Energy Transfer Partners, L.P. (NYSE: ETP) (“ETP” or the
“Partnership”) today reported its financial results for the quarter
ended September 30, 2015. Adjusted EBITDA for ETP for the three months
ended September 30, 2015 totaled $1.50 billion, an increase of
$49 million compared to the same period last year. Distributable Cash
Flow attributable to the partners of ETP, as adjusted, for the three
months ended September 30, 2015 totaled $740 million, a decrease of
$130 million compared to the same period last year. Income from
continuing operations for the three months ended September 30, 2015 was
$393 million, a decrease of $121 million compared to the same period
last year.
Distributable Cash Flow for the third quarter of 2015 was affected by a
partial reversal from the second quarter 2015 tax benefit, with $79
million of current income tax expense for the third quarter of 2015.
Distributable Cash Flow was also affected this quarter by a lower
overall pricing environment for percent-of-proceeds volumes, continued
shut-in volumes in the Northeast and unscheduled plant outages in the
Permian Basin.
In October 2015, ETP announced an increase in its quarterly distribution
to $1.055 per Partnership common unit ($4.22 annualized) for the quarter
ended September 30, 2015, representing an increase of $0.32 per
Partnership common unit on an annualized basis, or 8.2%, compared to the
third quarter of 2014.
ETP’s other recent key accomplishments include the following:
-
Effective July 1, 2015, Energy Transfer Equity, L.P. (“ETE”) acquired
100% of the membership interests of Sunoco GP LLC (“Sunoco GP”), the
general partner of Sunoco LP, and all of the IDRs of Sunoco LP from
ETP, and in exchange, ETE transferred to ETP 21 million ETP common
units. In connection with ETP’s 2014 acquisition of Susser, ETE agreed
to provide ETP a $35 million annual IDR subsidy for 10 years, which
terminated upon the closing of ETE’s acquisition of Sunoco GP. In
connection with the exchange and repurchase, ETE will provide ETP a
$35 million annual IDR subsidy for two years beginning with the
quarter ended September 30, 2015. In connection with this transaction,
the Partnership deconsolidated Sunoco LP. The Partnership continues to
hold 26.8 million Sunoco LP common units and 10.9 million Sunoco LP
subordinated units accounted for under the equity method.
-
In October 2015, Sunoco Logistics Partners L.P. (“Sunoco Logistics”)
completed the previously announced acquisition of a 40% membership
interest (the “Bakken Membership Interest”) in Bakken Holdings Company
LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned
subsidiaries, owns a 75% membership interest in each of Dakota Access,
LLC and Energy Transfer Crude Oil Company, LLC, which together intend
to develop the previously announced pipeline system to deliver crude
oil from the Bakken/Three Forks production area in North Dakota to the
Gulf Coast (the “Bakken Pipeline Project”). ETP transferred the Bakken
Membership Interest to Sunoco Logistics in exchange for approximately
9.4 million Class B Units representing limited partner interests in
Sunoco Logistics and the payment by Sunoco Logistics to ETP of
$382 million of cash, which represented reimbursement for its
proportionate share of the total cash contributions made in the Bakken
Pipeline Project as of the date of closing of the exchange transaction.
-
During the third quarter 2015, Lake Charles LNG Export Company, LLC
(“Lake Charles LNG”), an entity owned 60% by ETE and 40% by ETP,
received the Federal Energy Regulatory Commission (“FERC”) Final
Environmental Impact Study for the liquefaction project. This issuance
starts the 90-day period in which other federal agencies are required
to complete their review of the liquefaction project and issue any
necessary agency authorizations. That decision deadline is November
12, 2015. The FERC authorization for the liquefaction project is
expected to be issued during this 90-day period. With the expected
emphasis on capital discipline and overall cost, ETP continues to
believe that Lake Charles LNG is one of the most attractive pre-final
investment decision (“FID”) projects for both Royal Dutch Shell plc
and BG Group plc and that as a result, the project remains on track to
receive FID in 2016, with construction to start immediately thereafter
and first LNG exports anticipated in late-2020.
-
As of September 30, 2015, the ETP Credit Facility had $665 million
outstanding borrowings and its credit ratio, as defined by the credit
agreement, was 4.49x.
-
In the third quarter of 2015, ETP issued 4.4 million common units
through its at-the-market equity program, generating net proceeds of
$206 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, November 5, 2015
to discuss the third quarter 2015 results. The conference call will be
broadcast live via an internet web cast, which can be accessed through www.energytransfer.com
and will also be available for replay on ETP’s web site 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 50.8% 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. web site
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 81.0 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. web site at www.energytransfer.com.
Sunoco Logistics Partners L.P. (NYSE: SXL) 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 owned by Energy Transfer Partners, L.P.
(NYSE: ETP). For more information, visit the Sunoco Logistics Partners,
L.P. web site 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 Partnership’s 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 web
site at www.energytransfer.com.
|
|
|
|
|
ENERGY TRANSFER PARTNERS, L.P. AND
SUBSIDIARIES
|
CONDENSED CONSOLIDATED BALANCE SHEETS
|
(In millions)
|
(unaudited)
|
|
|
|
|
|
|
|
September 30, 2015
|
|
December 31, 2014
|
ASSETS
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS
|
|
$
|
5,325
|
|
|
$
|
6,043
|
|
|
|
|
|
PROPERTY, PLANT AND EQUIPMENT, net
|
|
|
42,821
|
|
|
|
38,907
|
|
|
|
|
|
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES
|
|
|
5,119
|
|
|
|
3,760
|
NON-CURRENT DERIVATIVE ASSETS
|
|
|
15
|
|
|
|
10
|
OTHER NON-CURRENT ASSETS, net
|
|
|
738
|
|
|
|
786
|
INTANGIBLE ASSETS, net
|
|
|
4,494
|
|
|
|
5,526
|
GOODWILL
|
|
|
5,633
|
|
|
|
7,642
|
Total assets
|
|
$
|
64,145
|
|
|
$
|
62,674
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
$
|
4,483
|
|
|
$
|
6,684
|
|
|
|
|
|
LONG-TERM DEBT, less current maturities
|
|
|
27,449
|
|
|
|
24,973
|
NON-CURRENT DERIVATIVE LIABILITIES
|
|
|
189
|
|
|
|
154
|
DEFERRED INCOME TAXES
|
|
|
3,768
|
|
|
|
4,246
|
OTHER NON-CURRENT LIABILITIES
|
|
|
1,144
|
|
|
|
1,258
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES
|
|
|
|
|
SERIES A PREFERRED UNITS
|
|
|
33
|
|
|
|
33
|
REDEEMABLE NONCONTROLLING INTERESTS
|
|
|
15
|
|
|
|
15
|
|
|
|
|
|
EQUITY:
|
|
|
|
|
Total partners’ capital
|
|
|
21,074
|
|
|
|
12,070
|
Noncontrolling interest
|
|
|
5,990
|
|
|
|
5,153
|
Predecessor equity
|
|
|
—
|
|
|
|
8,088
|
Total equity
|
|
|
27,064
|
|
|
|
25,311
|
Total liabilities and equity
|
|
$
|
64,145
|
|
|
$
|
62,674
|
|
|
|
|
|
ENERGY TRANSFER PARTNERS, L.P. AND
SUBSIDIARIES
|
CONDENSED CONSOLIDATED STATEMENTS OF
OPERATIONS
|
(In millions, except per unit data)
|
(unaudited)
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2015
|
|
|
|
2014
|
|
|
2015
|
|
|
2014
|
|
REVENUES
|
|
$
|
6,601
|
|
|
$
|
14,933
|
|
|
$
|
28,467
|
|
|
$
|
42,048
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
|
Cost of products sold
|
|
|
4,925
|
|
|
|
13,014
|
|
|
22,750
|
|
|
36,808
|
|
Operating expenses
|
|
|
535
|
|
|
|
547
|
|
|
1,805
|
|
|
1,378
|
|
Depreciation, depletion and amortization
|
|
|
471
|
|
|
|
410
|
|
|
1,451
|
|
|
1,206
|
|
Selling, general and administrative
|
|
|
94
|
|
|
|
152
|
|
|
389
|
|
|
372
|
|
Total costs and expenses
|
|
|
6,025
|
|
|
|
14,123
|
|
|
26,395
|
|
|
39,764
|
|
OPERATING INCOME
|
|
|
576
|
|
|
|
810
|
|
|
2,072
|
|
|
2,284
|
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
Interest expense, net of interest capitalized
|
|
|
(333
|
)
|
|
|
(299
|
)
|
|
(979
|
)
|
|
(868
|
)
|
Equity in earnings of unconsolidated affiliates
|
|
|
214
|
|
|
|
84
|
|
|
388
|
|
|
265
|
|
Losses on extinguishments of debt
|
|
|
(10
|
)
|
|
|
—
|
|
|
(43
|
)
|
|
—
|
|
Gain on sale of AmeriGas common units
|
|
|
—
|
|
|
|
14
|
|
|
—
|
|
|
177
|
|
Losses on interest rate derivatives
|
|
|
(64
|
)
|
|
|
(25
|
)
|
|
(14
|
)
|
|
(73
|
)
|
Other, net
|
|
|
32
|
|
|
|
(15
|
)
|
|
56
|
|
|
(36
|
)
|
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
|
|
|
415
|
|
|
|
569
|
|
|
1,480
|
|
|
1,749
|
|
Income tax expense (benefit) from continuing operations
|
|
|
22
|
|
|
|
55
|
|
|
(20
|
)
|
|
271
|
|
INCOME FROM CONTINUING OPERATIONS
|
|
|
393
|
|
|
|
514
|
|
|
1,500
|
|
|
1,478
|
|
Income from discontinued operations
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
66
|
|
NET INCOME
|
|
|
393
|
|
|
|
514
|
|
|
1,500
|
|
|
1,544
|
|
Less: Net income (loss) attributable to noncontrolling interest
|
|
|
(24
|
)
|
|
|
78
|
|
|
182
|
|
|
219
|
|
Less: Net income (loss) attributable to predecessor
|
|
|
—
|
|
|
|
94
|
|
|
(34
|
)
|
|
97
|
|
NET INCOME ATTRIBUTABLE TO PARTNERS
|
|
|
417
|
|
|
|
342
|
|
|
1,352
|
|
|
1,228
|
|
General Partner’s interest in net income
|
|
|
277
|
|
|
|
135
|
|
|
779
|
|
|
373
|
|
Class H Unitholder’s interest in net income
|
|
|
66
|
|
|
|
59
|
|
|
184
|
|
|
159
|
|
Class I Unitholder’s interest in net income
|
|
|
15
|
|
|
|
—
|
|
|
80
|
|
|
—
|
|
Common Unitholders’ interest in net income
|
|
$
|
59
|
|
|
$
|
148
|
|
|
$
|
309
|
|
|
$
|
696
|
|
INCOME FROM CONTINUING OPERATIONS PER COMMON UNIT:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.11
|
|
|
$
|
0.44
|
|
|
$
|
0.70
|
|
|
$
|
1.91
|
|
Diluted
|
|
$
|
0.10
|
|
|
$
|
0.44
|
|
|
$
|
0.68
|
|
|
$
|
1.90
|
|
NET INCOME PER COMMON UNIT:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.11
|
|
|
$
|
0.44
|
|
|
$
|
0.70
|
|
|
$
|
2.11
|
|
Diluted
|
|
$
|
0.10
|
|
|
$
|
0.44
|
|
|
$
|
0.68
|
|
|
$
|
2.10
|
|
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
485.0
|
|
|
|
331.4
|
|
|
415.1
|
|
|
324.8
|
|
Diluted
|
|
|
487.3
|
|
|
|
333.1
|
|
|
417.7
|
|
|
326.5
|
|
|
|
|
|
|
SUPPLEMENTAL INFORMATION
|
(Dollars and units in millions, except per unit amounts)
|
(unaudited)
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
2015
|
|
|
|
2014
|
|
Reconciliation of net income to Adjusted EBITDA and Distributable
Cash Flow (a):
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
393
|
|
|
$
|
514
|
|
|
$
|
1,500
|
|
|
$
|
1,544
|
|
Interest expense, net of interest capitalized
|
|
|
333
|
|
|
|
299
|
|
|
|
979
|
|
|
|
868
|
|
Gain on sale of AmeriGas common units
|
|
|
—
|
|
|
|
(14
|
)
|
|
|
—
|
|
|
|
(177
|
)
|
Income tax expense (benefit) from continuing operations (b)
|
|
|
22
|
|
|
|
55
|
|
|
|
(20
|
)
|
|
|
271
|
|
Depreciation, depletion and amortization
|
|
|
471
|
|
|
|
410
|
|
|
|
1,451
|
|
|
|
1,206
|
|
Non-cash compensation expense
|
|
|
16
|
|
|
|
18
|
|
|
|
59
|
|
|
|
50
|
|
Losses on interest rate derivatives
|
|
|
64
|
|
|
|
25
|
|
|
|
14
|
|
|
|
73
|
|
Unrealized (gains) losses on commodity risk management activities
|
|
|
(47
|
)
|
|
|
(32
|
)
|
|
|
72
|
|
|
|
1
|
|
Inventory valuation adjustments
|
|
|
134
|
|
|
|
51
|
|
|
|
(16
|
)
|
|
|
17
|
|
Losses on extinguishments of debt
|
|
|
10
|
|
|
|
—
|
|
|
|
43
|
|
|
|
—
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
(214
|
)
|
|
|
(84
|
)
|
|
|
(388
|
)
|
|
|
(265
|
)
|
Adjusted EBITDA related to unconsolidated affiliates
|
|
|
350
|
|
|
|
184
|
|
|
|
711
|
|
|
|
584
|
|
Other, net
|
|
|
(32
|
)
|
|
|
25
|
|
|
|
(51
|
)
|
|
|
10
|
|
Adjusted EBITDA (consolidated)
|
|
|
1,500
|
|
|
|
1,451
|
|
|
|
4,354
|
|
|
|
4,182
|
|
Adjusted EBITDA related to unconsolidated affiliates
|
|
|
(350
|
)
|
|
|
(184
|
)
|
|
|
(711
|
)
|
|
|
(584
|
)
|
Distributable cash flow from unconsolidated affiliates (c)
|
|
|
232
|
|
|
|
131
|
|
|
|
468
|
|
|
|
363
|
|
Interest expense, net of interest capitalized
|
|
|
(333
|
)
|
|
|
(299
|
)
|
|
|
(979
|
)
|
|
|
(868
|
)
|
Amortization included in interest expense
|
|
|
(9
|
)
|
|
|
(15
|
)
|
|
|
(30
|
)
|
|
|
(48
|
)
|
Current income tax (expense) benefit from continuing operations
|
|
|
(79
|
)
|
|
|
(10
|
)
|
|
|
42
|
|
|
|
(337
|
)
|
Transaction-related income taxes (d)
|
|
|
—
|
|
|
|
34
|
|
|
|
—
|
|
|
|
381
|
|
Maintenance capital expenditures
|
|
|
(124
|
)
|
|
|
(122
|
)
|
|
|
(308
|
)
|
|
|
(260
|
)
|
Other, net
|
|
|
4
|
|
|
|
5
|
|
|
|
11
|
|
|
|
5
|
|
Distributable Cash Flow (consolidated)
|
|
|
841
|
|
|
|
991
|
|
|
|
2,847
|
|
|
|
2,834
|
|
Distributable Cash Flow attributable to SXL (100%)
|
|
|
(210
|
)
|
|
|
(194
|
)
|
|
|
(634
|
)
|
|
|
(573
|
)
|
Distributions from SXL to ETP
|
|
|
107
|
|
|
|
74
|
|
|
|
295
|
|
|
|
204
|
|
Distributable Cash Flow attributable to Sunoco LP (100%) (e)
|
|
|
—
|
|
|
|
(4
|
)
|
|
|
(68
|
)
|
|
|
(4
|
)
|
Distributions from Sunoco LP to ETP (e)
|
|
|
—
|
|
|
|
8
|
|
|
|
24
|
|
|
|
8
|
|
Distributable cash flow attributable to noncontrolling interest in
Edwards Lime Gathering LLC
|
|
|
(5
|
)
|
|
|
(5
|
)
|
|
|
(15
|
)
|
|
|
(14
|
)
|
Distributable Cash Flow attributable to the partners of ETP
|
|
|
733
|
|
|
|
870
|
|
|
|
2,449
|
|
|
|
2,455
|
|
Transaction-related expenses
|
|
|
7
|
|
|
|
—
|
|
|
|
37
|
|
|
|
—
|
|
Distributable Cash Flow attributable to the partners of ETP, as
adjusted
|
|
$
|
740
|
|
|
$
|
870
|
|
|
$
|
2,486
|
|
|
$
|
2,455
|
|
|
|
|
|
|
|
|
|
|
Distributions to the partners of ETP (f):
|
|
|
|
|
|
|
|
|
Limited Partners:
|
|
|
|
|
|
|
|
|
Common Units held by public
|
|
$
|
508
|
|
|
$
|
312
|
|
|
$
|
1,458
|
|
|
$
|
858
|
|
Common Units held by ETE
|
|
|
3
|
|
|
|
30
|
|
|
|
51
|
|
|
|
88
|
|
Class H Units held by ETE (g)
|
|
|
68
|
|
|
|
56
|
|
|
|
186
|
|
|
|
159
|
|
General Partner interests held by ETE
|
|
|
8
|
|
|
|
6
|
|
|
|
23
|
|
|
|
16
|
|
Incentive Distribution Rights (“IDRs”) held by ETE
|
|
|
320
|
|
|
|
200
|
|
|
|
937
|
|
|
|
546
|
|
IDR relinquishments net of Class I Unit distributions
|
|
|
(28
|
)
|
|
|
(67
|
)
|
|
|
(83
|
)
|
|
|
(182
|
)
|
Total distributions to be paid to the partners of ETP
|
|
$
|
879
|
|
|
$
|
537
|
|
|
$
|
2,572
|
|
|
$
|
1,485
|
|
Common Units outstanding – end of period
|
|
|
495.6
|
|
|
|
351.0
|
|
|
|
495.6
|
|
|
|
351.0
|
|
Distribution coverage ratio (h)
|
|
0.84x
|
|
1.62x
|
|
0.97x
|
|
1.65x
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow per Common Unit (i)
|
|
$
|
0.77
|
|
|
$
|
2.04
|
|
|
$
|
3.43
|
|
|
$
|
5.90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 nine months ended September 30, 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 nine months ended September 30,
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. For the three and nine months
ended September 30, 2015, the Partnership’s income tax expense was
favorably impacted by $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. Additionally, the Partnership
recognized a net tax benefit of $7 million related to the settlement of
the Southern Union 2004-2009 Internal Revenue Service (“IRS”)
examination in July 2015. For the three and nine months ended
September 30, 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.
(c) For the three and nine months ended September 30, 2015,
distributions from unconsolidated affiliates includes distributions to
be paid by Sunoco LP with respect to the third quarter of 2015, as well
as the Partnership’s share of the distributable cash flow of Sunoco LLC
for the third quarter of 2015.
(d) Transaction-related income taxes primarily included income tax
expense related to the Lake Charles LNG Transaction. For the three and
nine months ended September 30, 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 and nine months
ended September 30, 2015 and 2014 were calculated as follows:
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
2015
|
|
|
|
2014
|
|
General partner distributions and incentive distributions from SXL
|
|
$
|
76
|
|
|
$
|
49
|
|
|
$
|
207
|
|
|
$
|
131
|
|
|
|
|
90.05
|
%
|
|
|
50.05
|
%
|
|
|
90.05
|
%
|
|
|
50.05
|
%
|
Share of SXL general partner and incentive distributions payable to
Class H Unitholder
|
|
|
68
|
|
|
|
25
|
|
|
|
186
|
|
|
|
66
|
|
Incremental distributions payable to Class H Unitholder (IDR subsidy
offset)*
|
|
|
—
|
|
|
|
31
|
|
|
|
—
|
|
|
|
93
|
|
Total Class H Unit distributions
|
|
$
|
68
|
|
|
$
|
56
|
|
|
$
|
186
|
|
|
$
|
159
|
|
* 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 Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
2015
|
|
|
|
2014
|
|
Distributable Cash Flow attributable to the partners of ETP, as
adjusted
|
|
$
|
740
|
|
|
$
|
870
|
|
|
$
|
2,486
|
|
|
$
|
2,455
|
|
Less:
|
|
|
|
|
|
|
|
|
Class H Units held by ETE
|
|
|
(68
|
)
|
|
|
(56
|
)
|
|
|
(186
|
)
|
|
|
(159
|
)
|
General Partner interests held by ETE
|
|
|
(8
|
)
|
|
|
(6
|
)
|
|
|
(23
|
)
|
|
|
(16
|
)
|
IDRs held by ETE
|
|
|
(320
|
)
|
|
|
(200
|
)
|
|
|
(937
|
)
|
|
|
(546
|
)
|
IDR relinquishments net of Class I Unit distributions
|
|
|
28
|
|
|
|
67
|
|
|
|
83
|
|
|
|
182
|
|
|
|
$
|
372
|
|
|
$
|
675
|
|
|
$
|
1,423
|
|
|
$
|
1,916
|
|
Weighted average Common Units outstanding – basic
|
|
|
485.0
|
|
|
|
331.4
|
|
|
|
415.1
|
|
|
|
324.8
|
|
Distributable Cash Flow per Common Unit
|
|
$
|
0.77
|
|
|
$
|
2.04
|
|
|
$
|
3.43
|
|
|
$
|
5.90
|
|
|
|
|
|
|
|
|
|
|
SUMMARY ANALYSIS OF QUARTERLY RESULTS BY
SEGMENT
|
(Tabular dollar amounts in millions)
|
(unaudited)
|
|
Our segment results were 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 Ended September 30,
|
|
|
2015
|
|
|
2014
|
Segment Adjusted EBITDA:
|
|
|
|
|
Midstream
|
|
$
|
318
|
|
|
$
|
379
|
Liquids transportation and services
|
|
|
192
|
|
|
|
163
|
Interstate transportation and storage
|
|
|
286
|
|
|
|
288
|
Intrastate transportation and storage
|
|
|
127
|
|
|
|
124
|
Investment in Sunoco Logistics
|
|
|
289
|
|
|
|
246
|
Retail marketing
|
|
|
195
|
|
|
|
191
|
All other
|
|
|
93
|
|
|
|
60
|
|
|
$
|
1,500
|
|
|
$
|
1,451
|
|
|
Midstream
|
|
|
|
|
Three Months Ended September 30,
|
|
|
2015
|
|
|
|
2014
|
|
Gathered volumes (MMBtu/d)
|
|
10,384,788
|
|
|
|
9,150,060
|
|
NGLs produced (Bbls/d)
|
|
413,426
|
|
|
|
364,302
|
|
Equity NGLs (Bbls/d)
|
|
26,296
|
|
|
|
30,703
|
|
Revenues
|
$
|
1,383
|
|
|
$
|
1,967
|
|
Cost of products sold
|
|
916
|
|
|
|
1,428
|
|
Gross margin
|
|
467
|
|
|
|
539
|
|
Unrealized gains on commodity risk management activities
|
|
—
|
|
|
|
(16
|
)
|
Operating expenses, excluding non-cash compensation expense
|
|
(148
|
)
|
|
|
(136
|
)
|
Selling, general and administrative expenses, excluding non-cash
compensation expense
|
|
(9
|
)
|
|
|
(12
|
)
|
Adjusted EBITDA related to unconsolidated affiliates
|
|
6
|
|
|
|
4
|
|
Other
|
|
2
|
|
|
|
—
|
|
Segment Adjusted EBITDA
|
$
|
318
|
|
|
$
|
379
|
|
|
|
|
|
Gathered volumes and NGLs produced increased primarily due to 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 Ended September 30,
|
|
|
|
2015
|
|
|
2014
|
Gathering and processing fee-based revenues
|
|
$
|
400
|
|
$
|
352
|
Non fee-based contracts and processing
|
|
|
67
|
|
|
187
|
Total gross margin
|
|
$
|
467
|
|
$
|
539
|
|
|
|
|
|
|
|
Midstream gross margin reflected an increase in fee-based revenues of
$46 million primarily due to increased production and increased capacity
from assets recently placed in service in the Eagle Ford Shale, Permian
Basin and Cotton Valley. Midstream gross margin reflected a decrease in
non fee-based revenues due to lower commodity prices. The decrease
between periods also reflected the impact from $16 million of gains on
commodity risk management activities recorded in the prior period.
Segment Adjusted EBITDA for the midstream segment reflected higher
operating expenses primarily due to additional expense from assets
recently placed in service, including the Rebel system in west Texas and
the King Ranch system in south Texas.
Segment Adjusted EBITDA for the midstream segment also reflected lower
selling, general and administrative expenses primarily due to a
reduction in employee-related costs.
|
|
|
Liquids Transportation and Services
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2015
|
|
|
|
2014
|
|
Liquids transportation volumes (Bbls/d)
|
|
|
442,683
|
|
|
|
352,990
|
|
NGL fractionation volumes (Bbls/d)
|
|
|
236,874
|
|
|
|
226,847
|
|
Revenues
|
|
$
|
854
|
|
|
$
|
1,196
|
|
Cost of products sold
|
|
|
614
|
|
|
|
994
|
|
Gross margin
|
|
|
240
|
|
|
|
202
|
|
Unrealized gains on commodity risk management activities
|
|
|
(4
|
)
|
|
|
(2
|
)
|
Operating expenses, excluding non-cash compensation expense
|
|
|
(40
|
)
|
|
|
(33
|
)
|
Selling, general and administrative expenses, excluding non-cash
compensation expense
|
|
|
(4
|
)
|
|
|
(6
|
)
|
Adjusted EBITDA related to unconsolidated affiliates
|
|
|
—
|
|
|
|
2
|
|
Segment Adjusted EBITDA
|
|
$
|
192
|
|
|
$
|
163
|
|
|
|
|
|
|
|
|
|
|
NGL transportation volumes increased due to an increase in volumes
transported on our Lone Star Gateway pipeline system of 63,000 Bbls/d.
These increased volumes were primarily out of west Texas as producers
ramped up volumes. Additionally, we commissioned a crude transportation
pipeline at the end of 2014 that transported 37,000 Bbls/d during the
three months ended September 30, 2015. The remainder of the increase
related to volumes on our NGL pipelines from our plants in southeast
Texas and in the Eagle Ford region.
Average daily fractionated volumes increased due to the ramp-up of our
second 100,000 Bbls/d fractionator at Mont Belvieu, Texas, which was
commissioned in October 2013. These volumes include all physical and
contractual volumes where we collected a fractionation fee.
Segment Adjusted EBITDA for the liquids transportation and services
segment reflected an increase in gross margin as follows:
|
|
|
|
|
Three Months Ended September 30,
|
|
|
2015
|
|
|
2014
|
Transportation margin
|
|
$
|
105
|
|
|
$
|
84
|
Processing and fractionation margin
|
|
|
77
|
|
|
|
75
|
Storage margin
|
|
|
41
|
|
|
|
36
|
Other margin
|
|
|
17
|
|
|
|
7
|
Total gross margin
|
|
$
|
240
|
|
|
$
|
202
|
|
|
|
|
|
|
Transportation margin increased $22 million primarily due to higher
volumes transported out of west Texas on our Lone Star Gateway pipeline
system, as noted in the volume discussion above. The commissioning of
our crude transportation pipeline in south Texas also contributed an
additional $2 million to the increase.
Processing and fractionation margin increased $16 million due to the
commissioning of the Mariner South LPG export project during February
2015 and was partially offset by decreases in processing and
fractionation margin of $8 million and $6 million due to lower prices at
our Lone Star fractionators and our off-gas fractionator as Geismar,
Louisiana, respectively.
Storage margin reflected increases of approximately $6 million due to
increased demand for leased storage capacity as a result of favorable
market conditions. These increases in fee based storage margin were
partially offset by a decrease of $2 million from lower non fee-based
storage activities, including blending activities, and lower financial
gains recognized on the withdrawal of inventory from our storage
facilities.
Other margin decreased primarily due to the withdrawal and sale of
physical storage volumes, primarily propanes and butanes.
Segment Adjusted EBITDA for the liquids transportation and services
segment also reflected an increase in operating expenses for the three
months ended September 30, 2015 compared to the same period last year
primarily due to the commissioning of the Mariner South LPG export
project during February 2015 and the ramp-up of Lone Star’s second
fractionator at Mont Belvieu, Texas, which was commissioned in October
2013.
|
|
|
Interstate Transportation and Storage
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2015
|
|
|
|
2014
|
|
Natural gas transported (MMBtu/d)
|
|
|
5,903,285
|
|
|
|
5,785,862
|
|
Natural gas sold (MMBtu/d)
|
|
|
19,171
|
|
|
|
18,697
|
|
Revenues
|
|
$
|
248
|
|
|
$
|
258
|
|
Operating expenses, excluding non-cash compensation, amortization
and accretion expenses
|
|
|
(78
|
)
|
|
|
(81
|
)
|
Selling, general and administrative expenses, excluding non-cash
compensation, amortization and accretion expenses
|
|
|
(14
|
)
|
|
|
(16
|
)
|
Adjusted EBITDA related to unconsolidated affiliates
|
|
|
130
|
|
|
|
127
|
|
Segment Adjusted EBITDA
|
|
$
|
286
|
|
|
$
|
288
|
|
|
|
|
|
|
Distributions from unconsolidated affiliates
|
|
$
|
104
|
|
|
$
|
87
|
|
|
|
|
|
|
|
|
|
|
Transported volumes increased 111,582 MMBtu/d on the Tiger pipeline,
primarily due to increased deliveries to pipelines supporting the upper
Midwest due to favorable market conditions and 77,639 MMBtu/d on the
Transwestern pipeline due to increased customer demand in the Texas
intrastate market. These increases were partially offset by a decrease
of 73,900 MMBtu/d on the Trunkline pipeline as a result of lower
customer demand due to lower price spreads and a managed contract roll
off to facilitate the transfer of one of the pipelines at Trunkline that
was taken out of service in advance of being repurposed from natural gas
service to crude oil service.
Segment Adjusted EBITDA for the interstate transportation and storage
segment decreased primarily due to the expiration of a transportation
rate schedule on the Transwestern pipeline and a managed contract roll
off to facilitate the transfer of one of the 30” pipelines at Trunkline
that was taken out of service in advance of being repurposed from
natural gas to crude oil service.
The increase in cash distributions from unconsolidated affiliates
reflected an increase in cash distributions from Citrus due to an
increase in revenues from the sale of additional Phase VIII capacity.
|
|
|
Intrastate Transportation and Storage
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2015
|
|
|
|
2014
|
|
Natural gas transported (MMBtu/d)
|
|
|
8,308,105
|
|
|
|
8,799,708
|
|
Revenues
|
|
$
|
592
|
|
|
$
|
601
|
|
Cost of products sold
|
|
|
428
|
|
|
|
438
|
|
Gross margin
|
|
|
164
|
|
|
|
163
|
|
Unrealized (gains) losses on commodity risk management activities
|
|
|
(4
|
)
|
|
|
1
|
|
Operating expenses, excluding non-cash compensation expense
|
|
|
(43
|
)
|
|
|
(46
|
)
|
Selling, general and administrative expenses, excluding non-cash
compensation expense
|
|
|
(6
|
)
|
|
|
(9
|
)
|
Adjusted EBITDA related to unconsolidated affiliates
|
|
|
16
|
|
|
|
15
|
|
Segment Adjusted EBITDA
|
|
$
|
127
|
|
|
$
|
124
|
|
|
|
|
|
|
Distributions from unconsolidated affiliates
|
|
$
|
14
|
|
|
$
|
15
|
|
|
|
|
|
|
|
|
|
|
Transported volumes declined compared to the same period last year
primarily due to lower production from certain key shippers in the
Barnett Shale region, offset by increased volumes related to significant
new long-term transportation contracts.
Intrastate transportation and storage gross margin increased $7 million,
despite a reduction in volume, primarily due to increased revenue from
renegotiated and newly initiated long-term fixed capacity fee contracts
on our Houston pipeline system. Additionally, storage margin increased
$2 million primarily due to the timing of the movement of market prices
during the period. These increases were partially offset by a decrease
of $6 million in retained fuel revenues primarily due to significantly
lower market prices and $2 million from natural gas sales and other
primarily due to a decrease in margin from the purchase and sale of
natural gas on our system.
|
|
|
Investment in Sunoco Logistics
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2015
|
|
|
|
2014
|
|
Revenues
|
|
$
|
2,406
|
|
|
$
|
4,915
|
|
Cost of products sold
|
|
|
2,127
|
|
|
|
4,581
|
|
Gross margin
|
|
|
279
|
|
|
|
334
|
|
Unrealized gains on commodity risk management activities
|
|
|
(31
|
)
|
|
|
(21
|
)
|
Operating expenses, excluding non-cash compensation expense
|
|
|
(57
|
)
|
|
|
(55
|
)
|
Selling, general and administrative expenses, excluding non-cash
compensation expense
|
|
|
(23
|
)
|
|
|
(26
|
)
|
Inventory valuation adjustments
|
|
|
103
|
|
|
|
—
|
|
Adjusted EBITDA related to unconsolidated affiliates
|
|
|
18
|
|
|
|
14
|
|
Segment Adjusted EBITDA
|
|
$
|
289
|
|
|
$
|
246
|
|
|
|
|
|
|
Distributions from unconsolidated affiliates
|
|
$
|
5
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
|
Segment Adjusted EBITDA related to Sunoco Logistics increased due to the
net impacts of the following:
-
an increase of $35 million from terminal facilities, primarily
attributable to increased operating results from Sunoco Logistics’
bulk marine terminals of $28 million, which benefited from NGL
contributions at Sunoco Logistics’ Nederland terminal and Marcus Hook
Industrial Complex, and approximately $5 million on the timing of
recognition on committed crude oil throughput volumes under deficiency
agreements. Improved contributions from Sunoco Logistics’ products and
NGLs acquisition and marketing activities of $2 million and refined
products terminals of $3 million also contributed to the increase;
-
an increase of $37 million from products pipelines, primarily due to
higher average pipeline revenue per barrel of $21 million and
increased throughput volumes of $15 million primarily related to the
Mariner NGL and Allegheny Access pipeline projects. Higher
contributions from Sunoco Logistics’ joint venture interests of
$3 million also contributed to the increase. These positive impacts
were partially offset by higher operating expenses of $4 million
largely attributable to growth projects; and
-
an increase of $38 million from crude oil pipelines, primarily due to
increased volumes of $12 million and higher average pipeline revenue
per barrel of $25 million largely related to the Permian Express 2
pipeline that commenced operations in July 2015. Expansion projects
placed into service in 2014 also contributed to the increase;
partially offset by
-
a decrease of $67 million from crude oil acquisition and marketing
activities, primarily attributable to lower gross profit per barrel
purchased, which was negatively impacted by narrowing crude oil
differentials compared to the prior period.
|
|
|
Retail Marketing
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2015
|
|
|
2014
|
|
Motor fuel outlets and convenience stores, end of period:
|
|
|
|
|
Retail
|
|
|
438
|
|
|
1,210
|
|
Third-party wholesale
|
|
|
—
|
|
|
5,287
|
|
Total
|
|
|
438
|
|
|
6,497
|
|
Total motor fuel gallons sold (in millions):
|
|
|
|
|
Retail
|
|
|
390
|
|
|
424
|
|
Third-party wholesale
|
|
|
10
|
|
|
1,198
|
|
Total
|
|
|
400
|
|
|
1,622
|
|
Motor fuel gross profit (cents/gallon):
|
|
|
|
|
Retail
|
|
|
28.5
|
|
|
30.8
|
|
Third-party wholesale
|
|
|
15.1
|
|
|
9.0
|
|
Volume-weighted average for all gallons
|
|
|
28.2
|
|
|
14.7
|
|
Merchandise sales (in millions)
|
|
$
|
285
|
|
|
$
|
287
|
|
Retail merchandise margin %
|
|
|
30.2
|
%
|
|
28.8
|
%
|
|
|
|
|
|
Revenues
|
|
$
|
1,363
|
|
|
$
|
5,988
|
|
Cost of products sold
|
|
|
1,149
|
|
|
5,645
|
|
Gross margin
|
|
|
214
|
|
|
343
|
|
Unrealized (gains) losses on commodity risk management activities
|
|
|
(1
|
)
|
|
4
|
|
Operating expenses, excluding non-cash compensation expense
|
|
|
(149
|
)
|
|
(183
|
)
|
Selling, general and administrative expenses, excluding non-cash
compensation expense
|
|
|
(8
|
)
|
|
(24
|
)
|
Inventory valuation adjustments
|
|
|
4
|
|
|
51
|
|
Adjusted EBITDA related to unconsolidated affiliates
|
|
|
135
|
|
|
—
|
|
Segment Adjusted EBITDA
|
|
$
|
195
|
|
|
$
|
191
|
|
|
|
|
|
|
|
|
|
|
Segment Adjusted EBITDA for the retail marketing segment increased due
to the net impacts of the following:
-
the favorable impact of recent acquisitions, including $81 million
from the acquisition of Susser in August 2014 and $15 million from the
acquisition of Aloha in December 2014; offset by
-
a decrease of $67 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; and
-
a decrease of $25 million in margins as 2014 benefited from favorable
regional market conditions for ethanol.
|
|
|
All Other
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2015
|
|
|
|
2014
|
|
Revenues
|
|
$
|
976
|
|
|
$
|
897
|
|
Cost of products sold
|
|
|
855
|
|
|
|
798
|
|
Gross margin
|
|
|
121
|
|
|
|
99
|
|
Unrealized (gains) losses on commodity risk management activities
|
|
|
(7
|
)
|
|
|
2
|
|
Operating expenses, excluding non-cash compensation expense
|
|
|
(26
|
)
|
|
|
(28
|
)
|
Selling, general and administrative expenses, excluding non-cash
compensation expense
|
|
|
(35
|
)
|
|
|
(47
|
)
|
Adjusted EBITDA related to unconsolidated affiliates
|
|
|
47
|
|
|
|
23
|
|
Other
|
|
|
18
|
|
|
|
18
|
|
Eliminations
|
|
|
(25
|
)
|
|
|
(7
|
)
|
Segment Adjusted EBITDA
|
|
$
|
93
|
|
|
$
|
60
|
|
|
|
|
|
|
Distributions from unconsolidated affiliates
|
|
$
|
14
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
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;
-
Regency’s 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 increased primarily due to an increase of
$24 million in Adjusted EBITDA related to unconsolidated affiliates. The
increase in Adjusted EBITDA related to unconsolidated affiliates was
primarily due to higher earnings driven by stronger refining crack
spreads from our investment in PES of $25 million.
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 September 30, 2015 were reflected as an offset to operating
expenses of $6 million and selling, general and administrative expenses
of $12 million in the consolidated statements of operations.
The increase in cash distributions from unconsolidated affiliates was
primarily due to an increase of $15 million in cash distribution 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) for the nine months
ended September 30, 2015:
|
|
|
|
|
|
|
|
|
|
Growth
|
|
Maintenance
|
|
Total
|
Direct(1):
|
|
|
|
|
|
|
Midstream
|
|
$
|
1,563
|
|
$
|
67
|
|
$
|
1,630
|
Liquids transportation and services(2)
|
|
|
1,618
|
|
|
13
|
|
|
1,631
|
Interstate transportation and storage(2)
|
|
|
586
|
|
|
81
|
|
|
667
|
Intrastate transportation and storage
|
|
|
54
|
|
|
19
|
|
|
73
|
Retail marketing(3)
|
|
|
179
|
|
|
45
|
|
|
224
|
All other (including eliminations)
|
|
|
290
|
|
|
27
|
|
|
317
|
Total direct capital expenditures
|
|
|
4,290
|
|
|
252
|
|
|
4,542
|
Indirect(1):
|
|
|
|
|
|
|
Investment in Sunoco Logistics
|
|
|
1,419
|
|
|
49
|
|
|
1,468
|
Investment in Sunoco LP(4)
|
|
|
83
|
|
|
7
|
|
|
90
|
Total indirect capital expenditures
|
|
|
1,502
|
|
|
56
|
|
|
1,558
|
Total capital expenditures
|
|
$
|
5,792
|
|
$
|
308
|
|
$
|
6,100
|
|
|
|
|
|
|
|
|
|
|
(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 (net of contributions in aid of
construction costs) for the full year 2015 to be within the following
ranges:
|
|
|
|
|
|
|
Growth
|
|
Maintenance
|
|
|
Low
|
|
High
|
|
Low
|
|
High
|
Direct(1):
|
|
|
|
|
|
|
|
|
Midstream
|
|
$
|
2,100
|
|
$
|
2,200
|
|
$
|
90
|
|
$
|
110
|
Liquids transportation and services:
|
|
|
|
|
|
|
|
|
NGL
|
|
|
1,550
|
|
|
1,600
|
|
|
20
|
|
|
25
|
Crude(2)
|
|
|
700
|
|
|
750
|
|
|
—
|
|
|
—
|
Interstate transportation and storage(2)
|
|
|
700
|
|
|
750
|
|
|
130
|
|
|
140
|
Intrastate transportation and storage
|
|
|
125
|
|
|
150
|
|
|
30
|
|
|
35
|
Retail marketing(3)
|
|
|
210
|
|
|
240
|
|
|
50
|
|
|
60
|
All other (including eliminations)
|
|
|
320
|
|
|
360
|
|
|
25
|
|
|
35
|
Total direct capital expenditures
|
|
|
5,705
|
|
|
6,050
|
|
|
345
|
|
|
405
|
Indirect(1):
|
|
|
|
|
|
|
|
|
Investment in Sunoco Logistics
|
|
|
2,400
|
|
|
2,600
|
|
|
65
|
|
|
75
|
Investment in Sunoco LP(4)
|
|
|
80
|
|
|
85
|
|
|
5
|
|
|
10
|
Total indirect capital expenditures
|
|
|
2,480
|
|
|
2,685
|
|
|
70
|
|
|
85
|
Total projected capital expenditures
|
|
$
|
8,185
|
|
$
|
8,735
|
|
$
|
415
|
|
$
|
490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
|
|
|
SUPPLEMENTAL INFORMATION ON
UNCONSOLIDATED AFFILIATES
|
(In millions)
|
(unaudited)
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
|
2015
|
|
|
|
2014
|
|
Equity in earnings (losses) of unconsolidated affiliates:
|
|
|
|
|
Citrus
|
|
$
|
29
|
|
|
$
|
32
|
|
FEP
|
|
|
14
|
|
|
|
14
|
|
PES
|
|
|
39
|
|
|
|
14
|
|
MEP
|
|
|
10
|
|
|
|
10
|
|
HPC
|
|
|
9
|
|
|
|
10
|
|
AmeriGas
|
|
|
(2
|
)
|
|
|
(3
|
)
|
Sunoco, LLC
|
|
|
(13
|
)
|
|
|
—
|
|
Sunoco LP
|
|
|
117
|
|
|
|
—
|
|
Other
|
|
|
11
|
|
|
|
7
|
|
Total equity in earnings of unconsolidated affiliates
|
|
$
|
214
|
|
|
$
|
84
|
|
|
|
|
|
|
Adjusted EBITDA related to unconsolidated affiliates:
|
|
|
|
|
Citrus
|
|
$
|
88
|
|
|
$
|
84
|
|
FEP
|
|
|
19
|
|
|
|
19
|
|
PES
|
|
|
46
|
|
|
|
21
|
|
MEP
|
|
|
23
|
|
|
|
24
|
|
HPC
|
|
|
16
|
|
|
|
16
|
|
Sunoco, LLC
|
|
|
53
|
|
|
|
—
|
|
Sunoco LP
|
|
|
81
|
|
|
|
—
|
|
Other
|
|
|
24
|
|
|
|
20
|
|
Total Adjusted EBITDA related to unconsolidated affiliates
|
|
$
|
350
|
|
|
$
|
184
|
|
|
|
|
|
|
Distributions received from unconsolidated affiliates:
|
|
|
|
|
Citrus
|
|
$
|
65
|
|
|
$
|
51
|
|
FEP
|
|
|
19
|
|
|
|
19
|
|
PES
|
|
|
15
|
|
|
|
—
|
|
MEP
|
|
|
20
|
|
|
|
18
|
|
HPC
|
|
|
14
|
|
|
|
14
|
|
Other
|
|
|
21
|
|
|
|
14
|
|
Total distributions received from unconsolidated affiliates
|
|
$
|
154
|
|
|
$
|
116
|
|
View source version on businesswire.com: http://www.businesswire.com/news/home/20151104006887/en/
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