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Share Name | Share Symbol | Market | Type |
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Energy Transfer Partners, L.P. Common Units Representing Limited Partner Interests (delisted) | NYSE:ETP | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
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0.00 | 0.00% | 21.47 | 0 | 01:00:00 |
Energy Transfer Partners, L.P. (NYSE: ETP) today reported its financial results for the quarter ended December 31, 2015. Adjusted EBITDA for Energy Transfer Partners, L.P. (“ETP” or the “Partnership”) for the three months ended December 31, 2015 totaled $1.36 billion, a decrease of $168 million compared to the same period last year. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the three months ended December 31, 2015 totaled $959 million, an increase of $165 million over the same period last year. Income from continuing operations for the three months ended December 31, 2015 was $21 million, an increase of $264 million over the same period last year.
Adjusted EBITDA for ETP for the year ended December 31, 2015 totaled $5.71 billion, an increase of $4 million compared to last year. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the year ended December 31, 2015 totaled $3.45 billion, an increase of $196 million over last year. Income from continuing operations for the year ended December 31, 2015 was $1.52 billion, an increase of $286 million over last year.
In January 2016, ETP announced a quarterly distribution of $1.055 per unit ($4.22 annualized) on ETP Common Units for the quarter ended December 31, 2015.
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, February 25, 2016 to discuss the fourth quarter 2015 results. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfer.com and will also be available for replay on ETP’s website 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 36% 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. website 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 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. website at www.energytransfer.com.
Sunoco Logistics Partners L.P. (NYSE: SXL), headquartered in Newtown Square, Pennsylvania, 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 a consolidated subsidiary of Energy Transfer Partners, L.P. (NYSE: ETP). For more information, visit the Sunoco Logistics Partners L.P. website 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 Partnerships’ 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 website at www.energytransfer.com.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(unaudited)
December 31, 2015 2014 ASSETS Current assets $ 4,698 $ 6,029 Property, plant and equipment, net 45,087 38,907 Advances to and investments in unconsolidated affiliates 5,003 3,760 Non-current derivative assets — 10 Other non-current assets, net 536 644 Intangible assets, net 4,421 5,526 Goodwill 5,428 7,642 Total assets $ 65,173 $ 62,518 LIABILITIES AND EQUITY Current liabilities $ 4,121 $ 6,585 Long-term debt, less current maturities 28,553 24,831 Long-term notes payable – related party 233 — Non-current derivative liabilities 137 154 Deferred income taxes 4,082 4,331 Other non-current liabilities 968 1,258 Commitments and contingencies Series A Preferred Units 33 33 Redeemable noncontrolling interests 15 15 Equity: Total partners’ capital 20,836 12,070 Noncontrolling interest 6,195 5,153 Predecessor equity — 8,088 Total equity 27,031 25,311 Total liabilities and equity $ 65,173 $ 62,518ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data) (unaudited)Three Months EndedDecember 31,
Years Ended December 31, 2015 2014 2015 2014 REVENUES $ 5,825 $ 13,427 $ 34,292 $ 55,475 COSTS AND EXPENSES: Cost of products sold 4,237 11,591 27,029 48,414 Operating expenses 498 696 2,261 2,059 Depreciation, depletion and amortization 478 463 1,929 1,669 Selling, general and administrative 86 148 475 520 Impairment losses 339 370 339 370 Total costs and expenses 5,638 13,268 32,033 53,032 OPERATING INCOME 187 159 2,259 2,443 OTHER INCOME (EXPENSE): Interest expense, net (312 ) (297 ) (1,291 ) (1,165 ) Equity in earnings from unconsolidated affiliates 81 67 469 332 Gain on sale of AmeriGas common units — — — 177 Losses on extinguishments of debt — (25 ) (43 ) (25 ) Losses on interest rate derivatives (4 ) (84 ) (18 ) (157 ) Other, net (34 ) 24 22 (12 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (82 ) (156 ) 1,398 1,593 Income tax expense (benefit) from continuing operations (103 ) 87 (123 ) 358 INCOME (LOSS) FROM CONTINUING OPERATIONS 21 (243 ) 1,521 1,235 Income (loss) from discontinued operations — (2 ) — 64 NET INCOME (LOSS) 21 (245 ) 1,521 1,299 Less: Net income (loss) attributable to noncontrolling interest (25 ) (103 ) 157 116 Less: Net loss attributable to predecessor — (250 ) (34 ) (153 ) NET INCOME ATTRIBUTABLE TO PARTNERS 46 108 1,398 1,336 General Partner’s interest in net income 285 140 1,064 513 Class H Unitholder’s interest in net income 74 58 258 217 Class I Unitholder’s interest in net income 14 — 94 — Common Unitholders’ interest in net income (loss) $ (327 ) $ (90 ) $ (18 ) $ 606 INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT: Basic $ (0.68 ) $ (0.27 ) $ (0.09 ) $ 1.58 Diluted $ (0.68 ) $ (0.27 ) $ (0.10 ) $ 1.58 NET INCOME (LOSS) PER COMMON UNIT: Basic $ (0.68 ) $ (0.28 ) $ (0.09 ) $ 1.77 Diluted $ (0.68 ) $ (0.28 ) $ (0.10 ) $ 1.77 WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING: Basic 485.1 351.2 432.8 331.5 Diluted 485.5 351.2 435.4 332.8SUPPLEMENTAL INFORMATION
(Dollars and units in millions, except per unit amounts) (unaudited)Three Months EndedDecember 31,
Years Ended December 31, 2015 2014 2015 2014 Reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow (a): Net income (loss) $ 21 $ (245 ) $ 1,521 $ 1,299 Interest expense, net of interest capitalized 312 297 1,291 1,165 Gain on sale of AmeriGas common units — — — (177 ) Impairment losses 339 370 339 370 Income tax expense (benefit) from continuing operations (b) (103 ) 87 (123 ) 358 Depreciation, depletion and amortization 478 463 1,929 1,669 Non-cash compensation expense 20 18 79 68 Losses on interest rate derivatives 4 84 18 157 Unrealized (gains) losses on commodity risk management activities (7 ) (113 ) 65 (112 ) Inventory valuation adjustments 120 456 104 473 Losses on extinguishments of debt — 25 43 25 Equity in earnings of unconsolidated affiliates (81 ) (67 ) (469 ) (332 ) Adjusted EBITDA related to unconsolidated affiliates 226 164 937 748 Other, net 31 (11 ) (20 ) (1 )Adjusted EBITDA (consolidated)
1,360 1,528 5,714 5,710 Adjusted EBITDA related to unconsolidated affiliates (226 ) (164 ) (937 ) (748 ) Distributable cash flow from unconsolidated affiliates (c) 214 119 682 482 Interest expense, net of interest capitalized (312 ) (297 ) (1,291 ) (1,165 ) Amortization included in interest expense (6 ) (12 ) (36 ) (60 ) Current income tax (expense) benefit from continuing operations (b) 283 (70 ) 325 (407 ) Transaction-related income taxes (d) (51 ) 15 (51 ) 396 Maintenance capital expenditures (177 ) (184 ) (485 ) (444 ) Other, net 1 2 12 7 Distributable Cash Flow (consolidated) 1,086 937 3,933 3,771 Distributable Cash Flow attributable to Sunoco Logistics Partners L.P. (“Sunoco Logistics”) (100%) (245 ) (177 ) (879 ) (750 ) Distributions from Sunoco Logistics to ETP 118 81 413 285 Distributable Cash Flow attributable to Sunoco LP (100%) (e) — (52 ) (68 ) (56 ) Distributions from Sunoco LP to ETP (e) — 10 24 18 Distributable cash flow attributable to noncontrolling interest in Edwards Lime Gathering LLC (5 ) (5 ) (20 ) (19 ) Distributable Cash Flow attributable to the partners of ETP 954 794 3,403 3,249 Transaction-related expenses 5 — 42 — Distributable Cash Flow attributable to the partners of ETP, as adjusted $ 959 $ 794 $ 3,445 $ 3,249 Distributions to the partners of ETP (f): Limited Partners: Common units held by public $ 512 $ 321 $ 1,970 $ 1,179 Common units held by ETE 3 31 54 119 Class H Units held by ETE (g) 77 60 263 219 General Partner interests held by ETE 8 5 31 21 Incentive Distribution Rights (“IDRs”) held by ETE 324 208 1,261 754 IDR relinquishments net of Class I Unit distributions (28 ) (68 ) (111 ) (250 ) Total distributions to be paid to the partners of ETP $ 896 $ 557 $ 3,468 $ 2,042 Common Units outstanding – end of period 505.6 355.5 505.6 355.5 Distribution coverage ratio (h)1.07
x
1.43
x
0.99
x
1.59
x
Distributable Cash Flow per Common Unit (i) $ 1.19 $ 1.68 $ 4.62 $ 7.56(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 twelve months ended December 31, 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 twelve months ended December 31, 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, as well as a favorable impact of $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. For the three and twelve months ended December 31, 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.
The three months ended December 31, 2015 reflect current income tax benefits of $80 million due to lower earnings among the Partnership’s consolidated corporate subsidiaries, $120 million due to the retroactive re-enactment of bonus depreciation, and $24 million attributable to the reversal of an income tax reserve for certain amended tax returns that had been filed claiming previously disallowed Pennsylvania net operating loss deductions. Additionally, the three months ended December 31, 2015 also reflect a $51 million current income tax benefit related to the funding of Sunoco, Inc.’s pension plan obligations, which benefit has been excluded from Distributable Cash Flow, as discussed in note (d) below.
(c) For the three months ended December 31, 2015, distributable cash flow from unconsolidated affiliates includes distributions to be paid by Sunoco LP with respect to the fourth quarter of 2015, as well as the Partnership’s share of the distributable cash flow of Sunoco LLC for the fourth quarter of 2015. For the year ended December 31, 2015, distributable cash flow from unconsolidated affiliates includes distributions to be paid by Sunoco LP with respect to the third and fourth quarters of 2015, as well as the Partnership’s share of the distributable cash flow of Sunoco LLC for the third and fourth quarters of 2015.
(d) For the three months ended December 31, 2015, transaction-related income taxes reflect a $51 million current income tax benefit related to the funding of Sunoco, Inc.’s pension plan obligations, which amount is reflected in “Current income tax (expense) benefit from continuing operations.”
Transaction-related income taxes primarily included income tax expense related to the Lake Charles LNG Transaction. For the three months and year ended December 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.
(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 months and years ended December 31, 2015 and 2014 were calculated as follows:
Three Months EndedDecember 31,
Years Ended December 31, 2015 2014 2015 2014 General partner distributions and incentive distributions from Sunoco Logistics $ 86 $ 54 $ 293 $ 185 90.05 % 50.05 % 90.05 % 50.05 % Share of Sunoco Logistics general partner and incentive distributions payable to Class H Unitholder 77 27 263 93 Incremental distributions payable to Class H Unitholder — 33 — 126 Total Class H Unit distributions $ 77 $ 60 $ 263 $ 219 * 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 EndedDecember 31,
Years Ended December 31, 2015 2014 2015 2014 Distributable Cash Flow attributable to the partners of ETP, as adjusted $ 959 $ 794 $ 3,445 $ 3,249 Less: Class H Units held by ETE (77 ) (60 ) (263 ) (219 ) General Partner interests held by ETE (8 ) (5 ) (31 ) (21 ) IDRs held by ETE (324 ) (208 ) (1,261 ) (754 ) IDR relinquishments net of Class I Unit distributions 28 68 111 250 $ 578 $ 589 $ 2,001 $ 2,505 Weighted average Common Units outstanding – basic 485.1 351.2 432.8 331.5 Distributable Cash Flow per Common Unit $ 1.19 $ 1.68 $ 4.62 $ 7.56SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions) (unaudited)Our segment results are presented based on the measure of Segment Adjusted EBITDA. The tables below identify the components of Segment Adjusted EBITDA, which was calculated as follows:
Three Months EndedDecember 31,
2015 2014 Segment Adjusted EBITDA: Midstream $ 264 $ 360 Liquids transportation and services 222 159 Interstate transportation and storage 283 307 Intrastate transportation and storage 122 120 Investment in Sunoco Logistics 317 237 Retail marketing 119 295 All other 33 50 $ 1,360 $ 1,528Midstream
Three Months EndedDecember 31,
2015 2014 Gathered volumes (MMBtu/d): 10,051,612 9,531,307 NGLs produced (Bbls/d): 443,741 376,724 Equity NGLs produced (Bbls/d): 29,437 30,656 Revenues $ 1,289 $ 1,599 Cost of products sold 840 993 Gross margin 449 606 Unrealized gains on commodity risk management activities — (76 ) Operating expenses, excluding non-cash compensation expense (183 ) (156 ) Selling, general and administrative expenses, excluding non-cash compensation expense (8 ) (16 ) Adjusted EBITDA related to unconsolidated affiliates 6 2 Segment Adjusted EBITDA $ 264 $ 360Gathered volumes and NGLs produced increased during the three months ended December 31, 2015 compared to the same period last year primarily due 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 EndedDecember 31,
2015 2014 Gathering and processing fee-based revenues $ 393 $ 382 Non fee-based contracts and processing 56 224 Total gross margin $ 449 $ 606For the three months ended December 31, 2015 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:
Liquids Transportation and Services
Three Months EndedDecember 31,
2015 2014 Liquids transportation volumes (Bbls/d) 473,656 393,743 NGL fractionation volumes (Bbls/d) 249,566 204,565 Revenues $ 972 $ 982 Cost of products sold 716 770 Gross margin 256 212 Unrealized (gains) losses on commodity risk management activities 6 (11 ) Operating expenses, excluding non-cash compensation expense (38 ) (38 ) Selling, general and administrative expenses, excluding non-cash compensation expense (4 ) (5 ) Adjusted EBITDA related to unconsolidated affiliates 2 1 Segment Adjusted EBITDA $ 222 $ 159NGL transportation volumes increased due to increases from the Eagle Ford, Permian, and Southeast Texas producing regions, offset by decreases from North Texas. Additionally, we commissioned a crude transportation pipeline in the fourth quarter of 2014 that transported approximately 44,000 Bbls/d for the three months ended December 31, 2015.
Segment Adjusted EBITDA for the liquids transportation and services segment reflected an increase in gross margin as follows:
Three Months EndedDecember 31,
2015 2014 Transportation margin $ 104 $ 100 Processing and fractionation margin 79 66 Storage margin 48 44 Other margin 25 2 Total gross margin $ 256 $ 212For the three months ended December 31, 2015 compared to the same period last year, Segment Adjusted EBITDA related to our liquids transportation and services segment increased due to the net impacts of the following:
Interstate Transportation and Storage
Three Months EndedDecember 31,
2015 2014 Natural gas transported (MMBtu/d) 5,739,157 6,125,616 Natural gas sold (MMBtu/d) 18,665 15,643 Revenues $ 258 $ 267 Operating expenses, excluding non-cash compensation, amortization and accretion expenses (83 ) (72 ) Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (9 ) (16 ) Adjusted EBITDA related to unconsolidated affiliates 117 117 Other — 11 Segment Adjusted EBITDA $ 283 $ 307 Distributions from unconsolidated affiliates $ 75 $ 80Transported volumes decreased primarily due to a managed contract roll off to facilitate the transfer of one of the pipelines that was taken out of service in advance of being repurposed from natural gas service to crude oil service. The decrease was partially offset by increased deliveries on the Transwestern pipeline due to sustained cooling demand in the Phoenix market and increased customer demand in New Mexico.
Segment Adjusted EBITDA for the interstate transportation and storage segment decreased primarily due to a $9 million decrease in revenues due to the expiration of a transportation rate schedule on the Transwestern pipeline and $8 million due to a managed contract roll off to facilitate the transfer of one of the pipelines that was taken out of service in advance of being repurposed from natural gas service to crude oil service. These decreases were partially offset by sales of capacity at higher rates on the Panhandle, Trunkline and Transwestern pipelines.
The decrease in cash distributions from unconsolidated affiliates reflected a decrease in cash distributions from Citrus due to slightly higher cash taxes on Citrus for the three months ended December 31, 2015.
Intrastate Transportation and Storage
Three Months EndedDecember 31,
2015 2014 Natural gas transported (MMBtu/d) 7,926,907 8,485,823 Revenues $ 503 $ 610 Cost of products sold 327 446 Gross margin 176 164 Unrealized gains on commodity risk management activities (23 ) (4 ) Operating expenses, excluding non-cash compensation expense (42 ) (49 ) Selling, general and administrative expenses, excluding non-cash compensation expense (4 ) (6 ) Adjusted EBITDA related to unconsolidated affiliates 15 15 Segment Adjusted EBITDA $ 122 $ 120Transported volumes decreased compared to the same period last year primarily due to lower production volume, mostly in the Barnett Shale region, partially offset by increased volumes related to significant new long-term transportation contracts.
For the three months ended December 31, 2015 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:
Investment in Sunoco Logistics
Three Months EndedDecember 31,
2015 2014 Revenue $ 2,305 $ 3,875 Cost of products sold(1) 2,067 3,812 Gross margin 238 63 Unrealized (gains) losses on commodity risk management activities 13 (3 ) Operating expenses, excluding non-cash compensation expense(1) (42 ) (63 ) Selling, general and administrative expenses, excluding non-cash compensation expense (24 ) (32 ) Inventory valuation adjustments 118 258 Adjusted EBITDA related to unconsolidated affiliates 14 13 Other — 1 Segment Adjusted EBITDA $ 317 $ 237 (1) Prior period expenses have been recast to conform to Sunoco Logistics’ current presentation.For the three months ended December 31, 2015 compared to the same period last year, Segment Adjusted EBITDA related to Sunoco Logistics increased due to the following:
Retail Marketing
Three Months EndedDecember 31,
2015 2014 Motor fuel outlets and convenience stores, end of period: Retail 438 1,251 Third-party wholesale — 5,399 Total 438 6,650 Total motor fuel gallons sold (in millions): Retail 266 608 Third-party wholesale — 1,304 Total 266 1,912 Motor fuel gross profit (cents/gallon): Retail 24.1 37.4 Third-party wholesale — 13.0 Volume-weighted average for all gallons 24.1 20.7 Merchandise sales (in millions) $ 143 $ 489 Retail merchandise margin % 25.6 % 30.1 % Revenue $ 777 $ 5,920 Cost of products sold 655 5,493 Gross margin 122 427 Unrealized gains on commodity risk management activities — (7 ) Operating expenses, excluding non-cash compensation expense (95 ) (283 ) Selling, general and administrative expenses, excluding non-cash compensation expense (4 ) (41 ) Inventory valuation adjustments 2 198 Adjusted EBITDA related to unconsolidated affiliates 94 1 Segment Adjusted EBITDA $ 119 $ 295The results reflected above include Sunoco LP for the three months ended December 31, 2014.
For the three months ended December 31, 2015 compared to the same period last year, Segment Adjusted EBITDA related to our retail marketing segment decreased due to the net impacts of the following:
All Other
Three Months EndedDecember 31,
2015 2014 Revenue $ 853 $ 949 Cost of products sold 748 868 Gross margin 105 81 Unrealized gains on commodity risk management activities (3 ) (12 ) Operating expenses, excluding non-cash compensation expense (24 ) (31 ) Selling, general and administrative expenses, excluding non-cash compensation expense (31 ) (28 ) Adjusted EBITDA related to unconsolidated affiliates (20 ) 17 Other 19 17 Elimination (13 ) 6 Segment Adjusted EBITDA $ 33 $ 50 Distributions from unconsolidated affiliates $ 43 $ 3Amounts reflected in our all other segment primarily include:
Segment Adjusted EBITDA decreased primarily due to lower earnings driven by the impact of weaker refining crack spreads on our investment in PES.
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 December 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 increase in cash distributions from unconsolidated affiliates was due to an increase of $42 million in cash distributions 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) during the year ended December 31, 2015:
Growth Maintenance Total Direct(1): Midstream $ 2,055 $ 117 $ 2,172 Liquids transportation and services(2) 2,091 18 2,109 Interstate transportation and storage(2) 741 119 860 Intrastate transportation and storage 74 31 105 Retail marketing(3) 259 63 322 All other (including eliminations) 337 46 383Total direct capital expenditures
5,557 394 5,951 Indirect(1): Investment in Sunoco Logistics 2,042 84 2,126 Investment in Sunoco LP(4) 83 7 90 Total indirect capital expenditures 2,125 91 2,216 Total capital expenditures $ 7,682 $ 485 $ 8,167 (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 for the full year 2016 to be within the following ranges:
Growth Maintenance Low High Low High Direct(1): Midstream $ 1,200 $ 1,250 $ 110 $ 120 Liquids transportation and services NGL 1,150 1,200 25 30 Crude(3) 1,275 1,325 — — Interstate transportation and storage(2)(3) 375 415 140 145 Intrastate transportation and storage(2) 10 20 35 40 All other (including eliminations) 65 75 20 25 Total direct capital expenditures 4,075 4,285 330 360 Indirect(1): Investment in Sunoco Logistics 2,600 2,800 75 85 Total projected capital expenditures $ 6,675 $ 7,085 $ 405 $ 445 (1) Indirect capital expenditures comprise those funded by our publicly traded subsidiary; all other capital expenditures are reflected as direct capital expenditures. (2) Net of amounts forecasted to be financed at the asset level with non-recourse debt of approximately $325 million. (3) Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects.SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions) (unaudited)Three Months EndedDecember 31,
2015 2014 Equity in earnings (losses) of unconsolidated affiliates: Citrus $ 20 $ 20 FEP 14 14 PES (25 ) 10 MEP 12 13 HPC 8 3 AmeriGas (5 ) (2 ) Sunoco, LLC 3 — Sunoco LP 85 — Other (31 ) 9 Total equity in earnings of unconsolidated affiliates $ 81 $ 67 Adjusted EBITDA related to unconsolidated affiliates(1): Citrus $ 73 $ 72 FEP 19 19 PES (16 ) 17 MEP 25 26 HPC 15 9 Sunoco, LLC 38 — Sunoco LP 56 — Other 16 21 Total Adjusted EBITDA related to unconsolidated affiliates $ 226 $ 164 Distributions received from unconsolidated affiliates: Citrus $ 37 $ 42 FEP 18 19 PES 42 — MEP 20 19 HPC 11 13 Sunoco LP 39 — Other 12 10 Total distributions received from unconsolidated affiliates $ 179 $ 103 (1) These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
View source version on businesswire.com: http://www.businesswire.com/news/home/20160224006658/en/
Investor Relations:Energy TransferBrent Ratliff, 214-981-0700orLyndsay Hannah, 214-840-5477orMedia Relations:Granado Communications GroupVicki Granado, 214-599-8785214-498-9272 (cell)
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