Energy Transfer Partners Reports Second Quarter Results
On
In connection with the Regency Merger,
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
In
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 theBayou Bridge pipeline that will deliver crude oil from the Phillips 66 andSunoco Logistics terminals inNederland, Texas toLake Charles, Louisiana . Phillips 66 holds a 40% interest in the joint venture and ETP andSunoco Logistics each hold a 30% interest. -
In
July 2015 ,Sunoco LP acquired 100% ofSusser 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 millionSunoco LP common units, valued at approximately $967 million, to ETP. In addition, there will be an exchange for 11 millionSunoco LP units owned by Susser for another 11 million newSunoco 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 ofSunoco GP LLC , the general partner ofSunoco LP , and all of the IDRs ofSunoco 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 inAugust 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 fromAlcoa 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 onAugust 14th . The next milestone after that will be theFederal 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 bothRoyal Dutch Shell plc andBG 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 inJune 2015 of all of the outstanding $499 million aggregate principal amount of Regency’s 8.375% senior notes due 2019, (iii) the issuance inJune 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
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
The information contained in this press release is available on our web site at www.energytransfer.com.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES |
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CONDENSED CONSOLIDATED BALANCE SHEETS |
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(In millions) | |||||||
(unaudited) | |||||||
|
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June 30, 2015 |
December 31, 2014 |
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ASSETS |
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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 |
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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 |
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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS |
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(In millions, except per unit data) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Three Months Ended June 30, |
Six Months Ended June 30, |
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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 |
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(Tabular dollar amounts in millions) | ||||||||||||||||
(unaudited) | ||||||||||||||||
Three Months Ended June 30, |
Six Months Ended June 30, |
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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
(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 Ended June 30, |
Six Months Ended June 30, |
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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 Ended June 30, |
Six Months Ended June 30, |
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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 Ended June 30, |
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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 Ended June 30, |
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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
Segment Adjusted EBITDA for the midstream segment reflected a decrease in gross margin as follows:
Three Months Ended June 30, |
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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
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
Segment Adjusted EBITDA for the midstream segment also reflected lower selling, general and administrative expenses primarily due to a reduction in employee-related costs.
Liquids Transportation and Services
Three Months Ended June 30, |
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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
Average daily fractionated volumes increased due to the ramp-up of our
second 100,000 Bbls/d fractionator at
Segment Adjusted EBITDA for the liquids transportation and services segment reflected an increase in gross margin as follows:
Three Months Ended June 30, |
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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
Processing and fractionation margin increased $18 million due to the
ramp-up of Lone Star’s second fractionator at
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
Interstate Transportation and Storage
Three Months Ended June 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
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 Ended June 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
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
Investment in
Three Months Ended June 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
-
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 andNederland 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 Ended June 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 Ended June 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 untilAugust 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
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
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
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
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
SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES |
||||||||
(In millions) | ||||||||
(unaudited) | ||||||||
Three Months Ended June 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 | ||||
View source version on businesswire.com: http://www.businesswire.com/news/home/20150805006762/en/
Source:
Investor Relations:
Energy Transfer
Brent Ratliff,
214-981-0700 (office)
or
Energy Transfer
Lyndsay Hannah,
214-840-5477 (office)
or
Media Relations:
Granado
Communications Group
Vicki Granado, 214-599-8785 (office)
214-498-9272
(cell)