Energy Transfer Partners, L.P. (NYSE: ETP) (“ETP” or the
“Partnership”) today reported its financial results for the quarter
ended June 30, 2015. Adjusted EBITDA for ETP for the three
months ended June 30, 2015 totaled $1.49 billion, an increase
of $95 million compared to the same period last year.
Distributable Cash Flow attributable to the partners of ETP, as
adjusted, for the three months ended June 30, 2015 totaled $894
million, an increase of $149 million compared to the same
period last year. Income from continuing operations for the three
months ended June 30, 2015 was $839 million, an increase of
$334 million compared to the same period last year.
On April 30, 2015, a wholly-owned subsidiary of the Partnership
merged with Regency Energy Partners LP (“Regency”), with Regency
continuing as the surviving entity (the “Regency Merger”). Each
Regency common unit and Class F unit was converted into the right
to receive 0.4124 Partnership common units. ETP issued
172.2 million Partnership common units to Regency unitholders,
including 15.5 million units issued to Partnership
subsidiaries. The 1.9 million outstanding Regency series A
preferred units were converted into corresponding new Partnership
Series A Preferred Units on a one-for-one basis.
In connection with the Regency Merger, Energy Transfer Equity,
L.P. (“ETE”) will reduce the incentive distributions it receives
from the Partnership by a total of $320 million over a
five-year period. The IDR subsidy in connection with the Regency
Merger will be $80 million in the first year post-closing and
$60 million per year for the following four years.
The Regency Merger was a combination of entities under common
control; therefore Regency’s assets and liabilities were not
adjusted. The Partnership’s consolidated financial statements have
been retrospectively adjusted to reflect consolidation of Regency
for all prior periods subsequent to May 26, 2010 (the date ETE
acquired Regency’s general partner). Predecessor equity included on
the consolidated financial statements represents Regency’s equity
prior to the Regency Merger.
In July 2015, ETP announced an increase in its quarterly
distribution to $1.035 per Partnership common unit ($4.14
annualized) for the quarter ended June 30, 2015, representing
an increase of $0.32 per Partnership common unit on an annualized
basis, or 8.4%, compared to the second quarter of 2014. For the
quarter ended June 30, 2015, ETP’s distribution coverage ratio
was 1.03x, and its distributable cash flow per common unit was
$1.23.
ETP’s other recent key accomplishments include the
following:
- In July 2015, ETP, Sunoco Logistics
Partners L.P. (“Sunoco Logistics”) and Phillips 66 announced they
have formed a joint venture to construct the Bayou Bridge pipeline
that will deliver crude oil from the Phillips 66 and Sunoco
Logistics terminals in Nederland, Texas to Lake Charles, Louisiana.
Phillips 66 holds a 40% interest in the joint venture and ETP and
Sunoco Logistics each hold a 30% interest.
- In July 2015, Sunoco LP acquired 100%
of Susser Holdings Corporation (“Susser”) from ETP in a transaction
valued at $1.93 billion. Sunoco LP paid approximately
$997 million in cash (including payment for working capital)
and issued 22 million Sunoco LP common units, valued at
approximately $967 million, to ETP. In addition, there will be
an exchange for 11 million Sunoco LP units owned by Susser for
another 11 million new Sunoco LP units to a subsidiary of
ETP.
- In July 2015, ETE entered into an
exchange and repurchase agreement with ETP, pursuant to which ETE
would acquire 100% of the membership interests of Sunoco GP LLC,
the general partner of Sunoco LP, and all of the IDRs of Sunoco LP
from ETP, in exchange for the repurchase of 21 million ETP
common units owned by ETE. In connection with ETP’s 2014
acquisition of Susser, ETE agreed to provide ETP a $35 million
annual IDR subsidy for 10 years, which would terminate upon ETE’s
acquisition of Sunoco GP. In connection with the exchange and
repurchase, ETE agreed to provide ETP a $35 million annual IDR
subsidy for two years. Following this transaction, Sunoco LP will
no longer be consolidated for accounting purposes by ETP. This
transaction is expected to close in August 2015.
- During the second quarter 2015,
progress on Lake Charles LNG Export Company, LLC (“Lake Charles
LNG”), an entity owned 60% by ETE and 40% by ETP, continued as we
purchased the land for the project from Alcoa Inc. and as we
received the draft Environmental Impact Statement (“EIS”) and filed
the additional data and information requests required thereunder.
We have also continued our work with the short-listed EPC
contractors as we continue to refine the cost structure for the
project. We expect to receive the final EIS next week on August
14th. The next milestone after that will be the Federal Energy
Regulatory Commission (“FERC”) authorization. With the expected
emphasis on capital discipline and overall cost, we continue 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, we remain on track
to sanction FID of the project in 2016.
- Subsequent to the Regency Merger, ETP
has undertaken a series of liability management steps, including
(i) the repayment of $2.3 billion under Regency’s credit facility
and cancellation of the facility upon the closing of the Regency
Merger, (ii) the redemption in June 2015 of all of the outstanding
$499 million aggregate principal amount of Regency’s 8.375%
senior notes due 2019, (iii) the issuance in June 2015 of
$3.0 billion aggregate principal amount of ETP senior notes
with coupons ranging from 2.50% to 6.125% and maturities ranging
from 2018 to 2045, and (iv) the repayment of outstanding borrowings
under the ETP Credit Facility.
- As of June 30, 2015, the ETP
Credit Facility had no outstanding borrowings and its credit ratio,
as defined by the credit agreement, was 4.59x.
- In the second quarter of 2015, ETP
issued 8.9 million common units through its at-the-market
equity program, generating net proceeds of $493 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,
August 6, 2015 to discuss the second 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 62,000 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. ETP owns 100% of Sunoco, Inc. Additionally,
ETP owns the general partner, 100% of the incentive distribution
rights and approximately 66% 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 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 approximately 23.6 million ETP
Common Units and 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.
Sunoco LP (NYSE: SUN) is a growth-oriented master limited
partnership that primarily distributes motor fuel to convenience
stores, independent dealers, commercial customers and distributors.
Sunoco LP also operates more than 830 convenience stores and retail
fuel sites. Sunoco LP conducts its business through wholly-owned
subsidiaries, as well as through its 31.58% interest in Sunoco LLC,
in partnership with its parent company, ETP. Sunoco LP’s general
partner is owned by Energy Transfer Partners, L.P. (NYSE: ETP). For
more information, visit the Sunoco LP web site at www.sunocolp.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)
June 30,2015 December 31,2014
ASSETS
CURRENT ASSETS $ 7,259 $ 6,043 PROPERTY, PLANT AND
EQUIPMENT, net 42,857 38,907 ADVANCES TO AND INVESTMENTS IN
UNCONSOLIDATED AFFILIATES 3,667 3,760 NON-CURRENT DERIVATIVE ASSETS
1 10 OTHER NON-CURRENT ASSETS, net 801 786 INTANGIBLE ASSETS, net
5,526 5,526 GOODWILL 7,440 7,642 Total assets $ 67,551
$ 62,674
LIABILITIES AND
EQUITY
CURRENT LIABILITIES $ 5,161 $ 6,684 LONG-TERM DEBT,
less current maturities 29,058 24,973 NON-CURRENT DERIVATIVE
LIABILITIES 109 154 DEFERRED INCOME TAXES 4,104 4,246 OTHER
NON-CURRENT LIABILITIES 1,220 1,258 COMMITMENTS AND
CONTINGENCIES SERIES A PREFERRED UNITS 33 33 REDEEMABLE
NONCONTROLLING INTERESTS 15 15 EQUITY: Total partners’
capital 21,313 12,070 Noncontrolling interest 6,538 5,153
Predecessor equity — 8,088 Total equity 27,851 25,311
Total liabilities and equity $ 67,551 $ 62,674
ENERGY TRANSFER
PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data) (unaudited)
Three Months EndedJune 30, Six Months EndedJune 30, 2015
2014 2015 2014 REVENUES $ 11,540 $ 14,088 $ 21,866 $
27,115 COSTS AND EXPENSES Cost of products sold 9,338 12,352 17,825
23,794 Operating expenses 651 417 1,270 831 Depreciation, depletion
and amortization 501 436 980 796 Selling, general and
administrative 162 115 295 220 Total
costs and expenses 10,652 13,320 20,370 25,641
OPERATING INCOME 888 768 1,496 1,474 OTHER INCOME (EXPENSE)
Interest expense, net of interest capitalized (336 ) (295 ) (646 )
(569 ) Equity in earnings of unconsolidated affiliates 117 77 174
181 Gain on sale of AmeriGas common units — 93 — 163 Gains (losses)
on interest rate derivatives 127 (46 ) 50 (48 ) Other, net (16 )
(21 ) (9 ) (21 ) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME
TAX EXPENSE 780 576 1,065 1,180 Income tax expense (benefit) from
continuing operations (59 ) 71 (42 ) 216 INCOME FROM
CONTINUING OPERATIONS 839 505 1,107 964 Income from discontinued
operations — 42 — 66 NET INCOME 839 547
1,107 1,030 Less: Net income attributable to noncontrolling
interest 212 87 206 141 Less: Net income (loss) attributable to
predecessor (27 ) (11 ) (34 ) 3 NET INCOME ATTRIBUTABLE TO
PARTNERS 654 471 935 886 General Partner’s interest in net income
260 125 502 238 Class H Unitholder’s interest in net income 64 51
118 100 Class I Unitholder’s interest in net income 32 —
65 — Common Unitholders’ interest in net
income $ 298 $ 295 $ 250 $ 548 INCOME
FROM CONTINUING OPERATIONS PER COMMON UNIT: Basic $ 0.67 $
0.79 $ 0.63 $ 1.47 Diluted $ 0.67 $
0.79 $ 0.63 $ 1.47 NET INCOME PER COMMON UNIT:
Basic $ 0.67 $ 0.92 $ 0.63 $ 1.67
Diluted $ 0.67 $ 0.92 $ 0.63 $ 1.67
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING: Basic 434.8
318.5 379.6 321.4 Diluted 436.3
319.5 381.2 322.4
SUPPLEMENTAL
INFORMATION
(Tabular dollar amounts in millions) (unaudited)
Three Months EndedJune 30, Six Months EndedJune 30, 2015
2014 2015 2014
Reconciliation of net income to
Adjusted EBITDA and Distributable Cash Flow (a): Net income $
839 $ 547 $ 1,107 $ 1,030 Interest expense, net of interest
capitalized 336 295 646 569 Gain on sale of AmeriGas common units —
(93 ) — (163 ) Income tax expense (benefit) from continuing
operations (b) (59 ) 71 (42 ) 216 Depreciation, depletion and
amortization 501 436 980 796 Non-cash compensation expense 23 15 43
32 (Gains) losses on interest rate derivatives (127 ) 46 (50 ) 48
Unrealized losses on commodity risk management activities 42 1 119
33 Inventory valuation adjustments (184 ) (20 ) (150 ) (34 ) Equity
in earnings of unconsolidated affiliates (117 ) (77 ) (174 ) (181 )
Adjusted EBITDA related to unconsolidated affiliates 215 190 361
400 Other, net 19 (18 ) 14 (15 ) Adjusted EBITDA
(consolidated) 1,488 1,393 2,854 2,731 Adjusted EBITDA related to
unconsolidated affiliates (215 ) (190 ) (361 ) (400 ) Distributions
from unconsolidated affiliates (c) 125 123 236 232 Interest
expense, net of interest capitalized (336 ) (295 ) (646 ) (569 )
Amortization included in interest expense (8 ) (19 ) (21 ) (33 )
Current income tax (expense) benefit from continuing operations 112
(74 ) 121 (327 ) Transaction-related income taxes (d) — 41 — 347
Maintenance capital expenditures (100 ) (74 ) (184 ) (138 ) Other,
net 3 (1 ) 7 — Distributable Cash Flow
(consolidated) 1,069 904 2,006 1,843 Distributable Cash Flow
attributable to SXL (100%) (264 ) (222 ) (424 ) (379 )
Distributions from SXL to ETP 98 68 188 130 Distributable Cash Flow
attributable to Sunoco LP (100%) (35 ) — (68 ) — Distributions from
Sunoco LP to ETP 12 — 24 — Distributable cash flow attributable to
noncontrolling interest in Edwards Lime Gathering LLC (5 ) (5 ) (10
) (9 ) Distributable Cash Flow attributable to the partners of ETP
875 745 1,716 1,585 Transaction-related expenses 19 —
30 — Distributable Cash Flow attributable to the
partners of ETP, as adjusted $ 894 $ 745 $ 1,746
$ 1,585
Distributions to the partners of
ETP (e): Limited Partners: Common Units held by public $ 485 $
280 $ 950 $ 546 Common Units held by ETE 24 29 48 58 Class H Units
held by ETE and ETE Common Holdings, LLC (“ETE Holdings”) (f) 62 53
118 103 General Partner interests held by ETE 7 5 15 10 Incentive
Distribution Rights (“IDRs”) held by ETE 317 178 617 346 IDR
relinquishments net of Class I Unit distributions (28 ) (58 ) (55 )
(115 ) Total distributions to be paid to the partners of ETP $ 867
$ 487 $ 1,693 $ 948 Distribution
coverage ratio (g) 1.03x 1.53x 1.03x 1.67x Distributable
Cash Flow per Common Unit (h) $ 1.23 $ 1.78 $ 2.77
$ 3.86
(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.
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 six months ended June 30, 2015, the
Partnership’s income tax expense from continuing operations
decreased primarily due to a decrease in earnings among the
Partnership’s consolidated corporate subsidiaries, which resulted
in decreases in income tax expense of $75 million and
$135 million, respectively. The Partnership’s income tax
expense also decreased for the three and six months ended
June 30, 2015 by $12 million due to the exclusion of a
portion of the dividend income received by certain of our
consolidated corporate subsidiaries. For the three and six months
ended June 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. In addition, for the
six months ended June 30, 2015, the Partnership’s income tax
expense from continuing operations also decreased due to
unfavorable income tax adjustments of $87 million in the prior
period related to the Lake Charles LNG Transaction, which occurred
in the first quarter of 2014 and was treated as a sale for tax
purposes.
(c) Distributions from unconsolidated affiliates for the six
months ended June 30, 2015 include $16 million of
distributions paid to a subsidiary of ETP. Distributions from
unconsolidated affiliates for the three and six months ended
June 30, 2014 include $15 million and $30 million,
respectively, of distributions paid to a subsidiary of ETP.
(d) Transaction-related income taxes primarily included income
tax expense related to the Lake Charles LNG Transaction. For the
three and six months ended June 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) Distributions on ETP Common Units, as reflected above,
exclude cash distributions on Partnership common units held by
subsidiaries of ETP.
(f) Distributions on the Class H Units for the three and six
months ended June 30, 2015 and 2014 were calculated as
follows:
Three Months EndedJune 30, Six Months EndedJune 30,
2015 2014 2015 2014 General partner distributions and
incentive distributions from SXL $ 69 $ 43 $ 131 $ 82 90.05 % 50.05
% 90.05 % 50.05 % Share of SXL general partner and incentive
distributions payable to Class H Unitholder 62 21 118 41
Incremental distributions payable to Class H Unitholder (IDR
subsidy offset)* — 32 — 62 Total Class
H Unit distributions $ 62 $ 53 $ 118 $ 103
* 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.
(g) 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.
(h) 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 EndedJune 30, Six Months EndedJune 30,
2015 2014 2015 2014 Distributable Cash Flow
attributable to the partners of ETP, as adjusted $ 894 $ 745 $
1,746 $ 1,585 Less: Class H Units held by ETE and ETE Holdings (62
) (53 ) (118 ) (103 ) General Partner interests held by ETE (7 ) (5
) (15 ) (10 ) IDRs held by ETE (317 ) (178 ) (617 ) (346 ) IDR
relinquishments net of Class I Unit distributions 28 58
55 115 $ 536 $ 567 $ 1,051
$ 1,241 Weighted average Common Units outstanding –
basic 434.8 318.5 379.6 321.4
Distributable Cash Flow per Common Unit $ 1.23 $ 1.78
$ 2.77 $ 3.86
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 EndedJune 30, 2015 2014
Segment
Adjusted EBITDA: Midstream $ 376 $ 356 Liquids transportation
and services 151 141 Interstate transportation and storage 285 291
Intrastate transportation and storage 117 124 Investment in Sunoco
Logistics 326 280 Retail marketing 140 136 All other 93 65 $
1,488 $ 1,393
Midstream
Three Months EndedJune 30, 2015 2014 Gathered volumes
(MMBtu/d) 10,161,338 8,042,365 NGLs produced (Bbls/d) 399,662
292,880 Equity NGLs (Bbls/d) 30,160 26,761 Revenues $ 1,244 $ 1,798
Cost of products sold 797 1,339 Gross margin 447 459
Unrealized losses on commodity risk management activities 71 —
Operating expenses, excluding non-cash compensation expense (147 )
(101 ) Selling, general and administrative expenses, excluding
non-cash compensation expense (3 ) (6 ) Adjusted EBITDA related to
unconsolidated affiliates 7 4 Other 1 — Segment
Adjusted EBITDA $ 376 $ 356
Gathered volumes, NGLs produced and equity NGLs produced
increased primarily due to the Eagle Rock and King Ranch
acquisitions, 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 EndedJune 30, 2015 2014 Gathering and
processing fee-based revenues $ 384 $ 311 Non fee-based contracts
and processing 63 148 Total gross margin $ 447 $ 459
Midstream gross margin reflected an increase in fee-based
revenues of $48 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. Fee-based
revenues also increased $5 million due to a change in contract
terms on our Southeast Texas system where certain contracts were
converted from non fee-based terms to fee-based. Additionally, the
acquisition of Eagle Rock midstream assets in July 2014 also
increased fee-based margin by $21 million. Lower commodity
prices and changes in contract terms resulted in decreases of non
fee-based margins of $70 million and $9 million,
respectively. These decreases were partially offset by an increase
from the acquisition of Eagle Rock midstream assets of
$11 million.
Segment Adjusted EBITDA for the midstream segment reflected
higher operating expenses primarily due to additional expense from
assets recently placed in service and the acquisition of Eagle Rock
midstream assets in July 2014.
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 EndedJune 30, 2015 2014 Liquids
transportation volumes (Bbls/d) 482,351 367,564 NGL fractionation
volumes (Bbls/d) 253,987 191,255 Revenues $ 824 $ 903 Cost of
products sold 628 731 Gross margin 196 172 Unrealized
gains on commodity risk management activities (5 ) — Operating
expenses, excluding non-cash compensation expense (39 ) (29 )
Selling, general and administrative expenses, excluding non-cash
compensation expense (4 ) (4 ) Adjusted EBITDA related to
unconsolidated affiliates 3 2 Segment Adjusted EBITDA
$ 151 $ 141
NGL transportation volumes increased due to an increase in
volumes transported on our Lone Star Gateway pipeline system of
67,000 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
36,000 Bbls/d during the three months ended June 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 EndedJune 30, 2015 2014 Transportation
margin $ 91 $ 69 Processing and fractionation margin 76 57 Storage
margin 39 37 Other margin (10 ) 9 Total gross margin $ 196 $
172
Transportation margin increased $16 million due to higher
volumes transported out of west Texas on our Lone Star Gateway
pipeline system, as noted in the volume discussion above. In
addition, the increase in transportation margin also reflected an
increase in volumes transported from our processing plants in
southeast Texas and in the Eagle Ford region on our NGL pipeline
system to Mont Belvieu, Texas, which increased $3 million. The
commissioning of our crude transportation pipeline in south Texas
also contributed an additional $3 million to the increase.
Processing and fractionation margin increased $18 million
due to the ramp-up of Lone Star’s second fractionator at Mont
Belvieu, Texas, which was commissioned in October 2013.
Additionally, the commissioning of the Mariner South LPG export
project during February 2015 contributed an additional
$12 million for the three months ended June 30, 2015.
Storage margin reflected increases of approximately
$7 million due to increased demand for leased storage capacity
as a result of favorable market conditions. These increases in fee
based storage margin were offset by a decrease of $4 million
from lower non fee-based storage activities, including blending
activities of $1 million, and $3 million of lower
financial gains recognized on the withdrawal of inventory from our
storage facilities.
Other margin decreased primarily due to the accounting treatment
of NGL storage inventory and the timing of declines in the market
price of component NGL products, resulting in losses realized
during the three months ended June 30, 2015.
Segment Adjusted EBITDA for the liquids transportation and
services segment also reflected an increase in operating expenses
for the three months ended June 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 EndedJune 30, 2015 2014 Natural gas
transported (MMBtu/d) 5,873,424 5,745,746 Natural gas sold
(MMBtu/d) 14,827 15,733 Revenues $ 243 $ 249 Operating expenses,
excluding non-cash compensation, amortization and accretion
expenses (71 ) (67 ) Selling, general and administrative expenses,
excluding non-cash compensation, amortization and accretion
expenses (14 ) (16 ) Adjusted EBITDA related to unconsolidated
affiliates 127 125 Segment Adjusted EBITDA $ 285
$ 291 Distributions from unconsolidated
affiliates $ 83 $ 76
Transported volumes increased primarily due to favorable
throughput on the Tiger and Transwestern pipelines, resulting in
increases of 183,446 MMBtu/d and 115,648 MMBtu/d, respectively.
These increases were partially offset by a decrease of 96,255
MMBtu/d on the Trunkline Gas pipeline as a result of lower customer
demand due to lower price spreads.
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.
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 EndedJune 30, 2015 2014 Natural gas
transported (MMBtu/d) 8,666,363 9,069,215 Revenues $ 569 $ 712 Cost
of products sold 383 551 Gross margin 186 161
Unrealized gains on commodity risk management activities (34 ) (3 )
Operating expenses, excluding non-cash compensation expense (42 )
(43 ) Selling, general and administrative expenses, excluding
non-cash compensation expense (8 ) (5 ) Adjusted EBITDA related to
unconsolidated affiliates 15 14 Segment Adjusted
EBITDA $ 117 $ 124 Distributions from
unconsolidated affiliates $ 14 $ 12
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 the ramp up of volumes related
to significant new long-term transportation contracts.
Intrastate transportation and storage gross margin increased
$10 million from natural gas sales and other primarily due to
an increase in margin from the purchase and sale of natural gas on
our system and an increase of $13 million in transportation
fees 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
$13 million primarily due to an increase in the volume of
natural gas we own in the Bammel storage facility. These increases
were partially offset by a decrease of $11 million in retained
fuel revenues primarily due to significantly lower market
prices.
Investment in Sunoco Logistics
Three Months EndedJune 30, 2015 2014 Revenues $ 3,203
$ 4,821 Cost of products sold 2,721 4,517 Gross
margin 482 304 Unrealized losses on commodity risk management
activities 7 8 Operating expenses, excluding non-cash compensation
expense (53 ) (26 ) Selling, general and administrative expenses,
excluding non-cash compensation expense (23 ) (20 ) Inventory
valuation adjustments (100 ) — Adjusted EBITDA related to
unconsolidated affiliates 13 14 Segment Adjusted
EBITDA $ 326 $ 280 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 $43 million from
terminal facilities, primarily attributable to higher results from
Sunoco Logistics’ products acquisition and marketing activities,
which were positively impacted by inventory accounting resulting
from the liquidation of certain inventories that were stored during
the first quarter to capture the contango market structure.
Improved operating results from Sunoco Logistics’ Marcus Hook and
Nederland terminals also contributed to the increase. These
positive impacts were partially offset by lower results from Sunoco
Logistics’ refined products terminals; and
- an increase of $30 million from
products pipelines, primarily due to higher throughput volumes and
higher average pipeline revenue per barrel associated with Sunoco
Logistics’ Mariner NGL pipeline projects. These positive impacts
were partially offset by lower contributions from Sunoco Logistics’
joint venture interests; partially offset by
- a decrease of $15 million from
crude oil pipelines, primarily due to lower average pipeline
revenue per barrel primarily driven by reduced volumes on
higher-priced tariff movements. Increased operating expenses, which
included lower pipeline operating gains and higher line testing
costs, and selling, general and administrative expenses on growth
also contributed to the decrease. These impacts were partially
offset by additional throughput volumes largely attributable to
expansion projects placed into service in 2014; and
- a decrease of $12 million from
crude oil acquisition and marketing activities, primarily
attributable to lower realized crude oil margins, which were
negatively impacted by narrowing crude oil differentials compared
to the prior year period. This impact was partially offset by
increased crude oil volumes resulting from 2014 acquisitions and
the expansion of Sunoco Logistics’ crude oil trucking fleet.
Retail Marketing
Three Months EndedJune 30, 2015 2014 Motor fuel
outlets and convenience stores, end of period: Retail 1,276 568
Third-party wholesale 5,481 4,584 Total 6,757
5,152 Total motor fuel gallons sold (in millions): Retail
639 328 Third-party wholesale 1,285 1,129 Total 1,924
1,457 Motor fuel gross profit (cents/gallon): Retail
21.0 28.5 Third-party wholesale 8.1 10.1 Volume-weighted average
for all gallons 12.4 14.3 Merchandise sales (in millions) $ 559 $
175 Retail merchandise margin % 31.5 % 26.6 % Revenues $
5,537 $ 5,568 Cost of products sold 5,003 5,260 Gross
margin 534 308 Unrealized (gains) losses on commodity risk
management activities 1 (1 ) Operating expenses, excluding non-cash
compensation expense (281 ) (135 ) Selling, general and
administrative expenses, excluding non-cash compensation expense
(57 ) (17 ) Inventory valuation adjustments (57 ) (20 ) Adjusted
EBITDA related to unconsolidated affiliates — 1
Segment Adjusted EBITDA $ 140 $ 136
Retail marketing gross margin increased due to the net impacts
of the following:
- an increase of $199 million from
the acquisition of Susser in August 2014;
- favorable impact of $26 million
from other recent acquisitions;
- an increase of $36 million from
non-retail margins;
- an increase of $6 million from
other retail margins;
- favorable impact of $37 million
related to non-cash inventory valuation adjustments; partially
offset by
- unfavorable impact of $77 million
in fuel margins and volumes of $3 million.
Segment Adjusted EBITDA for the retail marketing segment also
reflected an increase in operating expenses and in selling, general
and administrative expenses primarily due to recent
acquisitions.
All Other
Three Months EndedJune 30, 2015 2014 Revenues $ 721 $
825 Cost of products sold 617 735 Gross margin 104 90
Unrealized (gains) losses on commodity risk management activities 2
(3 ) Operating expenses, excluding non-cash compensation expense
(22 ) (20 ) Selling, general and administrative expenses, excluding
non-cash compensation expense (47 ) (48 ) Adjusted EBITDA related
to unconsolidated affiliates 53 31 Other 19 19 Eliminations (16 )
(4 ) Segment Adjusted EBITDA $ 93 $ 65
Distributions from unconsolidated affiliates $ 19 $ 13
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 $22 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 $29 million, partially offset by a decrease of
$5 million related to our investment in AmeriGas driven by a
reduction in our investment due to the sale of AmeriGas common
units in 2014.
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 June 30, 2015
were reflected as an offset to operating expenses of
$7 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 $19 million in
cash distribution from our ownership in PES, partially offset by a
decrease of $11 million in cash distribution from our
ownership in AmeriGas as a result of selling our interests in
AmeriGas in 2014.
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 six months
ended June 30, 2015:
Growth Maintenance Total Direct(1): Midstream $ 1,014 $ 32 $
1,046 Liquids transportation and services(2) 1,117 8 1,125
Interstate transportation and storage(2) 586 47 633 Intrastate
transportation and storage 28 8 36 Retail marketing(3) 134 33 167
All other (including eliminations) 183 18 201 Total
direct capital expenditures 3,062 146 3,208 Indirect(1): Investment
in Sunoco Logistics 898 31 929 Investment in Sunoco LP(3) 83
7 90 Total indirect capital expenditures 981 38
1,019 Total capital expenditures $ 4,043 $ 184
$ 4,227
(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 the investment in Sunoco LP, as well as ETP’s wholly-owned
retail marketing operations. Capital expenditures by Sunoco LP are
reflected as indirect because Sunoco LP is a publicly traded
subsidiary.
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 $ 1,900 $ 2,000 $ 90 $ 110 Liquids
transportation and services: NGL 1,550 1,600 20 25 Crude(2) 800 850
— — Interstate transportation and storage(2) 700 750 130 140
Intrastate transportation and storage 130 180 30 35 Retail
marketing(3) 160 210 55 75 All other (including eliminations) 200
250 35 45 Total direct capital expenditures
5,440 5,840 360 430 Indirect(1): Investment in Sunoco Logistics
2,400 2,600 65 75 Investment in Sunoco LP(3) 220 270
40 50 Total indirect capital expenditures 2,620 2,870
105 125 Total projected capital expenditures $ 8,060
$ 8,710 $ 465 $ 555
(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 the investment in Sunoco LP, as well as ETP’s wholly-owned
retail marketing operations. Capital expenditures by Sunoco LP are
reflected as indirect because Sunoco LP is a publicly traded
subsidiary.
SUPPLEMENTAL
INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions) (unaudited) Three Months
EndedJune 30, 2015 2014
Equity in earnings (losses) of
unconsolidated affiliates: Citrus $ 29 $ 26 FEP 13 13 PES 47 18
MEP 11 11 HPC 6 8 AmeriGas (2 ) (8 ) Other 13 9 Total
equity in earnings of unconsolidated affiliates $ 117 $ 77
Adjusted EBITDA related to unconsolidated
affiliates: Citrus $ 85 $ 81 FEP 18 18 PES 54 25 MEP 24 26 HPC
15 14 AmeriGas — 5 Other 19 21 Total Adjusted EBITDA
related to unconsolidated affiliates $ 215 $ 190
Distributions received from unconsolidated
affiliates: Citrus $ 47 $ 41 FEP 16 16 PES 19 — MEP 20 18 HPC
14 11 AmeriGas — 11 Other 9 11 Total distributions
received from unconsolidated affiliates – actual $ 125 $ 108
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version on businesswire.com: http://www.businesswire.com/news/home/20150805006762/en/
Investor Relations:Energy TransferBrent Ratliff,
214-981-0700 (office)orEnergy TransferLyndsay Hannah, 214-840-5477
(office)orMedia Relations:Granado Communications GroupVicki
Granado, 214-599-8785 (office)214-498-9272 (cell)
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