We could not find any results for:
Make sure your spelling is correct or try broadening your search.
Share Name | Share Symbol | Market | Type |
---|---|---|---|
Sunoco LP | NYSE:SUN | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 55.24 | 0 | 09:01:23 |
Energy Transfer Partners, L.P. (NYSE: ETP) (“ETP” or the “Partnership”) today reported its financial results for the quarter ended September 30, 2015. Adjusted EBITDA for ETP for the three months ended September 30, 2015 totaled $1.50 billion, an increase of $49 million compared to the same period last year. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the three months ended September 30, 2015 totaled $740 million, a decrease of $130 million compared to the same period last year. Income from continuing operations for the three months ended September 30, 2015 was $393 million, a decrease of $121 million compared to the same period last year.
Distributable Cash Flow for the third quarter of 2015 was affected by a partial reversal from the second quarter 2015 tax benefit, with $79 million of current income tax expense for the third quarter of 2015. Distributable Cash Flow was also affected this quarter by a lower overall pricing environment for percent-of-proceeds volumes, continued shut-in volumes in the Northeast and unscheduled plant outages in the Permian Basin.
In October 2015, ETP announced an increase in its quarterly distribution to $1.055 per Partnership common unit ($4.22 annualized) for the quarter ended September 30, 2015, representing an increase of $0.32 per Partnership common unit on an annualized basis, or 8.2%, compared to the third quarter of 2014.
ETP’s other recent key accomplishments include the following:
An analysis of ETP’s segment results and other supplementary data is provided after the financial tables shown below. ETP has scheduled a conference call for 8:00 a.m. Central Time, Thursday, November 5, 2015 to discuss the third quarter 2015 results. The conference call will be broadcast live via an internet web cast, which can be accessed through www.energytransfer.com and will also be available for replay on ETP’s web site for a limited time.
Energy Transfer Partners, L.P. (NYSE: ETP) is a master limited partnership owning and operating one of the largest and most diversified portfolios of energy assets in the United States. ETP’s subsidiaries include Panhandle Eastern Pipe Line Company, LP (the successor of Southern Union Company) and Lone Star NGL LLC, which owns and operates natural gas liquids storage, fractionation and transportation assets. In total, ETP currently owns and operates more than 62,500 miles of natural gas and natural gas liquids pipelines. ETP also owns the general partner, 100% of the incentive distribution rights, and approximately 67.1 million common units in Sunoco Logistics Partners L.P. (NYSE: SXL), which operates a geographically diverse portfolio of crude oil and refined products pipelines, terminalling and crude oil acquisition and marketing assets. Additionally, ETP owns fuel distribution and retail marketing assets and approximately 50.8% of the limited partner interests in Sunoco LP (formerly Susser Petroleum Partners LP) (NYSE: SUN), a wholesale fuel distributor and convenience store operator. ETP’s general partner is owned by Energy Transfer Equity, L.P. (NYSE: ETE). For more information, visit the Energy Transfer Partners, L.P. web site at www.energytransfer.com.
Energy Transfer Equity, L.P. (NYSE: ETE) is a master limited partnership which owns the general partner and 100% of the incentive distribution rights (IDRs) of Energy Transfer Partners, L.P. (NYSE: ETP) and Sunoco LP (NYSE: SUN) and approximately 2.6 million ETP Common Units, approximately 81.0 million ETP Class H Units, which track 90% of the underlying economics of the general partner interest and the IDRs of Sunoco Logistics Partners L.P. (NYSE: SXL), and 100 ETP Class I Units. On a consolidated basis, ETE’s family of companies owns and operates approximately 71,000 miles of natural gas, natural gas liquids, refined products, and crude oil pipelines. For more information, visit the Energy Transfer Equity, L.P. web site at www.energytransfer.com.
Sunoco Logistics Partners L.P. (NYSE: SXL) is a master limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary crude oil, refined products, and natural gas liquids pipeline, terminalling and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, refined products, and natural gas liquids. Sunoco Logistics’ general partner is owned by Energy Transfer Partners, L.P. (NYSE: ETP). For more information, visit the Sunoco Logistics Partners, L.P. web site at www.sunocologistics.com.
Forward-Looking Statements
This press release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results are discussed in the Partnership’s Annual Reports on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. The Partnership undertakes no obligation to update or revise any forward-looking statement to reflect new information or events.
The information contained in this press release is available on our web site at www.energytransfer.com.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(unaudited)
September 30,2015 December 31,2014ASSETS
CURRENT ASSETS $ 5,325 $ 6,043 PROPERTY, PLANT AND EQUIPMENT, net 42,821 38,907 ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES 5,119 3,760 NON-CURRENT DERIVATIVE ASSETS 15 10 OTHER NON-CURRENT ASSETS, net 738 786 INTANGIBLE ASSETS, net 4,494 5,526 GOODWILL 5,633 7,642 Total assets $ 64,145 $ 62,674LIABILITIES AND EQUITY
CURRENT LIABILITIES $ 4,483 $ 6,684 LONG-TERM DEBT, less current maturities 27,449 24,973 NON-CURRENT DERIVATIVE LIABILITIES 189 154 DEFERRED INCOME TAXES 3,768 4,246 OTHER NON-CURRENT LIABILITIES 1,144 1,258 COMMITMENTS AND CONTINGENCIES SERIES A PREFERRED UNITS 33 33 REDEEMABLE NONCONTROLLING INTERESTS 15 15 EQUITY: Total partners’ capital 21,074 12,070 Noncontrolling interest 5,990 5,153 Predecessor equity — 8,088 Total equity 27,064 25,311 Total liabilities and equity $ 64,145 $ 62,674ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(unaudited)
Three Months EndedSeptember 30, Nine Months EndedSeptember 30, 2015 2014 2015 2014 REVENUES $ 6,601 $ 14,933 $ 28,467 $ 42,048 COSTS AND EXPENSES Cost of products sold 4,925 13,014 22,750 36,808 Operating expenses 535 547 1,805 1,378 Depreciation, depletion and amortization 471 410 1,451 1,206 Selling, general and administrative 94 152 389 372 Total costs and expenses 6,025 14,123 26,395 39,764 OPERATING INCOME 576 810 2,072 2,284 OTHER INCOME (EXPENSE) Interest expense, net of interest capitalized (333 ) (299 ) (979 ) (868 ) Equity in earnings of unconsolidated affiliates 214 84 388 265 Losses on extinguishments of debt (10 ) — (43 ) — Gain on sale of AmeriGas common units — 14 — 177 Losses on interest rate derivatives (64 ) (25 ) (14 ) (73 ) Other, net 32 (15 ) 56 (36 ) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE 415 569 1,480 1,749 Income tax expense (benefit) from continuing operations 22 55 (20 ) 271 INCOME FROM CONTINUING OPERATIONS 393 514 1,500 1,478 Income from discontinued operations — — — 66 NET INCOME 393 514 1,500 1,544 Less: Net income (loss) attributable to noncontrolling interest (24 ) 78 182 219 Less: Net income (loss) attributable to predecessor — 94 (34 ) 97 NET INCOME ATTRIBUTABLE TO PARTNERS 417 342 1,352 1,228 General Partner’s interest in net income 277 135 779 373 Class H Unitholder’s interest in net income 66 59 184 159 Class I Unitholder’s interest in net income 15 — 80 — Common Unitholders’ interest in net income $ 59 $ 148 $ 309 $ 696 INCOME FROM CONTINUING OPERATIONS PER COMMON UNIT: Basic $ 0.11 $ 0.44 $ 0.70 $ 1.91 Diluted $ 0.10 $ 0.44 $ 0.68 $ 1.90 NET INCOME PER COMMON UNIT: Basic $ 0.11 $ 0.44 $ 0.70 $ 2.11 Diluted $ 0.10 $ 0.44 $ 0.68 $ 2.10 WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING: Basic 485.0 331.4 415.1 324.8 Diluted 487.3 333.1 417.7 326.5SUPPLEMENTAL INFORMATION
(Dollars and units in millions, except per unit amounts)
(unaudited)
Three Months EndedSeptember 30, Nine Months EndedSeptember 30, 2015 2014 2015 2014 Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (a): Net income $ 393 $ 514 $ 1,500 $ 1,544 Interest expense, net of interest capitalized 333 299 979 868 Gain on sale of AmeriGas common units — (14 ) — (177 ) Income tax expense (benefit) from continuing operations (b) 22 55 (20 ) 271 Depreciation, depletion and amortization 471 410 1,451 1,206 Non-cash compensation expense 16 18 59 50 Losses on interest rate derivatives 64 25 14 73 Unrealized (gains) losses on commodity risk management activities (47 ) (32 ) 72 1 Inventory valuation adjustments 134 51 (16 ) 17 Losses on extinguishments of debt 10 — 43 — Equity in earnings of unconsolidated affiliates (214 ) (84 ) (388 ) (265 ) Adjusted EBITDA related to unconsolidated affiliates 350 184 711 584 Other, net (32 ) 25 (51 ) 10 Adjusted EBITDA (consolidated) 1,500 1,451 4,354 4,182 Adjusted EBITDA related to unconsolidated affiliates (350 ) (184 ) (711 ) (584 ) Distributable cash flow from unconsolidated affiliates (c) 232 131 468 363 Interest expense, net of interest capitalized (333 ) (299 ) (979 ) (868 ) Amortization included in interest expense (9 ) (15 ) (30 ) (48 ) Current income tax (expense) benefit from continuing operations (79 ) (10 ) 42 (337 ) Transaction-related income taxes (d) — 34 — 381 Maintenance capital expenditures (124 ) (122 ) (308 ) (260 ) Other, net 4 5 11 5 Distributable Cash Flow (consolidated) 841 991 2,847 2,834 Distributable Cash Flow attributable to SXL (100%) (210 ) (194 ) (634 ) (573 ) Distributions from SXL to ETP 107 74 295 204 Distributable Cash Flow attributable to Sunoco LP (100%) (e) — (4 ) (68 ) (4 ) Distributions from Sunoco LP to ETP (e) — 8 24 8 Distributable cash flow attributable to noncontrolling interest in Edwards Lime Gathering LLC (5 ) (5 ) (15 ) (14 ) Distributable Cash Flow attributable to the partners of ETP 733 870 2,449 2,455 Transaction-related expenses 7 — 37 — Distributable Cash Flow attributable to the partners of ETP, as adjusted $ 740 $ 870 $ 2,486 $ 2,455 Distributions to the partners of ETP (f): Limited Partners: Common Units held by public $ 508 $ 312 $ 1,458 $ 858 Common Units held by ETE 3 30 51 88 Class H Units held by ETE (g) 68 56 186 159 General Partner interests held by ETE 8 6 23 16 Incentive Distribution Rights (“IDRs”) held by ETE 320 200 937 546 IDR relinquishments net of Class I Unit distributions (28 ) (67 ) (83 ) (182 ) Total distributions to be paid to the partners of ETP $ 879 $ 537 $ 2,572 $ 1,485 Common Units outstanding – end of period 495.6 351.0 495.6 351.0 Distribution coverage ratio (h) 0.84x 1.62x 0.97x 1.65x Distributable Cash Flow per Common Unit (i) $ 0.77 $ 2.04 $ 3.43 $ 5.90(a) Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures used by industry analysts, investors, lenders, and rating agencies to assess the financial performance and the operating results of ETP’s fundamental business activities and should not be considered in isolation or as a substitute for net income, income from operations, cash flows from operating activities, or other GAAP measures.
There are material limitations to using measures such as Adjusted EBITDA and Distributable Cash Flow, including the difficulty associated with using either as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA and Distributable Cash Flow may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP, such as gross margin, operating income, net income, and cash flow from operating activities.
Definition of Adjusted EBITDA
ETP defines Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on ETP’s proportionate ownership.
Adjusted EBITDA is used by management to determine our operating performance and, along with other financial and volumetric data, as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.
Definition of Distributable Cash Flow
ETP defines Distributable Cash Flow as net income, adjusted for certain non-cash items, less maintenance capital expenditures. Non-cash items include depreciation and amortization, non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities and deferred income taxes. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Distributable Cash Flow reflects earnings from unconsolidated affiliates on a cash basis, including (i) for unconsolidated affiliates with publicly traded equity interests, distributions paid or expected to be paid for the periods presented and (ii) for unconsolidated affiliates that are under common control of ETP’s parent, ETP’s proportionate share of the distributable cash flow of the investee.
Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.
On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ETP’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among ETP’s subsidiaries, the Distributable Cash Flow generated by ETP’s subsidiaries may not be available to be distributed to the partners of ETP. In order to reflect the cash flows available for distributions to the partners of ETP, ETP has reported Distributable Cash Flow attributable to the partners of ETP, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:
For Distributable Cash Flow attributable to the partners of ETP, as adjusted, certain transaction-related and non-recurring expenses that are included in net income are excluded.
(b) For the three and nine months ended September 30, 2015, the Partnership’s effective income tax rate decreased from the prior year primarily due to lower earnings among the Partnership’s consolidated corporate subsidiaries. The three and nine months ended September 30, 2015 also reflect a benefit of $24 million of net state tax benefit attributable to statutory state rate changes resulting from the Regency Merger and sale of Susser to Sunoco LP. For the three and nine months ended September 30, 2015, the Partnership’s income tax expense was favorably impacted by $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015. Additionally, the Partnership recognized a net tax benefit of $7 million related to the settlement of the Southern Union 2004-2009 Internal Revenue Service (“IRS”) examination in July 2015. For the three and nine months ended September 30, 2014, the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $87 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes.
(c) For the three and nine months ended September 30, 2015, distributions from unconsolidated affiliates includes distributions to be paid by Sunoco LP with respect to the third quarter of 2015, as well as the Partnership’s share of the distributable cash flow of Sunoco LLC for the third quarter of 2015.
(d) Transaction-related income taxes primarily included income tax expense related to the Lake Charles LNG Transaction. For the three and nine months ended September 30, 2014, amounts previously reported for each of the interim periods have been adjusted to reflect income taxes related to other transactions, which amounts had not previously been reflected in the calculation of Distributable Cash Flow for such interim periods.
(e) Amounts related to Sunoco LP reflect the periods through June 30, 2015, subsequent to which Sunoco LP was deconsolidated and is now reflected as an equity method investment.
(f) Distributions on ETP Common Units, as reflected above, exclude cash distributions on Partnership common units held by subsidiaries of ETP.
(g) Distributions on the Class H Units for the three and nine months ended September 30, 2015 and 2014 were calculated as follows:
Three Months EndedSeptember 30, Nine Months EndedSeptember 30, 2015 2014 2015 2014 General partner distributions and incentive distributions from SXL $ 76 $ 49 $ 207 $ 131 90.05 % 50.05 % 90.05 % 50.05 % Share of SXL general partner and incentive distributions payable to Class H Unitholder 68 25 186 66 Incremental distributions payable to Class H Unitholder (IDR subsidy offset)* — 31 — 93 Total Class H Unit distributions $ 68 $ 56 $ 186 $ 159* Incremental distributions previously paid to the Class H Unitholder were eliminated in Amendment No. 9 to ETP’s Amended and Restated Agreement of Limited Partnership effective in the first quarter of 2015.
(h) Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to the partners of ETP, as adjusted, divided by net distributions expected to be paid to the partners of ETP in respect of such period.
(i) The Partnership defines Distributable Cash Flow per Common Unit for a period as the quotient of Distributable Cash Flow attributable to the partners of ETP, as adjusted, net of distributions related to the Class H Units, Class I Units and the General Partner and IDR interests, divided by the weighted average number of Common Units outstanding.
Similar to Distributable Cash Flow as described above, Distributable Cash Flow per Common Unit is a significant liquidity measure used by the Partnership’s senior management to compare net cash flows generated by the Partnership to the distributions the Partnership expects to pay to its unitholders. Using this measure, the Partnership’s management can compare Distributable Cash Flow attributable to the partners of ETP, as adjusted, among different periods on a per-unit basis.
Distributable Cash Flow per Common Unit is calculated as follows:
Three Months EndedSeptember 30, Nine Months EndedSeptember 30, 2015 2014 2015 2014 Distributable Cash Flow attributable to the partners of ETP, as adjusted $ 740 $ 870 $ 2,486 $ 2,455 Less: Class H Units held by ETE (68 ) (56 ) (186 ) (159 ) General Partner interests held by ETE (8 ) (6 ) (23 ) (16 ) IDRs held by ETE (320 ) (200 ) (937 ) (546 ) IDR relinquishments net of Class I Unit distributions 28 67 83 182 $ 372 $ 675 $ 1,423 $ 1,916 Weighted average Common Units outstanding – basic 485.0 331.4 415.1 324.8 Distributable Cash Flow per Common Unit $ 0.77 $ 2.04 $ 3.43 $ 5.90SUMMARY 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:
Midstream
Three Months EndedSeptember 30, 2015 2014 Gathered volumes (MMBtu/d) 10,384,788 9,150,060 NGLs produced (Bbls/d) 413,426 364,302 Equity NGLs (Bbls/d) 26,296 30,703 Revenues $ 1,383 $ 1,967 Cost of products sold 916 1,428 Gross margin 467 539 Unrealized gains on commodity risk management activities — (16 ) Operating expenses, excluding non-cash compensation expense (148 ) (136 ) Selling, general and administrative expenses, excluding non-cash compensation expense (9 ) (12 ) Adjusted EBITDA related to unconsolidated affiliates 6 4 Other 2 — Segment Adjusted EBITDA $ 318 $ 379Gathered volumes and NGLs produced increased primarily due to the King Ranch acquisition, as well as increased gathering and processing capacities in the Eagle Ford Shale, Permian Basin and Cotton Valley regions.
Segment Adjusted EBITDA for the midstream segment reflected a decrease in gross margin as follows:
Three Months EndedSeptember 30, 2015 2014 Gathering and processing fee-based revenues $ 400 $ 352 Non fee-based contracts and processing 67 187 Total gross margin $ 467 $ 539Midstream gross margin reflected an increase in fee-based revenues of $46 million primarily due to increased production and increased capacity from assets recently placed in service in the Eagle Ford Shale, Permian Basin and Cotton Valley. Midstream gross margin reflected a decrease in non fee-based revenues due to lower commodity prices. The decrease between periods also reflected the impact from $16 million of gains on commodity risk management activities recorded in the prior period.
Segment Adjusted EBITDA for the midstream segment reflected higher operating expenses primarily due to additional expense from assets recently placed in service, including the Rebel system in west Texas and the King Ranch system in south Texas.
Segment Adjusted EBITDA for the midstream segment also reflected lower selling, general and administrative expenses primarily due to a reduction in employee-related costs.
Liquids Transportation and Services
Three Months EndedSeptember 30, 2015 2014 Liquids transportation volumes (Bbls/d) 442,683 352,990 NGL fractionation volumes (Bbls/d) 236,874 226,847 Revenues $ 854 $ 1,196 Cost of products sold 614 994 Gross margin 240 202 Unrealized gains on commodity risk management activities (4 ) (2 ) Operating expenses, excluding non-cash compensation expense (40 ) (33 ) Selling, general and administrative expenses, excluding non-cash compensation expense (4 ) (6 ) Adjusted EBITDA related to unconsolidated affiliates — 2 Segment Adjusted EBITDA $ 192 $ 163NGL transportation volumes increased due to an increase in volumes transported on our Lone Star Gateway pipeline system of 63,000 Bbls/d. These increased volumes were primarily out of west Texas as producers ramped up volumes. Additionally, we commissioned a crude transportation pipeline at the end of 2014 that transported 37,000 Bbls/d during the three months ended September 30, 2015. The remainder of the increase related to volumes on our NGL pipelines from our plants in southeast Texas and in the Eagle Ford region.
Average daily fractionated volumes increased due to the ramp-up of our second 100,000 Bbls/d fractionator at Mont Belvieu, Texas, which was commissioned in October 2013. These volumes include all physical and contractual volumes where we collected a fractionation fee.
Segment Adjusted EBITDA for the liquids transportation and services segment reflected an increase in gross margin as follows:
Three Months EndedSeptember 30, 2015 2014 Transportation margin $ 105 $ 84 Processing and fractionation margin 77 75 Storage margin 41 36 Other margin 17 7 Total gross margin $ 240 $ 202Transportation margin increased $22 million primarily due to higher volumes transported out of west Texas on our Lone Star Gateway pipeline system, as noted in the volume discussion above. The commissioning of our crude transportation pipeline in south Texas also contributed an additional $2 million to the increase.
Processing and fractionation margin increased $16 million due to the commissioning of the Mariner South LPG export project during February 2015 and was partially offset by decreases in processing and fractionation margin of $8 million and $6 million due to lower prices at our Lone Star fractionators and our off-gas fractionator as Geismar, Louisiana, respectively.
Storage margin reflected increases of approximately $6 million due to increased demand for leased storage capacity as a result of favorable market conditions. These increases in fee based storage margin were partially offset by a decrease of $2 million from lower non fee-based storage activities, including blending activities, and lower financial gains recognized on the withdrawal of inventory from our storage facilities.
Other margin decreased primarily due to the withdrawal and sale of physical storage volumes, primarily propanes and butanes.
Segment Adjusted EBITDA for the liquids transportation and services segment also reflected an increase in operating expenses for the three months ended September 30, 2015 compared to the same period last year primarily due to the commissioning of the Mariner South LPG export project during February 2015 and the ramp-up of Lone Star’s second fractionator at Mont Belvieu, Texas, which was commissioned in October 2013.
Interstate Transportation and Storage
Three Months EndedSeptember 30, 2015 2014 Natural gas transported (MMBtu/d) 5,903,285 5,785,862 Natural gas sold (MMBtu/d) 19,171 18,697 Revenues $ 248 $ 258 Operating expenses, excluding non-cash compensation, amortization and accretion expenses (78 ) (81 ) Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (14 ) (16 ) Adjusted EBITDA related to unconsolidated affiliates 130 127 Segment Adjusted EBITDA $ 286 $ 288 Distributions from unconsolidated affiliates $ 104 $ 87Transported volumes increased 111,582 MMBtu/d on the Tiger pipeline, primarily due to increased deliveries to pipelines supporting the upper Midwest due to favorable market conditions and 77,639 MMBtu/d on the Transwestern pipeline due to increased customer demand in the Texas intrastate market. These increases were partially offset by a decrease of 73,900 MMBtu/d on the Trunkline pipeline as a result of lower customer demand due to lower price spreads and a managed contract roll off to facilitate the transfer of one of the pipelines at Trunkline that was taken out of service in advance of being repurposed from natural gas service to crude oil service.
Segment Adjusted EBITDA for the interstate transportation and storage segment decreased primarily due to the expiration of a transportation rate schedule on the Transwestern pipeline and a managed contract roll off to facilitate the transfer of one of the 30” pipelines at Trunkline that was taken out of service in advance of being repurposed from natural gas to crude oil service.
The increase in cash distributions from unconsolidated affiliates reflected an increase in cash distributions from Citrus due to an increase in revenues from the sale of additional Phase VIII capacity.
Intrastate Transportation and Storage
Three Months EndedSeptember 30, 2015 2014 Natural gas transported (MMBtu/d) 8,308,105 8,799,708 Revenues $ 592 $ 601 Cost of products sold 428 438 Gross margin 164 163 Unrealized (gains) losses on commodity risk management activities (4 ) 1 Operating expenses, excluding non-cash compensation expense (43 ) (46 ) Selling, general and administrative expenses, excluding non-cash compensation expense (6 ) (9 ) Adjusted EBITDA related to unconsolidated affiliates 16 15 Segment Adjusted EBITDA $ 127 $ 124 Distributions from unconsolidated affiliates $ 14 $ 15Transported volumes declined compared to the same period last year primarily due to lower production from certain key shippers in the Barnett Shale region, offset by increased volumes related to significant new long-term transportation contracts.
Intrastate transportation and storage gross margin increased $7 million, despite a reduction in volume, primarily due to increased revenue from renegotiated and newly initiated long-term fixed capacity fee contracts on our Houston pipeline system. Additionally, storage margin increased $2 million primarily due to the timing of the movement of market prices during the period. These increases were partially offset by a decrease of $6 million in retained fuel revenues primarily due to significantly lower market prices and $2 million from natural gas sales and other primarily due to a decrease in margin from the purchase and sale of natural gas on our system.
Investment in Sunoco Logistics
Three Months EndedSeptember 30, 2015 2014 Revenues $ 2,406 $ 4,915 Cost of products sold 2,127 4,581 Gross margin 279 334 Unrealized gains on commodity risk management activities (31 ) (21 ) Operating expenses, excluding non-cash compensation expense (57 ) (55 ) Selling, general and administrative expenses, excluding non-cash compensation expense (23 ) (26 ) Inventory valuation adjustments 103 — Adjusted EBITDA related to unconsolidated affiliates 18 14 Segment Adjusted EBITDA $ 289 $ 246 Distributions from unconsolidated affiliates $ 5 $ 4Segment Adjusted EBITDA related to Sunoco Logistics increased due to the net impacts of the following:
Retail Marketing
Three Months EndedSeptember 30, 2015 2014 Motor fuel outlets and convenience stores, end of period: Retail 438 1,210 Third-party wholesale — 5,287 Total 438 6,497 Total motor fuel gallons sold (in millions): Retail 390 424 Third-party wholesale 10 1,198 Total 400 1,622 Motor fuel gross profit (cents/gallon): Retail 28.5 30.8 Third-party wholesale 15.1 9.0 Volume-weighted average for all gallons 28.2 14.7 Merchandise sales (in millions) $ 285 $ 287 Retail merchandise margin % 30.2 % 28.8 % Revenues $ 1,363 $ 5,988 Cost of products sold 1,149 5,645 Gross margin 214 343 Unrealized (gains) losses on commodity risk management activities (1 ) 4 Operating expenses, excluding non-cash compensation expense (149 ) (183 ) Selling, general and administrative expenses, excluding non-cash compensation expense (8 ) (24 ) Inventory valuation adjustments 4 51 Adjusted EBITDA related to unconsolidated affiliates 135 — Segment Adjusted EBITDA $ 195 $ 191Segment Adjusted EBITDA for the retail marketing segment increased due to the net impacts of the following:
All Other
Three Months EndedSeptember 30, 2015 2014 Revenues $ 976 $ 897 Cost of products sold 855 798 Gross margin 121 99 Unrealized (gains) losses on commodity risk management activities (7 ) 2 Operating expenses, excluding non-cash compensation expense (26 ) (28 ) Selling, general and administrative expenses, excluding non-cash compensation expense (35 ) (47 ) Adjusted EBITDA related to unconsolidated affiliates 47 23 Other 18 18 Eliminations (25 ) (7 ) Segment Adjusted EBITDA $ 93 $ 60 Distributions from unconsolidated affiliates $ 14 $ 2Amounts reflected in our all other segment primarily include:
Segment Adjusted EBITDA increased primarily due to an increase of $24 million in Adjusted EBITDA related to unconsolidated affiliates. The increase in Adjusted EBITDA related to unconsolidated affiliates was primarily due to higher earnings driven by stronger refining crack spreads from our investment in PES of $25 million.
In connection with the Lake Charles LNG Transaction, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. These fees were reflected in “Other” in the “All other” segment and for the three months ended September 30, 2015 were reflected as an offset to operating expenses of $6 million and selling, general and administrative expenses of $12 million in the consolidated statements of operations.
The increase in cash distributions from unconsolidated affiliates was primarily due to an increase of $15 million in cash distribution from our ownership in PES.
SUPPLEMENTAL INFORMATION ON CAPITAL EXPENDITURES
(Tabular amounts in millions) (unaudited) The following is a summary of capital expenditures (net of contributions in aid of construction costs) for the nine months ended September 30, 2015:Growth Maintenance Total Direct(1): Midstream $ 1,563 $ 67 $ 1,630 Liquids transportation and services(2) 1,618 13 1,631 Interstate transportation and storage(2) 586 81 667 Intrastate transportation and storage 54 19 73 Retail marketing(3) 179 45 224 All other (including eliminations) 290 27 317 Total direct capital expenditures 4,290 252 4,542 Indirect(1): Investment in Sunoco Logistics 1,419 49 1,468 Investment in Sunoco LP(4) 83 7 90 Total indirect capital expenditures 1,502 56 1,558 Total capital expenditures $ 5,792 $ 308 $ 6,100 (1) Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures. (2) Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects. (3) The retail marketing segment includes our wholly-owned retail marketing operations. (4) Investment in Sunoco LP includes capital expenditures for the period prior to deconsolidation on July 1, 2015.
We currently expect capital expenditures (net of contributions in aid of construction costs) for the full year 2015 to be within the following ranges:
Growth Maintenance Low High Low High Direct(1): Midstream $ 2,100 $ 2,200 $ 90 $ 110 Liquids transportation and services: NGL 1,550 1,600 20 25 Crude(2) 700 750 — — Interstate transportation and storage(2) 700 750 130 140 Intrastate transportation and storage 125 150 30 35 Retail marketing(3) 210 240 50 60 All other (including eliminations) 320 360 25 35 Total direct capital expenditures 5,705 6,050 345 405 Indirect(1): Investment in Sunoco Logistics 2,400 2,600 65 75 Investment in Sunoco LP(4) 80 85 5 10 Total indirect capital expenditures 2,480 2,685 70 85 Total projected capital expenditures $ 8,185 $ 8,735 $ 415 $ 490(1)
Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.(2)
Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects.(3)
The retail marketing segment includes our wholly-owned retail marketing operations.(4)
Investment in Sunoco LP includes capital expenditures for the period prior to deconsolidation on July 1, 2015.SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions) (unaudited) Three Months EndedSeptember 30, 2015 2014 Equity in earnings (losses) of unconsolidated affiliates: Citrus $ 29 $ 32 FEP 14 14 PES 39 14 MEP 10 10 HPC 9 10 AmeriGas (2 ) (3 ) Sunoco, LLC (13 ) — Sunoco LP 117 — Other 11 7 Total equity in earnings of unconsolidated affiliates $ 214 $ 84 Adjusted EBITDA related to unconsolidated affiliates: Citrus $ 88 $ 84 FEP 19 19 PES 46 21 MEP 23 24 HPC 16 16 Sunoco, LLC 53 — Sunoco LP 81 — Other 24 20 Total Adjusted EBITDA related to unconsolidated affiliates $ 350 $ 184 Distributions received from unconsolidated affiliates: Citrus $ 65 $ 51 FEP 19 19 PES 15 — MEP 20 18 HPC 14 14 Other 21 14 Total distributions received from unconsolidated affiliates $ 154 $ 116
View source version on businesswire.com: http://www.businesswire.com/news/home/20151104006887/en/
Investor Relations:Energy TransferBrent Ratliff, 214-981-0700orLyndsay Hannah, 214-840-5477orMedia Relations:Granado Communications GroupVicki Granado, 214-599-8785214-498-9272 (cell)
1 Year Sunoco Chart |
1 Month Sunoco Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions