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 EndedSeptember 30, Nine Months EndedSeptember
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 EndedSeptember 30, Nine Months EndedSeptember
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 EndedSeptember 30, Nine Months
EndedSeptember 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 EndedSeptember 30, Nine Months
EndedSeptember 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 EndedSeptember 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 EndedSeptember 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 EndedSeptember 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 EndedSeptember 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 EndedSeptember 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 EndedSeptember 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 EndedSeptember 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 EndedSeptember 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 EndedSeptember 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 EndedSeptember 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
EndedSeptember 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/
Investor Relations:Energy TransferBrent Ratliff,
214-981-0700orLyndsay Hannah, 214-840-5477orMedia
Relations:Granado Communications GroupVicki Granado,
214-599-8785214-498-9272 (cell)
Sunoco Logistics Partners L.P. (NYSE:ETP)
Historical Stock Chart
From Apr 2024 to May 2024
Sunoco Logistics Partners L.P. (NYSE:ETP)
Historical Stock Chart
From May 2023 to May 2024