an affirmative
investment decision and first LNG export anticipated about four
years later.
- In November 2015, ETP and Sunoco LP
announced ETP’s contribution to Sunoco LP of the remaining 68.42%
interest in Sunoco, LLC and 100% interest in the legacy Sunoco,
Inc. retail business for $2.23 billion. Sunoco LP will pay ETP
$2.03 billion in cash, subject to certain working capital
adjustments, and will issue to ETP 5.7 million Sunoco LP common
units. The transaction will be effective January 1, 2016, and is
expected to close in March 2016.
- As of December 31, 2015, ETP’s
$3.75 billion revolving credit facility had $1.36 billion of
outstanding borrowings, and its leverage ratio, as defined by the
credit agreement, was 4.50x.
- In the fourth quarter of 2015, ETP
issued 6.7 million common units through its at-the-market
equity program, generating net proceeds of $293 million.
An analysis of ETP’s segment results and other supplementary
data is provided after the financial tables shown below. ETP has
scheduled a conference call for 8:00 a.m. Central Time, Thursday,
February 25, 2016 to discuss the fourth quarter 2015 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 owning and operating one of the largest and
most diversified portfolios of energy assets in the United States.
ETP’s subsidiaries include Panhandle Eastern Pipe Line Company, LP
(the successor of Southern Union Company) and Lone Star NGL LLC,
which owns and operates natural gas liquids storage, fractionation
and transportation assets. In total, ETP currently owns and
operates more than 62,500 miles of natural gas and natural gas
liquids pipelines. ETP also owns the general partner, 100% of the
incentive distribution rights, and approximately 67.1 million
common units in Sunoco Logistics Partners L.P. (NYSE: SXL), which
operates a geographically diverse portfolio of crude oil and
refined products pipelines, terminalling and crude oil acquisition
and marketing assets. Additionally, ETP owns fuel distribution and
retail marketing assets and approximately 36% of the limited
partner interests in Sunoco LP (formerly Susser Petroleum Partners
LP) (NYSE: SUN), a wholesale fuel distributor and convenience store
operator. 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 which 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) and approximately 2.6
million ETP Common Units, approximately 81 million ETP Class H
Units, which track 90% of the underlying economics of the general
partner interest and the IDRs of Sunoco Logistics Partners L.P.
(NYSE: SXL), and 100 ETP Class I Units. On a consolidated basis,
ETE’s family of companies owns and operates approximately 71,000
miles of natural gas, natural gas liquids, refined products, and
crude oil pipelines. For more information, visit the Energy
Transfer Equity, L.P. website at www.energytransfer.com.
Sunoco Logistics Partners L.P. (NYSE: SXL), headquartered
in Newtown Square, Pennsylvania, is a master limited partnership
that owns and operates a logistics business consisting of a
geographically diverse portfolio of complementary crude oil,
refined products, and natural gas liquids pipeline, terminalling
and acquisition and marketing assets which are used to facilitate
the purchase and sale of crude oil, refined products, and natural
gas liquids. Sunoco Logistics’ general partner is a consolidated
subsidiary of Energy Transfer Partners, L.P. (NYSE: ETP). For more
information, visit the Sunoco Logistics Partners L.P. website at
www.sunocologistics.com.
Forward-Looking Statements
This press 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 Partnerships’ Annual Reports 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)
December 31, 2015 2014
ASSETS
Current assets $ 4,698 $ 6,029 Property, plant and
equipment, net 45,087 38,907 Advances to and investments in
unconsolidated affiliates 5,003 3,760 Non-current derivative assets
— 10 Other non-current assets, net 536 644 Intangible assets, net
4,421 5,526 Goodwill 5,428 7,642 Total assets $
65,173 $ 62,518
LIABILITIES AND EQUITY Current
liabilities $ 4,121 $ 6,585 Long-term debt, less current
maturities 28,553 24,831 Long-term notes payable – related party
233 — Non-current derivative liabilities 137 154 Deferred income
taxes 4,082 4,331 Other non-current liabilities 968 1,258
Commitments and contingencies Series A Preferred Units 33 33
Redeemable noncontrolling interests 15 15 Equity: Total
partners’ capital 20,836 12,070 Noncontrolling interest 6,195 5,153
Predecessor equity — 8,088 Total equity 27,031
25,311 Total liabilities and equity $ 65,173 $ 62,518
ENERGY TRANSFER
PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data) (unaudited)
Three Months EndedDecember 31,
Years Ended December 31, 2015 2014
2015 2014 REVENUES $ 5,825 $
13,427 $ 34,292 $ 55,475 COSTS AND EXPENSES: Cost of products sold
4,237 11,591 27,029 48,414 Operating expenses 498 696 2,261 2,059
Depreciation, depletion and amortization 478 463 1,929 1,669
Selling, general and administrative 86 148 475 520 Impairment
losses 339 370 339
370 Total costs and expenses 5,638
13,268 32,033 53,032 OPERATING
INCOME 187 159 2,259 2,443 OTHER INCOME (EXPENSE): Interest
expense, net (312 ) (297 ) (1,291 ) (1,165 ) Equity in earnings
from unconsolidated affiliates 81 67 469 332 Gain on sale of
AmeriGas common units — — — 177 Losses on extinguishments of debt —
(25 ) (43 ) (25 ) Losses on interest rate derivatives (4 ) (84 )
(18 ) (157 ) Other, net (34 ) 24 22
(12 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE
INCOME TAX EXPENSE (82 ) (156 ) 1,398 1,593 Income tax expense
(benefit) from continuing operations (103 ) 87
(123 ) 358 INCOME (LOSS) FROM CONTINUING
OPERATIONS 21 (243 ) 1,521 1,235 Income (loss) from discontinued
operations — (2 ) — 64
NET INCOME (LOSS) 21 (245 ) 1,521 1,299 Less: Net income
(loss) attributable to noncontrolling interest (25 ) (103 ) 157 116
Less: Net loss attributable to predecessor —
(250 ) (34 ) (153 ) NET INCOME ATTRIBUTABLE TO
PARTNERS 46 108 1,398 1,336 General Partner’s interest in net
income 285 140 1,064 513 Class H Unitholder’s interest in net
income 74 58 258 217 Class I Unitholder’s interest in net income
14 — 94 —
Common Unitholders’ interest in net income (loss) $ (327 ) $ (90 )
$ (18 ) $ 606 INCOME (LOSS) FROM CONTINUING OPERATIONS PER
COMMON UNIT: Basic $ (0.68 ) $ (0.27 ) $ (0.09 ) $ 1.58 Diluted $
(0.68 ) $ (0.27 ) $ (0.10 ) $ 1.58 NET INCOME (LOSS) PER COMMON
UNIT: Basic $ (0.68 ) $ (0.28 ) $ (0.09 ) $ 1.77 Diluted $ (0.68 )
$ (0.28 ) $ (0.10 ) $ 1.77 WEIGHTED AVERAGE NUMBER OF COMMON UNITS
OUTSTANDING: Basic 485.1 351.2 432.8 331.5 Diluted 485.5 351.2
435.4 332.8
SUPPLEMENTAL
INFORMATION
(Dollars and units in millions, except per unit amounts)
(unaudited)
Three Months EndedDecember 31,
Years Ended December 31, 2015
2014 2015 2014
Reconciliation of net income (loss) to Adjusted EBITDA and
Distributable Cash Flow (a): Net income (loss) $ 21 $ (245 ) $
1,521 $ 1,299 Interest expense, net of interest capitalized 312 297
1,291 1,165 Gain on sale of AmeriGas common units — — — (177 )
Impairment losses 339 370 339 370 Income tax expense (benefit) from
continuing operations (b) (103 ) 87 (123 ) 358 Depreciation,
depletion and amortization 478 463 1,929 1,669 Non-cash
compensation expense 20 18 79 68 Losses on interest rate
derivatives 4 84 18 157 Unrealized (gains) losses on commodity risk
management activities (7 ) (113 ) 65 (112 ) Inventory valuation
adjustments 120 456 104 473 Losses on extinguishments of debt — 25
43 25 Equity in earnings of unconsolidated affiliates (81 ) (67 )
(469 ) (332 ) Adjusted EBITDA related to unconsolidated affiliates
226 164 937 748 Other, net 31 (11 ) (20
) (1 )
Adjusted EBITDA (consolidated)
1,360 1,528 5,714 5,710 Adjusted EBITDA related to unconsolidated
affiliates (226 ) (164 ) (937 ) (748 ) Distributable cash flow from
unconsolidated affiliates (c) 214 119 682 482 Interest expense, net
of interest capitalized (312 ) (297 ) (1,291 ) (1,165 )
Amortization included in interest expense (6 ) (12 ) (36 ) (60 )
Current income tax (expense) benefit from continuing operations (b)
283 (70 ) 325 (407 ) Transaction-related income taxes (d) (51 ) 15
(51 ) 396 Maintenance capital expenditures (177 ) (184 ) (485 )
(444 ) Other, net 1 2 12
7 Distributable Cash Flow (consolidated) 1,086 937 3,933
3,771 Distributable Cash Flow attributable to Sunoco Logistics
Partners L.P. (“Sunoco Logistics”) (100%) (245 ) (177 ) (879 ) (750
) Distributions from Sunoco Logistics to ETP 118 81 413 285
Distributable Cash Flow attributable to Sunoco LP (100%) (e) — (52
) (68 ) (56 ) Distributions from Sunoco LP to ETP (e) — 10 24 18
Distributable cash flow attributable to noncontrolling interest in
Edwards Lime Gathering LLC (5 ) (5 ) (20 ) (19
) Distributable Cash Flow attributable to the partners of ETP 954
794 3,403 3,249 Transaction-related expenses 5
— 42 — Distributable Cash Flow
attributable to the partners of ETP, as adjusted $ 959 $ 794
$ 3,445 $ 3,249
Distributions to the
partners of ETP (f): Limited Partners: Common units held by
public $ 512 $ 321 $ 1,970 $ 1,179 Common units held by ETE 3 31 54
119 Class H Units held by ETE (g) 77 60 263 219 General Partner
interests held by ETE 8 5 31 21 Incentive Distribution Rights
(“IDRs”) held by ETE 324 208 1,261 754 IDR relinquishments net of
Class I Unit distributions (28 ) (68 ) (111 )
(250 ) Total distributions to be paid to the partners of ETP $ 896
$ 557 $ 3,468 $ 2,042 Common Units
outstanding – end of period 505.6 355.5
505.6 355.5 Distribution coverage ratio (h)
1.07
x
1.43
x
0.99
x
1.59
x
Distributable Cash Flow per Common Unit (i) $ 1.19 $
1.68 $ 4.62 $ 7.56
(a) 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 gross margin, operating income, net
income, and cash flow from operating activities.
Definition of Adjusted EBITDA
ETP defines Adjusted EBITDA as total partnership earnings before
interest, taxes, depreciation, 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 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 ETP’s 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
ETP defines Distributable Cash Flow as net income, adjusted for
certain non-cash items, less maintenance capital expenditures.
Non-cash items include depreciation and amortization, 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 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). Distributable Cash
Flow reflects earnings from unconsolidated affiliates on a cash
basis, including (i) for unconsolidated affiliates with publicly
traded equity interests, distributions paid or expected to be paid
for the periods presented and (ii) for unconsolidated affiliates
that are under common control of ETP’s parent, ETP’s proportionate
share of the distributable cash flow of the investee.
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
ETP’s subsidiaries, the Distributable Cash Flow generated by ETP’s
subsidiaries may not be available to be distributed to the partners
of ETP. In order to reflect the cash flows available for
distributions to the partners of ETP, ETP has reported
Distributable Cash Flow attributable to the partners of ETP, 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 the partners of ETP
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 the partners of ETP is net
of distributions to be paid by the subsidiary to the noncontrolling
interests.
For Distributable Cash Flow attributable to the partners of ETP,
as adjusted, certain transaction-related and non-recurring expenses
that are included in net income are excluded.
(b) For the three and twelve months ended December 31,
2015, the Partnership’s effective income tax rate decreased from
the prior year primarily due to lower earnings among the
Partnership’s consolidated corporate subsidiaries. The three and
twelve months ended December 31, 2015 also reflect a benefit
of $24 million of net state tax benefit attributable to
statutory state rate changes resulting from the Regency Merger and
sale of Susser to Sunoco LP, as well as a favorable impact of
$11 million due to a reduction in the statutory Texas
franchise tax rate which was enacted by the Texas legislature
during the second quarter of 2015. For the three and twelve months
ended December 31, 2014, the Partnership’s income tax expense from
continuing operations included unfavorable income tax adjustments
of $87 million related to the Lake Charles LNG Transaction,
which was treated as a sale for tax purposes.
The three months ended December 31, 2015 reflect current
income tax benefits of $80 million due to lower earnings among the
Partnership’s consolidated corporate subsidiaries, $120 million due
to the retroactive re-enactment of bonus depreciation, and $24
million attributable to the reversal of an income tax reserve for
certain amended tax returns that had been filed claiming previously
disallowed Pennsylvania net operating loss deductions.
Additionally, the three months ended December 31, 2015 also
reflect a $51 million current income tax benefit related to
the funding of Sunoco, Inc.’s pension plan obligations, which
benefit has been excluded from Distributable Cash Flow, as
discussed in note (d) below.
(c) For the three months ended December 31, 2015,
distributable cash flow from unconsolidated affiliates includes
distributions to be paid by Sunoco LP with respect to the fourth
quarter of 2015, as well as the Partnership’s share of the
distributable cash flow of Sunoco LLC for the fourth quarter of
2015. For the year ended December 31, 2015, distributable cash
flow from unconsolidated affiliates includes distributions to be
paid by Sunoco LP with respect to the third and fourth quarters of
2015, as well as the Partnership’s share of the distributable cash
flow of Sunoco LLC for the third and fourth quarters of 2015.
(d) For the three months ended December 31, 2015,
transaction-related income taxes reflect a $51 million current
income tax benefit related to the funding of Sunoco, Inc.’s pension
plan obligations, which amount is reflected in “Current income tax
(expense) benefit from continuing operations.”
Transaction-related income taxes primarily included income tax
expense related to the Lake Charles LNG Transaction. For the three
months and year ended December 31, 2014, amounts previously
reported for each of the interim periods have been adjusted to
reflect income taxes related to other transactions, which amounts
had not previously been reflected in the calculation of
Distributable Cash Flow for such interim periods.
(e) Amounts related to Sunoco LP reflect the periods through
June 30, 2015, subsequent to which Sunoco LP was deconsolidated and
is now reflected as an equity method investment.
(f) Distributions on ETP Common Units, as reflected above,
exclude cash distributions on Partnership common units held by
subsidiaries of ETP.
(g) Distributions on the Class H Units for the three months and
years ended December 31, 2015 and 2014 were calculated as
follows:
Three Months EndedDecember 31,
Years Ended December 31, 2015 2014
2015 2014 General partner
distributions and incentive distributions from Sunoco Logistics $
86 $ 54 $ 293 $ 185 90.05 % 50.05 % 90.05 %
50.05 % Share of Sunoco Logistics general partner and
incentive distributions payable to Class H Unitholder 77 27 263 93
Incremental distributions payable to Class H Unitholder —
33 — 126 Total
Class H Unit distributions $ 77 $ 60 $ 263 $
219 * Incremental distributions previously
paid to the Class H Unitholder were eliminated in Amendment No. 9
to ETP’s Amended and Restated Agreement of Limited Partnership
effective in the first quarter of 2015.
(h) Distribution coverage ratio for a period is calculated as
Distributable Cash Flow attributable to the partners of ETP, as
adjusted, divided by net distributions expected to be paid to the
partners of ETP in respect of such period.
(i) The Partnership defines Distributable Cash Flow per Common
Unit for a period as the quotient of Distributable Cash Flow
attributable to the partners of ETP, as adjusted, net of
distributions related to the Class H Units, Class I Units and the
General Partner and IDR interests, divided by the weighted average
number of Common Units outstanding.
Similar to Distributable Cash Flow as described above,
Distributable Cash Flow per Common Unit is a significant liquidity
measure used by the Partnership’s senior management to compare net
cash flows generated by the Partnership to the distributions the
Partnership expects to pay to its unitholders. Using this measure,
the Partnership’s management can compare Distributable Cash Flow
attributable to the partners of ETP, as adjusted, among different
periods on a per-unit basis.
Distributable Cash Flow per Common Unit is calculated as
follows:
Three Months EndedDecember 31,
Years Ended December 31, 2015
2014 2015 2014
Distributable Cash Flow attributable to the partners of ETP, as
adjusted $ 959 $ 794 $ 3,445 $ 3,249 Less: Class H Units held by
ETE (77 ) (60 ) (263 ) (219 ) General Partner interests held by ETE
(8 ) (5 ) (31 ) (21 ) IDRs held by ETE (324 ) (208 ) (1,261 ) (754
) IDR relinquishments net of Class I Unit distributions 28
68 111 250 $ 578
$ 589 $ 2,001 $ 2,505 Weighted average
Common Units outstanding – basic 485.1 351.2
432.8 331.5 Distributable Cash
Flow per Common Unit $ 1.19 $ 1.68 $ 4.62 $
7.56
SUMMARY ANALYSIS
OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions) (unaudited)
Our segment results are presented based on the measure of
Segment Adjusted EBITDA. The tables below identify the components
of Segment Adjusted EBITDA, which was calculated as follows:
- Gross margin, operating expenses, and
selling, general and administrative expenses. These amounts
represent the amounts included in our consolidated financial
statements that are attributable to each segment.
- Unrealized gains or losses on commodity
risk management activities and inventory valuation adjustments.
These are the unrealized amounts that are included in cost of
products sold to calculate gross margin. These amounts are not
included in Segment Adjusted EBITDA; therefore, the unrealized
losses are added back and the unrealized gains are subtracted to
calculate the segment measure.
- Non-cash compensation expense. These
amounts represent the total non-cash compensation recorded in
operating expenses and selling, general and administrative
expenses. This expense is not included in Segment Adjusted EBITDA
and therefore is added back to calculate the segment measure.
- Adjusted EBITDA related to
unconsolidated affiliates. These amounts represent our
proportionate share of the Adjusted EBITDA of our unconsolidated
affiliates. Amounts reflected are calculated consistently with our
definition of Adjusted EBITDA.
Three Months EndedDecember 31,
2015 2014
Segment Adjusted
EBITDA: Midstream $ 264 $ 360 Liquids transportation and
services 222 159 Interstate transportation and storage 283 307
Intrastate transportation and storage 122 120 Investment in Sunoco
Logistics 317 237 Retail marketing 119 295 All other 33
50 $ 1,360 $ 1,528
Midstream
Three Months EndedDecember 31,
2015 2014 Gathered volumes (MMBtu/d):
10,051,612 9,531,307 NGLs produced (Bbls/d): 443,741 376,724 Equity
NGLs produced (Bbls/d): 29,437 30,656 Revenues $ 1,289 $ 1,599 Cost
of products sold 840 993 Gross margin
449 606 Unrealized gains on commodity risk management activities —
(76 ) Operating expenses, excluding non-cash compensation expense
(183 ) (156 ) Selling, general and administrative expenses,
excluding non-cash compensation expense (8 ) (16 ) Adjusted EBITDA
related to unconsolidated affiliates 6 2
Segment Adjusted EBITDA $ 264 $ 360
Gathered volumes and NGLs produced increased during the three
months ended December 31, 2015 compared to the same period last
year primarily due the King Ranch acquisition, as well as increased
gathering and processing capacities in the Eagle Ford Shale,
Permian Basin and Cotton Valley regions.
Segment Adjusted EBITDA for the midstream segment reflected a
decrease in gross margin as follows:
Three Months EndedDecember 31,
2015 2014 Gathering and processing fee-based
revenues $ 393 $ 382 Non fee-based contracts and processing
56 224 Total gross margin $ 449 $ 606
For the three months ended December 31, 2015 compared to
the same period last year, Segment Adjusted EBITDA related to our
midstream segment decreased due to the net impacts of the
following:
- lower natural gas prices and lower NGL
prices resulted in lower non-fee based margins of $22 million and
$51 million, respectively;
- a decrease of $19 million due to
realized gains on derivatives in the prior year; and
- an increase of $27 million in operating
expenses primarily due to assets recently placed in service,
including the Rebel system in west Texas, the King Ranch system in
south Texas, as well as the Dubberly plant in north Louisiana;
partially offset by
- an increase of $11 million in fee-based
revenues due to increased production and increased capacity from
assets placed in service in the Eagle Ford Shale, Permian Basin and
Cotton Valley, partially offset by volume declines in the North
Texas and Mid-Continent/Panhandle regions; and
- a decrease of $8 million in general and
administrative expenses primarily due to a reduction in
employee-related cost.
Liquids Transportation and
Services
Three Months EndedDecember 31,
2015 2014 Liquids transportation
volumes (Bbls/d) 473,656 393,743 NGL fractionation volumes (Bbls/d)
249,566 204,565 Revenues $ 972 $ 982 Cost of products sold
716 770 Gross margin 256 212 Unrealized
(gains) losses on commodity risk management activities 6 (11 )
Operating expenses, excluding non-cash compensation expense (38 )
(38 ) Selling, general and administrative expenses, excluding
non-cash compensation expense (4 ) (5 ) Adjusted EBITDA related to
unconsolidated affiliates 2 1 Segment
Adjusted EBITDA $ 222 $ 159
NGL transportation volumes increased due to increases from the
Eagle Ford, Permian, and Southeast Texas producing regions, offset
by decreases from North Texas. Additionally, we commissioned a
crude transportation pipeline in the fourth quarter of 2014 that
transported approximately 44,000 Bbls/d for the three months ended
December 31, 2015.
Segment Adjusted EBITDA for the liquids transportation and
services segment reflected an increase in gross margin as
follows:
Three Months EndedDecember 31,
2015 2014 Transportation margin $ 104 $ 100
Processing and fractionation margin 79 66 Storage margin 48 44
Other margin 25 2 Total gross margin $ 256 $ 212
For the three months ended December 31, 2015 compared to
the same period last year, Segment Adjusted EBITDA related to our
liquids transportation and services segment increased due to the
net impacts of the following:
- an increase of $4 million in
transportation margin primarily due to higher volumes transported
out of the Permian and the Eagle Ford producing regions. Increased
volumes from the Eagle Ford region led to increases in margin of $3
million for the three months ended December 31, 2015;
- an increase of $6 million in processing
and fractionation margin (excluding changes in unrealized gains of
$7 million) due to a $15 million increase in fees from the Mariner
South export terminal which ramped up starting in April of 2015,
offset by a reduction of $8 million in margin associated with our
off-gas fractionator in Geismar, Louisiana for the three months
ended December 31, 2015 as NGL and olefins market prices decreased
significantly for the comparable period;
- an increase of $4 million in storage
margin due to a $3 million increase in fee-based storage margin for
the three months ended December 31, 2015 as a result of favorable
market conditions and a specific contract negotiated in connection
with the Mariner South LPG export project. In addition, non-fee
based storage margin increased $1 million for the three months
ended December 31, 2015 due to gains recognized on the withdrawal
of inventory from our caverns;
- an increase of $48 million in other
margin (excluding changes in unrealized losses of $25 million)
primarily due to the withdrawal and sale of physical storage
volumes; and
- a decrease of $1 million in selling,
general and administrative expenses primarily due to lower
employee-related costs.
Interstate Transportation and
Storage
Three Months EndedDecember 31,
2015 2014 Natural gas
transported (MMBtu/d) 5,739,157 6,125,616 Natural gas sold
(MMBtu/d) 18,665 15,643 Revenues $ 258 $ 267 Operating expenses,
excluding non-cash compensation, amortization and accretion
expenses (83 ) (72 ) Selling, general and administrative expenses,
excluding non-cash compensation, amortization and accretion
expenses (9 ) (16 ) Adjusted EBITDA related to unconsolidated
affiliates 117 117 Other — 11 Segment
Adjusted EBITDA $ 283 $ 307 Distributions from
unconsolidated affiliates $ 75 $ 80
Transported volumes decreased primarily due to a managed
contract roll off to facilitate the transfer of one of the
pipelines that was taken out of service in advance of being
repurposed from natural gas service to crude oil service. The
decrease was partially offset by increased deliveries on the
Transwestern pipeline due to sustained cooling demand in the
Phoenix market and increased customer demand in New Mexico.
Segment Adjusted EBITDA for the interstate transportation and
storage segment decreased primarily due to a $9 million decrease in
revenues due to the expiration of a transportation rate schedule on
the Transwestern pipeline and $8 million due to a managed contract
roll off to facilitate the transfer of one of the pipelines that
was taken out of service in advance of being repurposed from
natural gas service to crude oil service. These decreases were
partially offset by sales of capacity at higher rates on the
Panhandle, Trunkline and Transwestern pipelines.
The decrease in cash distributions from unconsolidated
affiliates reflected a decrease in cash distributions from Citrus
due to slightly higher cash taxes on Citrus for the three months
ended December 31, 2015.
Intrastate Transportation and
Storage
Three Months EndedDecember 31,
2015 2014 Natural gas
transported (MMBtu/d) 7,926,907 8,485,823 Revenues $ 503 $ 610 Cost
of products sold 327 446 Gross margin
176 164 Unrealized gains on commodity risk management activities
(23 ) (4 ) Operating expenses, excluding non-cash compensation
expense (42 ) (49 ) Selling, general and administrative expenses,
excluding non-cash compensation expense (4 ) (6 ) Adjusted EBITDA
related to unconsolidated affiliates 15 15
Segment Adjusted EBITDA $ 122 $ 120
Transported volumes decreased compared to the same period last
year primarily due to lower production volume, mostly in the
Barnett Shale region, partially offset by increased volumes related
to significant new long-term transportation contracts.
For the three months ended December 31, 2015 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 $6 million in
transportation fees margin (excluding changes in unrealized loss of
$1 million), primarily due to increased revenue from renegotiated
and newly initiated long-term fixed-capacity fee contracts on our
Houston Pipeline system;
- a decrease of $7 million in operating
expenses primarily due to a decrease in fuel consumption expense
driven by a decrease in fuel market prices; and
- a decrease of $2 million in selling,
general and administrative expenses primarily due to lower
employee-related costs; partially offset by
- a decrease of $3 million in storage
margin (excluding changes in unrealized gains of $14 million),
primarily due to the timing of the movement of market prices;
- a decrease of $2 million (excluding
changes in unrealized gains of $7 million) due to a decrease from
the purchase and sale of natural gas on our system;
- a decrease of $8 million in retained
fuel revenues (excluding changes in unrealized loss of $1 million)
due to significantly lower market prices. The average spot price at
the Houston Ship Channel location for the twelve month period
ending December 31, 2015 decreased by $1.76, or 41%, to $2.57 as
compared to $4.32 for the prior year period.
Investment in Sunoco Logistics
Three Months EndedDecember 31,
2015 2014 Revenue $ 2,305 $
3,875 Cost of products sold(1) 2,067 3,812
Gross margin 238 63 Unrealized (gains) losses on commodity
risk management activities 13 (3 ) Operating expenses, excluding
non-cash compensation expense(1) (42 ) (63 ) Selling, general and
administrative expenses, excluding non-cash compensation expense
(24 ) (32 ) Inventory valuation adjustments 118 258 Adjusted EBITDA
related to unconsolidated affiliates 14 13 Other —
1 Segment Adjusted EBITDA $ 317 $ 237
(1) Prior period expenses have been recast to conform
to Sunoco Logistics’ current presentation.
For the three months ended December 31, 2015 compared to
the same period last year, Segment Adjusted EBITDA related to
Sunoco Logistics increased due to the following:
- an increase of $9 million from crude
oil pipelines, primarily due to the commencement of operations on
the Permian Express 2 pipeline in the third quarter of 2015. Higher
contributions from crude oil terminals also contributed to the
increase. These positive factors were partially offset by decreased
margins related to crude oil acquisition and marketing activities
which were negatively impacted by narrowing crude oil differentials
compared to the same period last year;
- an increase of $36 million from NGL
pipelines, primarily due to improved contributions from NGLs
pipelines which was driven by the Mariner South and Mariner East 1
pipeline projects which commenced operations in late 2014.
Increased results from the Nederland and Marcus Hook NGLs terminals
also contributed to the increase. These positive factors were
partially offset by decreased margins related to NGLs acquisition
and marketing activities; and
- an increase of $35 million from refined
products pipelines, primarily due to increased contributions which
was largely attributable to the Allegheny Access pipeline which
commenced operations in the first quarter of 2015. Results related
to the refined products terminals and acquisition and marketing
activities improved compared to the prior year period. Adjusted
EBITDA related to refined products joint venture interest also
contributed to the increase.
Retail Marketing
Three Months EndedDecember 31,
2015 2014 Motor fuel outlets and
convenience stores, end of period: Retail 438 1,251 Third-party
wholesale — 5,399 Total 438
6,650 Total motor fuel gallons sold (in
millions): Retail 266 608 Third-party wholesale —
1,304 Total 266 1,912
Motor fuel gross profit (cents/gallon): Retail 24.1 37.4
Third-party wholesale — 13.0 Volume-weighted average for all
gallons 24.1 20.7 Merchandise sales (in millions) $ 143 $ 489
Retail merchandise margin % 25.6 % 30.1 % Revenue $ 777 $
5,920 Cost of products sold 655 5,493
Gross margin 122 427 Unrealized gains on commodity risk management
activities — (7 ) Operating expenses, excluding non-cash
compensation expense (95 ) (283 ) Selling, general and
administrative expenses, excluding non-cash compensation expense (4
) (41 ) Inventory valuation adjustments 2 198 Adjusted EBITDA
related to unconsolidated affiliates 94 1
Segment Adjusted EBITDA $ 119 $ 295
The results reflected above include Sunoco LP for the three
months ended December 31, 2014.
For the three months ended December 31, 2015 compared to
the same period last year, Segment Adjusted EBITDA related to our
retail marketing segment decreased due to the net impacts of the
following:
- a decrease of $57 million due to the
deconsolidation of Sunoco LP as a result of the sale of Sunoco LP’s
general partner interest and incentive distribution rights to ETE
effective July 1, 2015;
- a decrease of $140 million due to
unfavorable fuel margins and $15 million due to unfavorable volumes
in the retail and wholesale channels; and
- a decrease of $7 million in margins as
2014 benefited from favorable regional market conditions for
ethanol; partially offset by
- an increase of $19 million in
merchandise margins and $9 million from other retail and wholesale
margins;
- a favorable impact of $8 million from
recent acquisitions; and
- a decrease of $7 million in expenses
primarily due to one-time acquisition costs in 2014.
All Other
Three Months EndedDecember 31,
2015 2014 Revenue $ 853 $ 949
Cost of products sold 748 868 Gross
margin 105 81 Unrealized gains on commodity risk management
activities (3 ) (12 ) Operating expenses, excluding non-cash
compensation expense (24 ) (31 ) Selling, general and
administrative expenses, excluding non-cash compensation expense
(31 ) (28 ) Adjusted EBITDA related to unconsolidated affiliates
(20 ) 17 Other 19 17 Elimination (13 ) 6
Segment Adjusted EBITDA $ 33 $ 50
Distributions from unconsolidated affiliates $ 43 $ 3
Amounts reflected in our all other segment primarily
include:
- our natural gas marketing and
compression operations;
- an approximate 33% non-operating
interest in PES, a refining joint venture;
- our investment in Coal Handling, an
entity that owns and operates end-user coal handling facilities;
and
- our investment in AmeriGas until August
2014.
Segment Adjusted EBITDA decreased primarily due to lower
earnings driven by the impact of weaker refining crack spreads on
our investment in PES.
In connection with the Lake Charles LNG Transaction, ETP agreed
to continue to provide management services for ETE through 2015 in
relation to both Lake Charles LNG’s regasification facility and the
development of a liquefaction project at Lake Charles LNG’s
facility, for which ETE has agreed to pay incremental management
fees to ETP of $75 million per year for the years ending December
31, 2014 and 2015. These fees were reflected in “Other” in the “All
other” segment and for the three months ended December 31,
2015 were reflected as an offset to operating expenses of
$6 million and selling, general and administrative expenses of
$13 million in the consolidated statements of operations.
The increase in cash distributions from
unconsolidated affiliates was due to an increase of $42 million in
cash distributions from our ownership in PES.
SUPPLEMENTAL
INFORMATION ON CAPITAL EXPENDITURES
(Tabular amounts in millions) (unaudited)
The following is a summary of capital expenditures (net of
contributions in aid of construction costs) during the year ended
December 31, 2015:
Growth Maintenance Total Direct(1): Midstream
$ 2,055 $ 117 $ 2,172 Liquids transportation and services(2) 2,091
18 2,109 Interstate transportation and storage(2) 741 119 860
Intrastate transportation and storage 74 31 105 Retail marketing(3)
259 63 322 All other (including eliminations) 337 46
383
Total direct capital expenditures
5,557 394 5,951 Indirect(1): Investment in Sunoco Logistics 2,042
84 2,126 Investment in Sunoco LP(4) 83 7 90
Total indirect capital expenditures 2,125 91
2,216 Total capital expenditures $ 7,682 $ 485 $ 8,167 (1)
Indirect capital expenditures comprise those funded by our
publicly traded subsidiaries; all other capital expenditures are
reflected as direct capital expenditures. (2) Includes capital
expenditures related to our proportionate ownership of the Bakken
and Rover pipeline projects. (3) The retail marketing segment
includes our wholly-owned retail marketing operations. (4)
Investment in Sunoco LP includes capital expenditures for the
period prior to deconsolidation on July 1, 2015.
We currently expect capital expenditures for the full year 2016
to be within the following ranges:
Growth Maintenance Low High Low High
Direct(1): Midstream $ 1,200 $ 1,250 $ 110 $ 120 Liquids
transportation and services NGL 1,150 1,200 25 30 Crude(3) 1,275
1,325 — — Interstate transportation and storage(2)(3) 375 415 140
145 Intrastate transportation and storage(2) 10 20 35 40 All other
(including eliminations) 65 75 20 25
Total direct capital expenditures 4,075 4,285 330 360 Indirect(1):
Investment in Sunoco Logistics 2,600 2,800 75
85 Total projected capital expenditures $ 6,675 $ 7,085 $
405 $ 445 (1) Indirect capital expenditures comprise
those funded by our publicly traded subsidiary; all other capital
expenditures are reflected as direct capital expenditures. (2) Net
of amounts forecasted to be financed at the asset level with
non-recourse debt of approximately $325 million. (3) Includes
capital expenditures related to our proportionate ownership of the
Bakken and Rover pipeline projects.
SUPPLEMENTAL
INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions) (unaudited)
Three Months EndedDecember 31,
2015 2014
Equity in earnings
(losses) of unconsolidated affiliates: Citrus $ 20 $ 20 FEP 14
14 PES (25 ) 10 MEP 12 13 HPC 8 3 AmeriGas (5 ) (2 ) Sunoco, LLC 3
— Sunoco LP 85 — Other (31 ) 9 Total equity in
earnings of unconsolidated affiliates $ 81 $ 67
Adjusted EBITDA related to unconsolidated
affiliates(1)
: Citrus $ 73 $ 72 FEP 19 19 PES (16 ) 17
MEP 25 26 HPC 15 9 Sunoco, LLC 38 — Sunoco LP 56 — Other 16
21 Total Adjusted EBITDA related to
unconsolidated affiliates $ 226 $ 164
Distributions received from unconsolidated affiliates:
Citrus $ 37 $ 42 FEP 18 19 PES 42 — MEP 20 19 HPC 11 13 Sunoco LP
39 — Other 12 10 Total distributions
received from unconsolidated affiliates $ 179 $ 103
(1) These amounts represent our proportionate share
of the Adjusted EBITDA of our unconsolidated affiliates and are
based on our equity in earnings or losses of our unconsolidated
affiliates adjusted for our proportionate share of the
unconsolidated affiliates’ interest, depreciation, depletion,
amortization, non-cash items and taxes.
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version on businesswire.com: http://www.businesswire.com/news/home/20160224006658/en/
Investor Relations:Energy TransferBrent Ratliff,
214-981-0700orLyndsay Hannah, 214-840-5477orMedia
Relations:Granado Communications GroupVicki Granado,
214-599-8785214-498-9272 (cell)
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