Energy Transfer Partners, L.P. (NYSE: ETP) today reported
its financial results for the quarter ended March 31, 2015.
Adjusted EBITDA for Energy Transfer Partners, L.P. (“ETP,” “we” or
the “Partnership”) for the three months ended March 31, 2015
totaled $1.15 billion, a decrease of $57 million compared
to the same period last year. Distributable Cash Flow attributable
to the partners of ETP, as adjusted, for the three months ended
March 31, 2015 totaled $692 million, a decrease of $52 million
compared to the same period last year. Income from continuing
operations for the three months ended March 31, 2015 was
$308 million, a decrease of $159 million compared to the
same period last year.
On a pro forma basis for the Regency Merger, as discussed below,
Adjusted EBITDA for ETP and Regency Energy Partners LP (“Regency”)
combined was $1.37 billion for the three months ended March
31, 2015. On a pro forma basis, Distributable Cash Flow
attributable to the partners of ETP, as adjusted, was $857 million
for the three months ended March 31, 2015.
On April 30, 2015, ETP and Regency completed the previously
announced merger of an indirect subsidiary of ETP, with and into
Regency, with Regency surviving the merger as a wholly-owned
subsidiary of ETP (the “Regency Merger”). As part of the merger
consideration, each Regency common unit and Class F unit was
converted into the right to receive 0.4124 ETP Common Units. Based
on the Regency units outstanding, ETP issued approximately
172.2 million ETP Common Units to Regency unitholders,
including approximately 15.5 million units issued to ETP
subsidiaries. The approximately 1.9 million outstanding
Regency series A preferred units were converted into corresponding
new ETP Series A Preferred Units. ETP and Regency are both
controlled by Energy Transfer Equity, L.P. (“ETE”); therefore, the
Regency Merger is a combination of entities under common control.
Beginning with the quarter ending June 30, 2015, ETP’s GAAP
financial statements will reflect retrospective consolidation of
Regency; however, such consolidation is not yet reflected in the
actual results presented herein. As such, ETP has included pro
forma amounts to reflect the combined results of ETP and
Regency.
In April 2015, ETP announced that its Board of Directors
approved an increase in its quarterly distribution to $1.015 per
ETP Common Unit ($4.06 annualized) for the quarter ended
March 31, 2015, representing an increase of $0.32 per ETP
Common Unit on an annualized basis, or 8.6%, compared to the first
quarter of 2014. On a stand-alone basis (pre-merger) for the
quarter ended March 31, 2015, ETP’s distribution coverage
ratio was 1.18x. For the quarter ended March 31, 2015, ETP’s
distribution coverage ratio would have been 1.04x on a pro forma
basis for the Regency Merger (excluding the impact of any
synergies).
ETP’s other recent key accomplishments include the
following:
- Material projects that commenced
operations in the quarter included: the Mariner South project, a
LPG export/import facility with Sunoco Logistics Partners L.P.
(“SXL”), which loaded its first propane cargo, and our Rebel
processing facility in the Permian Basin, which helped contribute
to overall volumes in our midstream segment.
- ETP, as a member of a consortium, was
awarded two pipeline projects for the transportation of natural gas
for Mexico's state power company, CFE, under long-term contracts.
The Trans-Pecos pipeline is an approximately 143-mile, 42-inch
pipeline to deliver at least 1.356 Bcf/d of natural gas from the
Waha Hub to the US/Mexico border near Presidio, Texas. The Comanche
Trail pipeline is an approximately 195-mile, 42-inch pipeline to
deliver at least 1.135 Bcf/d of natural gas from the Waha Hub to
the US/Mexico border near San Elizario, Texas. ETP will be the
construction manager and operator of both pipelines. The expected
all-in cost for these two pipelines is anticipated to be
approximately $1.3 billion and we expect both pipelines to be
in-service in the first quarter of 2017.
- In March 2015, ETE transfered
30.8 million ETP Common Units, ETE’s 45% interest in the
Bakken pipeline project, and $879 million in cash to the
Partnership in exchange for 30.8 million newly issued Class H
Units of ETP that, when combined with the 50.2 million
previously issued Class H Units, generally entitle ETE to receive
90.05% of the cash distributions and other economic attributes of
the general partner interest and IDRs of SXL (the “Bakken Pipeline
Transaction”). In connection with this transaction, ETP also issued
to ETE 100 Class I Units that provide distributions to ETE to
offset IDR subsidies previously provided to ETP. The IDR subsidies
from ETE to ETP, including the impact from distributions on Class I
Units, will be reduced by $55 million in 2015 and
$30 million in 2016.
- In addition, ETP and SXL have agreed to
transfer 30% of the Bakken pipeline to SXL.
- In April 2015, Sunoco LP completed the
acquisition of a 31.58% equity interest in Sunoco, LLC from ETP
Retail Holdings (“Retail Holdings”). Sunoco LLC distributes
approximately 5.3 billion gallons per year of motor fuel to
customers in the east, midwest and southwest regions of the United
States. The transaction was valued at approximately
$816 million. Sunoco LP paid $775 million in cash and
issued $41 million of Sunoco LP common units to Retail
Holdings.
- In March 2015, we closed on the
acquisition of the King Ranch project from Exxon Mobil Corporation,
for a total purchase price of $370 million. This acquisition
includes a 750 MMcf/d natural gas processing plant, a 42,000 Bbls/d
NGL fractionator, a NGL pipeline that delivers products to Corpus
Christi and the ETC King Ranch pipeline, which consists of 165
miles of mainline and gathering pipelines.
- Earlier this week, we announced that
our subsidiary, Lone Star NGL LLC (“Lone Star”), would construct a
fourth NGL fractionation facility at Mont Belvieu, Texas.
Fractionator IV, estimated to cost approximately $450 million,
is scheduled to be operational by December 2016. The 120,000 Bbls/d
fractionator is fully subscribed by multiple long-term contracts
and will provide off-take for the new 533-mile, 24- and 30-inch
Lone Star Express pipeline.
- Regarding our Lake Charles LNG project,
on April 10, 2015, the draft Environmental Impact
Statement for Lake Charles LNG and the expansion of the
Trunkline interstate pipeline was issued by the Federal Energy
Regulatory Commission (“FERC”). ETE/ETP and BG Group plc (“BG”)
were pleased with the findings and recommendations by FERC. It
moves the Lake Charles LNG project one step closer to our goal of
achieving a final investment decision (“FID”) in 2016.On April 7,
2015, BG and Royal Dutch Shell plc (“Shell”) announced a proposed
takeover of BG by Shell. We understand that the closing of the
BG/Shell merger is expected to occur in early 2016. In the interim,
BG and ETE/ETP remain focused on completing the development
milestones for the project as the parties move toward FID.
- In March 2015, ETP issued
$1.0 billion aggregate principal amount of 4.05% senior notes
due March 2025, $500 million aggregate principal amount of
4.90% senior notes due March 2035, and $1.0 billion aggregate
principal amount of 5.15% senior notes due March 2045. ETP used the
$2.48 billion net proceeds to pay outstanding borrowings under
the ETP Credit Facility, to fund growth capital expenditures and
for general partnership purposes.
- As of March 31, 2015, the ETP
Credit Facility had no outstanding borrowings and its credit ratio,
as defined by the credit agreement, was 4.05x. Pro forma for the
Regency Merger, borrowings under the ETP Credit Facility increased
to $1.5 billion and the pro forma credit ratio, as defined by
the credit agreement, was 4.62x.
- In the first quarter of 2015, ETP
issued approximately 1.2 million Common Units through its
at-the-market equity program, generating net proceeds of
approximately $76 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,
May 7, 2015 to discuss the first 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. and 100% of
Susser Holdings Corporation. Additionally, ETP owns the general
partner, 100% of the incentive distribution rights and
approximately 44% 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). 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), headquartered
in Philadelphia, 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 150 convenience stores and retail
fuel sites. 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)
Actual Pro Forma for Regency Merger(1) March 31,2015
December 31,2014 March 31,2015 December
31,2014
ASSETS
CURRENT ASSETS $ 6,206 $ 5,439 $ 6,776 $ 6,043
PROPERTY, PLANT AND EQUIPMENT, net 31,649 29,743 41,143 38,907
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES
3,723 3,840 3,667 3,760 GOODWILL 6,256 6,419 7,480 7,642 INTANGIBLE
ASSETS, net 2,093 2,087 5,499 5,526 OTHER NON-CURRENT ASSETS, net
702 693 802 796 Total assets $ 50,629 $
48,221 $ 65,367 $ 62,674
LIABILITIES AND
EQUITY
CURRENT LIABILITIES $ 4,707 $ 6,040 $ 5,258 $ 6,684
LONG-TERM DEBT, less current maturities 20,430 18,332 27,651 24,973
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES 214 138 228 154
DEFERRED INCOME TAXES 4,036 4,226 4,060 4,226 OTHER NON-CURRENT
LIABILITIES 1,256 1,206 1,306 1,278 COMMITMENTS AND
CONTINGENCIES SERIES A PREFERRED UNITS — — 33 33 REDEEMABLE
NONCONTROLLING INTERESTS 15 15 15 15 EQUITY: Total partners’
capital 12,966 12,070 12,966 12,070 Noncontrolling interest 7,005
6,194 5,943 5,152 Predecessor equity — — 7,907
8,089 Total equity 19,971 18,264 26,816
25,311 Total liabilities and equity $ 50,629 $ 48,221 $
65,367 $ 62,674 (1) The Regency Merger is a
combination of entities under common control. Beginning with the
quarter ending June 30, 2015, ETP’s GAAP financial statements will
reflect retrospective consolidation of Regency. The pro forma
amounts reflect the retrospective consolidation of Regency.
ENERGY TRANSFER
PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(unaudited)
Actual Pro Forma for Regency Merger(1) Three Months
EndedMarch 31, Three Months EndedMarch 31, 2015 2014
2015 2014 REVENUES $ 9,530 $ 12,232 $ 10,326 $ 13,027
COSTS AND EXPENSES: Cost of products sold 8,040 10,866 8,487 11,442
Operating expenses 485 336 619 414 Depreciation, depletion and
amortization 322 266 479 360 Selling, general and administrative
100 76 133 105
Total costs and expenses 8,947 11,544
9,718 12,321 OPERATING INCOME
583 688 608 706 OTHER INCOME (EXPENSE): Interest expense, net of
interest capitalized (228 ) (219 ) (310 ) (274 ) Equity in earnings
of unconsolidated affiliates 40 79 57 104 Gain on sale of AmeriGas
common units — 70 — 70 Losses on interest rate derivatives (77 ) (2
) (77 ) (2 ) Other, net 3 (3 ) 7
— INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX
EXPENSE 321 613 285 604 Income tax expense from continuing
operations 13 146 17
145 INCOME FROM CONTINUING OPERATIONS 308 467 268 459
Income from discontinued operations — 24
— 24 NET INCOME 308 491 268 483
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST 27 76 1 54
LESS: NET INCOME ATTRIBUTABLE TO PREDECESSOR —
— (14 ) 14 NET INCOME ATTRIBUTABLE TO
PARTNERS 281 415 281 415 General Partner’s interest in net income
242 113 242 192 Class H Unitholder’s interest in net income 54 49
54 49 Class I Unitholder’s interest in net income 33
— 33 — Common
Unitholders’ interest in net income (loss) $ (48 ) $ 253 $
(48 ) $ 174 INCOME (LOSS) FROM CONTINUING OPERATIONS PER
COMMON UNIT: Basic $ (0.17 ) $ 0.69 $ (0.09 ) $ 0.36
Diluted $ (0.17 ) $ 0.69 $ (0.09 ) $ 0.36 NET INCOME
(LOSS) PER COMMON UNIT: Basic $ (0.17 ) $ 0.76 $ (0.09 ) $
0.41 Diluted $ (0.17 ) $ 0.76 $ (0.09 ) $ 0.41
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING: Basic
323.8 324.5 495.8 420.3
Diluted 323.8 325.5 493.5
421.3
(1) See Footnote 1 of the condensed
consolidated balance sheets.
SUPPLEMENTAL
INFORMATION
(Tabular dollar amounts in millions)
(unaudited)
Actual Pro Forma (a) Three Months EndedMarch 31, Three
Months EndedMarch 31, 2015 2014 2015
2014
Reconciliation of net income to Adjusted EBITDA and
Distributable Cash Flow (b): Net income $ 308 $ 491 $ 268 $ 483
Interest expense, net of interest capitalized 228 219 310 274 Gain
on sale of AmeriGas common units — (70 ) — (70 ) Income tax expense
from continuing operations (c) 13 146 17 145 Depreciation,
depletion and amortization 322 266 479 360 Non-cash compensation
expense 16 14 20 17 Losses on interest rate derivatives 77 2 77 2
Unrealized losses on commodity risk management activities 66 29 77
32 Inventory valuation adjustments 34 (14 ) 34 (14 ) Equity in
earnings of unconsolidated affiliates (40 ) (79 ) (57 ) (104 )
Adjusted EBITDA related to unconsolidated affiliates 127 196 144
210 Other, net (2 ) 6 (4 ) 2
Adjusted EBITDA (consolidated) 1,149 1,206 1,365 1,337
Adjusted EBITDA related to unconsolidated affiliates (127 ) (196 )
(144 ) (210 ) Distributions from unconsolidated affiliates (d) 75
81 111 109 Interest expense, net of interest capitalized (228 )
(219 ) (310 ) (274 ) Amortization included in interest expense (13
) (16 ) (13 ) (14 ) Current income tax (expense) benefit from
continuing operations 9 (253 ) 9 (253 ) Transaction-related income
taxes (e) — 306 — 306 Maintenance capital expenditures (62 ) (39 )
(84 ) (64 ) Other, net 4 2 3
2 Distributable Cash Flow (consolidated) 807
872 937 939 Distributable Cash Flow attributable to SXL (100%) (160
) (157 ) (160 ) (157 ) Distributions from SXL to ETP 90 62 90 62
Distributable Cash Flow attributable to Sunoco LP (100%) (33 ) —
(33 ) — Distributions from Sunoco LP to ETP 12 — 12 — Distributions
to Regency in respect of Lone Star (f) (35 ) (33 )
— — Distributable Cash Flow
attributable to the partners of ETP 681 744 846 844 Bakken Pipeline
Transaction – pro forma interest expense (g) 6 — 6 —
Transaction-related expenses 5 —
5 — Distributable Cash Flow attributable to
the partners of ETP, as adjusted $ 692 $ 744 $ 857
$ 844
Distributions to the partners of ETP
(h): Limited Partners (i): Common Units held by public $ 330 $
266 $ 465 $ 390 Common Units held by ETE — 29 24 29 Class H Units
held by ETE and ETE Common Holdings, LLC (“ETE Holdings”) (j) 56 50
56 50 General Partner interests held by ETE 8 5 8 5 Incentive
Distribution Rights (“IDRs”) held by ETE 199 168 300 242 IDR
relinquishments net of Class I Unit distributions (7 )
(57 ) (27 ) (57 ) Total distributions to be
paid to the partners of ETP $ 586 $ 461 $ 826
$ 659 Distribution coverage ratio (k)
1.18
x
1.61
x
1.04
x
1.28
x
Distributable Cash Flow per Common Unit (l) $ 1.35 $
1.78 $ 1.05 $ 1.44
(a) Pro forma amounts reflect the combined results of ETP and
Regency assuming the Regency Merger closed January 1, 2014.
(b) 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. As of March 31, 2015, Lone Star was such a
subsidiary, as it was 30% owned by Regency, which was an
unconsolidated affiliate.
The Partnership has presented Distributable Cash Flow in
previous communications; however, the Partnership changed its
calculation of this non-GAAP measure in recent periods and has
revised amounts in prior periods to be consistent with the
Partnership’s updated calculation of this measure.
Previously, the Partnership’s calculation of Distributable Cash
Flow reflected income tax expense from continuing operations, which
included current and deferred income taxes. Current income tax
expense represents the estimated taxes that will be payable or
refundable for the current period, while deferred income taxes
represent the estimated tax effects of tax carryforwards and the
reversal of temporary differences between financial reporting
carrying amounts and the tax basis of existing assets and
liabilities. The Partnership revised its calculation of
Distributable Cash Flow to reflect current income tax expense from
continuing operations, rather than total income tax expense from
continuing operations. Management believes that this revised
calculation is more useful and more accurately reflects the cash
flows of the Partnership that are available for payment of
distributions. Distributable Cash Flow previously reported for the
three months ended March 31, 2014 has been revised to reflect
these changes.
For Distributable Cash Flow attributable to the partners of ETP,
certain transaction-related and non-recurring expenses that are
included in net income are excluded.
(c) Income tax expense is based on the earnings of our taxable
subsidiaries. For the three months ended March 31, 2015, the
Partnership’s income tax expense from continuing operations
included favorable state income tax adjustments of
$14 million. For the three months ended March 31, 2014,
the Partnership’s income tax expense from continuing operations
included unfavorable income tax adjustments of $85 million
related to the Lake Charles LNG Transaction, which was treated as a
sale for tax purposes.
(d) Distributions from unconsolidated affiliates for the pro
forma three months ended March 31, 2015 and 2014 include
$16 million and $15 million, respectively, of
distributions paid to a subsidiary of ETP related to Regency.
(e) Transaction-related income taxes primarily included income
tax expense related to the Lake Charles LNG Transaction. For the
three months ended March 31, 2014, amounts previously reported
for each of the interim periods have been adjusted to reflect
income taxes related to other transactions, which amounts had not
previously been reflected in the calculation of Distributable Cash
Flow for such interim periods.
(f) Cash distributions to Regency in respect of Lone Star
consist of cash distributions paid in arrears on a quarterly basis.
These amounts are in respect of the periods then ended, including
payments made in arrears subsequent to period end.
(g) Pro forma interest expense adjustment for $879 million
cash payment received from ETE related to the Bakken Pipeline
Transaction.
(h) Distributions on ETP Common Units, as reflected above,
exclude cash distributions on ETP Common Units held by subsidiaries
of ETP.
(i) For the three months ended March 31, 2015, the
distributions to the partners of ETP reflected in the “actual”
column exclude distributions related to the ETP Common Units that
were issued in the Regency Merger.
(j) Distributions on the Class H Units for the three months
ended March 31, 2015 and 2014 were calculated as follows:
Three Months EndedMarch 31, 2015 2014 General
partner distributions and incentive distributions from SXL $ 62 $
39 90.05 % 50.05 % Share of SXL general partner and
incentive distributions payable to Class H Unitholder 56 20
Incremental distributions payable to Class H Unitholder (IDR
subsidy offset)* — 30 Total Class H
Unit distributions $ 56 $ 50
* 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.
(k) 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.
(l) 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:
Actual Pro Forma Three Months
EndedMarch 31, Three Months EndedMarch 31, 2015 2014
2015 2014 Distributable Cash Flow attributable to the
partners of ETP, as adjusted $ 692 $ 744 $ 857 $ 844 Less: Class H
Units held by ETE and ETE Holdings (56 ) (50 ) (56 ) (50 ) General
Partner interests held by ETE (8 ) (5 ) (8 ) (5 ) IDRs held by ETE
(199 ) (168 ) (300 ) (242 ) IDR relinquishments net of Class I Unit
distributions 7 57 27
57 $ 436 $ 578 $ 520 $ 604
Weighted average Common Units outstanding – basic
323.8 324.5 495.8 420.3
Distributable Cash Flow per Common Unit $ 1.35 $ 1.78
$ 1.05 $ 1.44
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.
Pro forma amounts reflect the combined results of ETP and
Regency assuming the Regency Merger closed January 1, 2014.
Actual Pro Forma for Regency
Merger Three Months EndedMarch 31, Three Months EndedMarch 31, 2015
2014 2015 2014
Segment Adjusted
EBITDA: Midstream $ 153 $ 126 $ 318 $ 236 Liquids
transportation and services 166 128 166 128 Interstate
transportation and storage 277 300 302 324 Intrastate
transportation and storage 162 177 176 191 Investment in Sunoco
Logistics 221 208 221 208 Retail marketing 129 109 129 109 All
other 41 158 53 141 $ 1,149 $ 1,206 $
1,365 $ 1,337
Midstream
Actual Pro Forma for Regency
Merger Three Months EndedMarch 31, Three Months EndedMarch 31, 2015
2014 2015 2014 Gathered volumes
(MMBtu/d) 3,657,371 2,558,851 9,413,358 5,221,201 NGLs produced
(Bbls/d) 202,370 136,818 369,941 238,146 Equity NGLs (Bbls/d)
14,320 12,106 26,368 20,878 Revenues $ 531 $ 653 $ 1,406 $ 1,459
Cost of products sold 346 493
959 1,133 Gross margin 185 160 447 326
Unrealized losses on commodity risk
management activities
— — 11 3 Operating expenses, excluding non-cash compensation
expense (30 ) (28 ) (138 ) (88 ) Selling, general and
administrative expenses, excluding non-cash compensation expense (2
) (6 ) (3 ) (7 ) Adjusted EBITDA related to unconsolidated
affiliates — — 1 2
Segment Adjusted EBITDA $ 153 $ 126 $ 318
$ 236
Gathered volumes, NGLs produced and equity NGLs produced
increased primarily due to increased production by our customers in
the Eagle Ford Shale and the recent startup of the Rebel plant in
the Permian Basin.
Segment Adjusted EBITDA for the midstream segment reflected an
increase in gross margin as follows:
Actual Pro Forma for Regency Merger
Three Months EndedMarch 31, Three Months EndedMarch 31, 2015
2014 2015 2014 Gathering and processing
fee-based revenues $ 161 $ 123 $ 363 $ 219 Non fee-based contracts
and processing 24 37 84 107 Total gross
margin $ 185 $ 160 $ 447 $ 326
Midstream gross margin reflected an increase in fee-based
revenues of $38 million primarily due to increased capacity
from assets recently placed in service in the Eagle Ford Shale and
Permian Basin and a change in contract terms on our Southeast Texas
system where certain contracts were converted from non fee-based
terms to fee-based. Lower commodity prices resulted in a decrease
in non fee-based revenues of $24 million, which was partially
offset by a $9 million increase in equity volumes due to
production in the Eagle Ford Shale and Permian Basin.
Segment Adjusted EBITDA for the midstream segment also reflected
lower selling, general and administrative expenses primarily due to
a reduction in employee-related costs.
For the pro forma results, the increase in actual Segment
Adjusted EBITDA, as discussed above, was incrementally increased
due to Regency’s gathering and processing operations.
Liquids Transportation and Services
Three Months EndedMarch 31, 2015 2014
Liquids transportation volumes (Bbls/d) 438,646 307,511 NGL
fractionation volumes (Bbls/d) 226,041 156,898 Revenues $ 831 $ 830
Cost of products sold 637 671 Gross
margin 194 159 Unrealized losses on commodity risk management
activities 9 1 Operating expenses, excluding non-cash compensation
expense (35 ) (28 ) Selling, general and administrative expenses,
excluding non-cash compensation expense (4 ) (5 ) Adjusted EBITDA
related to unconsolidated affiliates 2 1
Segment Adjusted EBITDA $ 166 $ 128
NGL transportation volumes increased approximately 98,000 Bbls/d
on our wholly-owned and joint venture pipelines due to an increase
in NGL production from our Jackson processing plants and volumes
transported to our Mont Belvieu, Texas facilities via our Justice
pipeline. The remainder of the increase was from volumes
transported out of west Texas on our Lone Star pipeline system as
producers ramped up volumes. Average daily fractionated volumes
increased for the three months ended March 31, 2015 compared
to the same period last year 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 EndedMarch 31, 2015 2014
Transportation margin $ 81 $ 59 Processing and fractionation margin
65 49 Storage margin 44 40 Other margin 4 11 Total
gross margin $ 194 $ 159
Transportation margin increased $11 million due to higher
volumes transported out of west Texas and the Eagle Ford Shale on
our Lone Star pipeline system, $9 million due to increases in
NGL production from our processing plants that connect to various
fractionators via our wholly-owned pipelines, and $2 million
due to the recent commissioning of our wholly-owned crude
pipeline.
Processing and fractionation margin increased primarily due to
the ramp-up of Lone Star’s second fractionator at Mont Belvieu,
Texas, which was commissioned in October 2013.
Storage margin reflected increases of approximately
$6 million due to increased demand for leased storage capacity
as a result of market conditions and higher ancillary fees
associated with throughput volumes of $2 million. 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.
Other margin decreased primarily due to the impact of the cold
winter season in early 2014.
Segment Adjusted EBITDA for the liquids transportation and
services segment also reflected an increase in operating expenses
for the three months ended March 31, 2015 compared to the same
period last year primarily due to the ramp-up of Lone Star’s second
fractionator in Mont Belvieu, Texas, which was commissioned in
October 2013.
Interstate Transportation and Storage
Actual Pro Forma for Regency
Merger Three Months EndedMarch 31, Three Months EndedMarch 31, 2015
2014 2015 2014 Natural gas transported
(MMBtu/d) 6,763,691 6,956,089 6,763,691 6,956,089 Natural gas sold
(MMBtu/d) 16,656 15,783 16,656 15,783 Revenues $ 276 $ 298 $ 276 $
298 Operating expenses, excluding non-cash compensation,
amortization and accretion expenses (72 ) (71 ) (72 ) (71 )
Selling, general and administrative expenses, excluding non-cash
compensation, amortization and accretion expenses (15 ) (14 ) (15 )
(14 ) Adjusted EBITDA related to unconsolidated affiliates
88 87 113 111
Segment Adjusted EBITDA $ 277 $ 300 $ 302 $
324 Distributions from unconsolidated affiliates $ 49
$ 50 $ 69 $ 68
Transported volumes decreased primarily due to warmer weather in
2015 along the Panhandle pipeline, resulting in a decrease of
137,508 MMBtu/d, and declines in supply into the Sea Robin pipeline
as a result of a customer maintenance related outage, resulting in
a decrease of 78,260 MMBtu/d.
Segment Adjusted EBITDA for the interstate transportation and
storage segment decreased primarily due to lower transportation
loan-related revenues of approximately $23 million as a result
of higher basis differentials in 2014 driven by the colder
weather.
The pro forma results for adjusted EBITDA related to
unconsolidated affiliates and distributions from unconsolidated
affiliates reflect the impact of Regency’s investment in
Midcontinent Express Pipeline LLC (“MEP”).
Intrastate Transportation and Storage
Actual Pro Forma for Regency
Merger Three Months EndedMarch 31, Three Months EndedMarch 31, 2015
2014 2015 2014 Natural gas transported
(MMBtu/d) 8,809,018 9,399,267 8,809,018 9,399,267 Revenues $ 586 $
934 $ 586 $ 934 Cost of products sold 416 734
416 734 Gross margin 170 200 170
200 Unrealized losses on commodity risk management activities 35 27
35 27 Operating expenses, excluding non-cash compensation expense
(36 ) (42 ) (36 ) (42 ) Selling, general and administrative
expenses, excluding non-cash compensation expense (7 ) (7 ) (7 ) (7
) Adjusted EBITDA related to unconsolidated affiliates —
(1 ) 14 13 Segment
Adjusted EBITDA $ 162 $ 177 $ 176 $ 191
Distributions from unconsolidated affiliates $ 1 $ 1 $ 14 $
11
Transported volumes declined compared to the same period last
year primarily due to lower production from certain key shippers in
the Barnett Shale region.
Intrastate transportation and storage gross margin decreased
$17 million in margin from natural gas sales and other
primarily due to a decrease in gains from derivatives.
Additionally, retained fuel revenues decreased $15 million
primarily due to the impact of the cold weather season in early
2014 and storage margin decreased $9 million principally
driven by a decline in the spreads between the spot and forward
prices on natural gas inventory held in the Bammel storage
facility. These decreases were partially offset by an increase of
$11 million in transportation fees primarily due to increased
revenue from long-term fixed capacity fee contracts on our Houston
pipeline system resulting from the renegotiation of existing
contracts, as well as the initiation of new contracts.
The pro forma results for adjusted EBITDA related to
unconsolidated affiliates and distributions from unconsolidated
affiliates reflect the impact of Regency’s investment in RIGS
Haynesville Partnership Co. (“HPC”).
Investment in Sunoco Logistics
Three Months EndedMarch 31, 2015 2014 Revenues
$ 2,572 $ 4,477 Cost of products sold 2,350
4,210 Gross margin 222 267 Unrealized (gains) losses on
commodity risk management activities 15 (1 ) Operating expenses,
excluding non-cash compensation expense (48 ) (39 ) Selling,
general and administrative expenses, excluding non-cash
compensation expense (22 ) (27 ) Inventory valuation adjustments 41
— Adjusted EBITDA related to unconsolidated affiliates 13
8 Segment Adjusted EBITDA $ 221 $ 208
Distributions from unconsolidated affiliates $ 5 $ 2
Segment Adjusted EBITDA related to Sunoco Logistics increased
due to the net impacts of the following:
- an increase of $19 million from
crude oil acquisition and marketing activities, primarily due to an
increase of $17 million from higher realized crude margins and
an increase of $1 million from increased crude oil volumes
resulting from recent acquisitions and the expansion of the crude
oil trucking fleet;
- an increase of $26 million from
products pipelines, primarily due to an increase of
$12 million from higher throughput volumes and higher average
pipeline revenue per barrel of $10 million, which were largely
driven by contributions from Sunoco Logistics’ Mariner NGL pipeline
projects, and increased contributions from Sunoco Logistics’ joint
venture interests of $5 million; and
- an increase of $2 million from
crude oil pipelines, primarily due to higher throughput volumes of
$10 million largely driven by expansion projects placed into
service in Texas and Oklahoma during 2014, largely offset by lower
average pipeline revenue per barrel of $7 million, which was
impacted by reduced volumes on higher-priced tariff movements;
partially offset by
- a decrease of $34 million from
terminal facilities, primarily due to lower results from products
acquisition and marketing activities of $45 million. Sunoco
Logistics utilized its storage capabilities to increase its level
of certain refined products inventories in order to capture the
contango market structure. These inventory positions, combined with
the timing of butane blending sales, were negatively impacted by
inventory valuation adjustments. This decrease in operating results
was partially offset by higher contributions from Sunoco Logistics’
bulk marine and refined products terminals of
$10 million.
Retail Marketing
Three Months EndedMarch 31, 2015 2014 Retail
gasoline outlets, end of period: Total 6,683 5,122 Company-operated
1,258 529 Motor fuel sales: Total gallons (in millions) 1,881 1,392
Company-operated (gallons/month per site) 156,456 178,448 Motor
fuel gross profit (cents per gallon): Total 12.9 8.4
Company-operated 26.0 22.1 Merchandise sales $ 481 $ 140
Revenues $ 4,805 $ 5,011 Cost of products sold 4,367
4,756 Gross margin 438 255 Unrealized losses on
commodity risk management activities 2 3 Operating expenses,
excluding non-cash compensation expense (271 ) (126 ) Selling,
general and administrative expenses, excluding non-cash
compensation expense (34 ) (10 ) Inventory valuation adjustments (7
) (14 ) Adjusted EBITDA related to unconsolidated affiliates
1 1 Segment Adjusted EBITDA $ 129 $ 109
Retail marketing gross margin increased due to the net impacts
of the following:
- an increase of $184 million from
the acquisition of Susser in August 2014;
- favorable impact of $34 million
from other recent acquisitions;
- an increase of $33 million from
stronger retail and wholesale motor fuel margins;
- an increase of $4 million from
other retail margins; partially offset by
- a decrease of $45 million due to
exceptionally strong results in 2014 from ethanol manufacturing and
blending, largely related to weather related impacts and regional
market dynamics;
- unfavorable impact of $20 million
in non-retail fuel activities; and
- unfavorable impact of $7 million
related to non-cash inventory valuation adjustments.
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
Actual Pro Forma for Regency
Merger Three Months EndedMarch 31, Three Months EndedMarch 31, 2015
2014 2015 2014 Revenues $ 383 $ 591 $
493 $ 660 Cost of products sold 374 564
389 574 Gross margin 9 27 104 86
Unrealized (gains) losses on commodity risk management activities 5
(1 ) 5 (1 ) Operating expenses, excluding non-cash compensation
expense 5 (5 ) (21 ) (27 ) Selling, general and administrative
expenses, excluding non-cash compensation expense (18 ) (11 ) (46 )
(36 ) Adjusted EBITDA related to discontinued operations — 27 — 27
Adjusted EBITDA related to unconsolidated affiliates 25 102 3 75
Other 19 19 19 19 Elimination (4 ) —
(11 ) (2 ) Segment Adjusted EBITDA $ 41 $ 158
$ 53 $ 141 Distributions from unconsolidated
affiliates $ 18 $ 26 $ 18 $ 26
Amounts reflected in our all other segment primarily
include:
- our natural gas marketing and
compression operations;
- an approximate 33% non-operating
interest in PES, a refining joint venture;
- our investment in Regency common and
Class F units; and
- our investment in AmeriGas until August
2014.
Segment Adjusted EBITDA decreased due to the net impact of the
following:
- a decrease of $77 million in
Adjusted EBITDA related to unconsolidated affiliates, primarily due
to a decrease of $51 million related to our investment in
AmeriGas driven by a reduction in our investment due to the sale of
AmeriGas common units in 2014 and lower earnings from our
investment in PES of $21 million; and
- Adjusted EBITDA related to discontinued
operations of $27 million in the prior period related to a
marketing business that was sold effective April 1, 2014.
For the pro forma results, the decrease in actual Segment
Adjusted EBITDA, as discussed above, was partially offset by
increases in Regency’s natural resources and contract services
operations.
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 March 31, 2015
were reflected as an offset to operating expenses of
$6 million and selling, general and administrative expenses of
$13 million in the consolidated statements of operations.
The decrease in cash distributions from unconsolidated
affiliates was primarily due to a decrease of $11 million in
cash distribution from our ownership in AmeriGas as a result of
selling our interests in AmeriGas in 2014, partially offset by an
increase of $2 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 three months
ended March 31, 2015, excluding Regency’s capital expenditures:
Growth Maintenance Total Direct(1):
Midstream $ 248 $ 4 $ 252 Liquids transportation and services(2)
559 4 563 Interstate transportation and storage(2) 271 19 290
Intrastate transportation and storage 15 3 18 Retail marketing(3)
73 14 87 All other (including eliminations) 10 —
10 Total direct capital expenditures 1,176 44 1,220
Indirect(1): Investment in Sunoco Logistics 416 15 431 Investment
in Sunoco LP(3) 36 3 39 Total indirect capital
expenditures 452 18 470 Total capital
expenditures – actual 1,628 62 1,690 Regency
capital expenditures (excluding contributions to Lone Star)
438 22 460 Total capital expenditures – pro forma for
Regency Merger $ 2,066 $ 84 $ 2,150 (1) Indirect
capital expenditures comprise those funded by our publicly traded
subsidiaries; all other capital expenditures are reflected as
direct capital expenditures. (2) Includes 100% of Lone Star, Bakken
and Rover’s capital expenditures. (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, including Regency’s expected capital
expenditures:
Growth Maintenance Low
High Low High Direct(1): Midstream $ 1,900 $
2,000 $ 90 $ 110 Liquids transportation and services: NGL(2) 1,700
1,750 25 30 Crude(3) 700 750 — — Interstate transportation and
storage(3) 750 850 100 115 Intrastate transportation and storage
150 200 30 35 Retail marketing(4) 200 250 80 100 All other
(including eliminations) 200 250 35 45
Total direct capital expenditures 5,600 6,050 360 435 Indirect(1):
Investment in Sunoco Logistics 2,400 2,600 65 75 Investment in
Sunoco LP(4) 180 230 15 25 Total
indirect capital expenditures 2,580 2,830 80
100 Total projected capital expenditures $ 8,180 $ 8,880 $
440 $ 535 (1) Indirect capital expenditures comprise
those funded by our publicly traded subsidiaries; all other capital
expenditures are reflected as direct capital expenditures. (2)
Includes 100% of Lone Star’s capital expenditures. (3) Includes
capital expenditures related to our proportionate ownership of the
Bakken and Rover pipeline projects. (4) 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 EndedMarch 31, 2015 2014
Equity in earnings (losses) of unconsolidated affiliates:
Citrus $ 19 $ 18 FEP 14 14 Regency 4 (7 ) PES (9 ) 17 AmeriGas 6 34
Other 6 3 Total equity in earnings of
unconsolidated affiliates – actual $ 40 $ 79 MEP 12
11 HPC 9 7 Other and eliminations (4 ) 7 Total
equity in earnings of unconsolidated affiliates – pro forma for
Regency Merger $ 57 $ 104
Adjusted EBITDA
related to unconsolidated affiliates: Citrus $ 69 $ 68 FEP 19
19 Regency 23 27 PES 2 23 AmeriGas — 51 Other 14
8 Total Adjusted EBITDA related to unconsolidated
affiliates – actual $ 127 $ 196 MEP 24 26 HPC 15 14
Other and eliminations (22 ) (26 ) Total Adjusted
EBITDA related to unconsolidated affiliates – pro forma for Regency
Merger $ 144 $ 210
Distributions received
from unconsolidated affiliates: Citrus $ 33 $ 34 FEP 16 16
Regency 16 15 PES 2 — AmeriGas — 11 Other 8 5
Total distributions received from unconsolidated affiliates
– actual $ 75 $ 81 MEP 20 18 HPC 13 10 Other and
eliminations 3 — Total distributions
received from unconsolidated affiliates – pro forma for Regency
Merger $ 111 $ 109
Investor Relations:Energy TransferBrent Ratliff,
214-981-0700orLyndsay Hannah, 214-840-5477orMedia
Relations:Granado Communications GroupVicki Granado,
214-599-8785Cell: 214-498-9272
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