SUN Sunoco LP

Energy Transfer Partners, L.P. (NYSE: ETP) today reported its financial results for the quarter ended December 31, 2016. For the three months ended December 31, 2016 Energy Transfer Partners, L.P. (“ETP” or the “Partnership”) reported a net loss of $362 million, a decrease of $383 million compared to net income of $21 million for the same period last year, primarily due to non-cash impairments of $813 million recorded in the current period. Adjusted EBITDA for the three months ended December 31, 2016 totaled $1.43 billion, an increase of $73 million over the same period last year. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the three months ended December 31, 2016 totaled $796 million, a decrease of $83 million compared to the same period last year, primarily due to a current tax benefit that was recorded in the prior year. Excluding the impact of the change in current tax benefit between periods, Distributable Cash Flow attributable to the partners of ETP, as adjusted, increased approximately $100 million compared to the fourth quarter of 2015.

In January 2017, ETP announced a quarterly distribution of $1.055 per unit ($4.22 annualized) on ETP Common Units for the quarter ended December 31, 2016.

ETP’s other recent key accomplishments include the following:

• In November 2016, ETP and Sunoco Logistics Partners L.P. (“Sunoco Logistics”) entered into a merger agreement providing for the acquisition of ETP by Sunoco Logistics in a unit-for-unit transaction. Under the terms of the transaction, ETP unitholders will receive 1.5 common units of Sunoco Logistics for each common unit of ETP they own.
• On November 1, 2016, ETP acquired certain interests in PennTex Midstream Partners, LP (“PennTex”) from various parties for total consideration of approximately $640 million in ETP units and cash.
• In February 2017, ETP announced that the Federal Energy Regulatory Commission (“FERC”) approved Rover Pipeline LLC’s (“Rover”) application to construct and operate the Rover Pipeline project, allowing Rover to move forward with its targeted in-service goals of July 2017 for Phase I and November 2017 for Phase II.
• On February 8, 2017, ETP announced that Dakota Access, LLC had received an easement from the U.S. Army Corps of Engineers (“Army Corps”) to construct a pipeline across land owned by the Army Corps on both sides of Lake Oahe in North Dakota. With the receipt of the easement, ETP expects to commence commercial operations on the Dakota Access Pipeline and the adjoining Energy Transfer Crude Oil Pipeline (collectively, the “Bakken Pipeline”) in the second quarter of 2017. In addition, the previously announced project financing for the Bakken Pipeline and the sale of a 36.75% interest in the Bakken Pipeline were completed in February 2017.
• In January 2017, the previously announced Comanche Trail Pipeline, which transports natural gas from the Permian Basin to Mexico, was placed into service.
• In the fourth quarter of 2016, ETP issued 6.5 million common units through its at-the-market equity program, generating net proceeds of $236 million. In addition, in January 2017, ETP raised $568 million through a private placement of its common units and $1.48 billion through a senior notes offering.
• As of December 31, 2016, ETP’s $3.75 billion revolving credit facility had $2.78 billion of outstanding borrowings, and its leverage ratio, as defined by the credit agreement, was 4.32x.

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 23, 2017 to discuss the fourth quarter 2016 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 that owns and operates 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 of Sunoco Logistics Partners L.P. (NYSE: SXL), which operates a geographically diverse portfolio of pipelines, terminalling and acquisition and marketing assets. ETP recently acquired the general partner, 100% of the incentive distribution rights, and an approximate 65% limited partnership interest in PennTex Midstream Partners, LP (NASDAQ: PTXP), which is a growth-oriented master limited partnership that provides natural gas gathering and processing and residue gas and natural gas liquids transportation services to producers in northern Louisiana. ETP’s general partner is owned by Energy Transfer Equity, L.P. 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 that owns the general partner and 100% of the incentive distribution rights of Energy Transfer Partners, L.P. and Sunoco LP. ETE also owns approximately 18.4 million ETP Common Units and 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). 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) is a master limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary pipeline, terminalling and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, natural gas liquids, and refined products. 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.

PennTex Midstream Partners, LP (NASDAQ: PTXP) is a growth-oriented master limited partnership focused on owning, operating, acquiring and developing midstream energy infrastructure assets in North America. PTXP provides natural gas gathering and processing and residue gas and natural gas liquids transportation services to producers in the Terryville Complex in northern Louisiana. PennTex Midstream Partners, LP’s general partner is a consolidated subsidiary of Energy Transfer Partners, L.P. (NYSE: ETP). For more information, visit the PennTex Midstream Partners, LP website at www.penntex.com.

Forward-Looking Statements

This news 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 Report 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 SUBSIDIARIESCONDENSED CONSOLIDATED BALANCE SHEETS(In millions)(unaudited)

  December 31, 2016     2015 ASSETS Current assets $ 5,729 $ 4,698   Property, plant and equipment, net 50,917 45,087   Advances to and investments in unconsolidated affiliates 4,280 5,003 Other non-current assets, net 672 536 Intangible assets, net 4,696 4,421 Goodwill   3,897   5,428 Total assets $ 70,191 $ 65,173     LIABILITIES AND EQUITY Current liabilities $ 6,203 $ 4,121   Long-term debt, less current maturities 31,741 28,553 Long-term notes payable – related party 250 233 Non-current derivative liabilities 76 137 Deferred income taxes 4,394 4,082 Other non-current liabilities 952 968   Commitments and contingencies Series A Preferred Units 33 33 Redeemable noncontrolling interests 15 15   Equity: Total partners’ capital 18,642 20,836 Noncontrolling interest   7,885   6,195 Total equity   26,527   27,031 Total liabilities and equity $ 70,191 $ 65,173            

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIESCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS(In millions, except per unit data)(unaudited)

  Three Months Ended December 31, Years Ended December 31, 2016     2015 2016     2015 REVENUES $ 6,526 $ 5,825 $ 21,827 $ 34,292 COSTS AND EXPENSES: Cost of products sold 4,865 4,237 15,394 27,029 Operating expenses 374 498 1,484 2,261 Depreciation, depletion and amortization 517 478 1,986 1,929 Selling, general and administrative 122 86 348 475 Impairment losses   813     339     813     339   Total costs and expenses   6,691     5,638     20,025     32,033   OPERATING INCOME (LOSS) (165 ) 187 1,802 2,259 OTHER INCOME (EXPENSE): Interest expense, net (336 ) (312 ) (1,317 ) (1,291 ) Equity in earnings (losses) from unconsolidated affiliates (201 ) 81 59 469 Impairment of investment in an unconsolidated affiliate — — (308 ) — Gains on acquisitions 83 — 83 — Losses on extinguishments of debt — — — (43 ) Gains (losses) on interest rate derivatives 167 (4 ) (12 ) (18 ) Other, net   35     (34 )   131     22   INCOME (LOSS) BEFORE INCOME TAX EXPENSE (417 ) (82 ) 438 1,398 Income tax benefit   (55 )   (103 )   (186 )   (123 ) NET INCOME (LOSS) (362 ) 21 624 1,521 Less: Net income (loss) attributable to noncontrolling interest 96 (25 ) 327 157 Less: Net loss attributable to predecessor   —     —     —     (34 ) NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS (458 ) 46 297 1,398 General Partner’s interest in net income 208 285 948 1,064 Class H Unitholder’s interest in net income 94 74 351 258 Class I Unitholder’s interest in net income   2     14     8     94   Common Unitholders’ interest in net loss $ (762 ) $ (327 ) $ (1,010 ) $ (18 ) NET LOSS PER COMMON UNIT: Basic $ (1.47 ) $ (0.68 ) $ (2.06 ) $ (0.09 ) Diluted $ (1.47 ) $ (0.68 ) $ (2.06 ) $ (0.10 ) WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING: Basic 522.5 485.1 505.5 432.8 Diluted 522.5 485.5 505.5 433.5            

SUPPLEMENTAL INFORMATION(Dollars and units in millions, except per unit amounts)(unaudited)

  Three Months Ended December 31, Years Ended December 31, 2016     2015 2016     2015 Reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow (a): Net income (loss) $ (362 ) $ 21 $ 624 $ 1,521 Interest expense, net 336 312 1,317 1,291 Gains on acquisitions (83 ) — (83 ) — Impairment losses (b) 813 339 813 339 Income tax benefit (55 ) (103 ) (186 ) (123 ) Depreciation, depletion and amortization 517 478 1,986 1,929 Non-cash compensation expense 20 20 80 79 (Gains) losses on interest rate derivatives (167 ) 4 12 18 Unrealized (gains) losses on commodity risk management activities 35 (7 ) 131 65 Inventory valuation adjustments (27 ) 120 (170 ) 104 Impairment of investment in an unconsolidated affiliate — — 308 — Losses on extinguishments of debt — — — 43 Equity in (earnings) losses of unconsolidated affiliates 201 (81 ) (59 ) (469 ) Adjusted EBITDA related to unconsolidated affiliates 235 226 946 937 Other, net   (30 )   31     (114 )   (20 ) Adjusted EBITDA (consolidated) 1,433 1,360 5,605 5,714 Adjusted EBITDA related to unconsolidated affiliates (235 ) (226 ) (946 ) (937 ) Distributable cash flow from unconsolidated affiliates 134 129 518 646 Interest expense, net of interest capitalized (336 ) (312 ) (1,317 ) (1,291 ) Amortization included in interest expense (4 ) (6 ) (20 ) (36 ) Current income tax benefit (c) 40 283 17 325 Transaction-related income taxes (c) — (51 ) — (51 ) Maintenance capital expenditures (134 ) (177 ) (368 ) (485 ) Other, net   8     1     21     12   Distributable Cash Flow (consolidated) 906 1,001 3,510 3,897   Distributable Cash Flow attributable to Sunoco Logistics (100%) (247 ) (240 ) (943 ) (874 ) Distributions from Sunoco Logistics to ETP 139 118 532 413 Distributable Cash Flow attributable to PennTex (100%) (11 ) — (11 ) — Distributions from PennTex to ETP 8 — 16 — Distributable Cash Flow attributable to Sunoco LP (100%) (d) — — — (68 ) Distributions from Sunoco LP to ETP (d) — — — 24 Distributable cash flow attributable to noncontrolling interest in other consolidated subsidiaries   (11 )   (5 )   (37 )   (20 ) Distributable Cash Flow attributable to the partners of ETP 784 874 3,067 3,372 Transaction-related expenses   12     5     16     42   Distributable Cash Flow attributable to the partners of ETP, as adjusted $ 796   $ 879   $ 3,083   $ 3,414     Distributions to the partners of ETP (e): Limited Partners: Common units held by public $ 561 $ 512 $ 2,168 $ 1,970 Common units held by ETE 20 3 28 54 Class H Units held by ETE (f) 94 77 357 263 General Partner interests held by ETE 8 8 32 31 Incentive Distribution Rights (“IDRs”) held by ETE 351 324 1,363 1,261 IDR relinquishments net of Class I Unit distributions (g)   (138 )   (28 )   (409 )   (111 ) Total distributions to be paid to the partners of ETP $ 896   $ 896   $ 3,539   $ 3,468   Common Units outstanding – end of period (e)   529.9     505.6     529.9     505.6   Distribution coverage ratio (h)  

0.89

x

 

0.98

x

 

0.87

x

 

0.98

x

 

(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, depletion, 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, non-cash impairment charges, losses on extinguishments of debt 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, depletion 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, non-cash impairment charges, losses on extinguishments of debt 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). For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investee’s distributable cash flow.

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) During the three months ended December 31, 2016, we recorded goodwill impairments of $638 million in the interstate transportation and storage segment and $32 million in the midstream segment. These goodwill impairments were primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. In addition, impairment losses for the three months ended December 31, 2016 also include a $133 million impairment to property, plant and equipment in the interstate transportation and storage segment due to a decrease in projected future cash flows as well as a $10 million impairment to property, plant and equipment in the midstream segment. During the three months ended December 31, 2015, we recorded goodwill impairments of (i) $99 million related to Transwestern due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, (ii) $106 million related to Lone Star Refinery Services due primarily to changes in assumptions related to potential future revenues as well as the market declines in current and expected future commodity prices, (iii) $110 million of fixed asset impairments related to Lone Star NGL Refinery Services primarily due to the economic obsolescence identified as a result of low utilization and expected decrease in future cash flows, and (iv) $24 million of intangible asset impairments related to Lone Star NGL Refinery Services primarily due to the economic obsolescence identified as a result of expected decrease in future cash flows.

(c) 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.

(d) 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.

(e) Distributions on ETP Common Units and the number of ETP Common Units outstanding at the end of the period, both as reflected above, exclude amounts related to ETP Common Units held by subsidiaries of ETP.

(f) Distributions on the Class H Units for the three months and years ended December 31, 2016 and 2015 were calculated as follows:

   

Three Months EndedDecember 31,

     

Years EndedDecember 31,

2016     2015 2016     2015 General partner distributions and incentive distributions from Sunoco Logistics $ 105 $ 86 $ 397 $ 293   90.05 %   90.05 %   90.05 %   90.05 % Total Class H Unit distributions $ 94   $ 77   $ 357   $ 263    

* 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) IDR relinquishments for the three and twelve months ended December 31, 2016 include the impact of $95 million and $255 million, respectively, of incentive distribution reductions beginning with respect to the second quarter 2016 distributions, as agreed to between ETE and ETP in July 2016. Additionally, the three and twelve months ended December 31, 2016 include the impact of $8 million and $17 million, respectively, of incentive distribution reductions beginning with respect to the third quarter of 2016 distributions, as agreed to between ETE and ETP in November 2016 related to ETP’s acquisition of PennTex.

(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.

SUMMARY 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:

• 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 EndedDecember 31,

2016     2015 Segment Adjusted EBITDA: Midstream $ 258 $ 260 Liquids transportation and services 281 226 Interstate transportation and storage 269 283 Intrastate transportation and storage 152 122 Investment in Sunoco Logistics 327 317 All other   146   152 $ 1,433 $ 1,360    

Midstream

   

Three Months EndedDecember 31,

2016     2015 Gathered volumes (MMBtu/d): 9,693,728 10,051,593 NGLs produced (Bbls/d): 430,603 443,741 Equity NGLs produced (Bbls/d): 29,001 29,437 Revenues $ 1,414 $ 1,286 Cost of products sold   966     841   Gross margin 448 445 Unrealized losses on commodity risk management activities 15 — Operating expenses, excluding non-cash compensation expense (168 ) (183 ) Selling, general and administrative expenses, excluding non-cash compensation expense (42 ) (8 ) Adjusted EBITDA related to unconsolidated affiliates   5     6   Segment Adjusted EBITDA $ 258   $ 260    

For the three months ended December 31, 2016 compared to the same period last year, gathered volumes decreased during the three months ended December 31, 2016 compared to the same period last year primarily due to basin declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions, partially offset by gains in the Permian, Northeast and the impact of recent acquisitions, including PennTex. NGL production declined primarily due to basin declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions, partially offset by increased gathering and processing capacities in the Permian and Cotton Valley regions.

For the three months ended December 31, 2016 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:

• a decrease of $2 million in non-fee based margin due to volume declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions;
• a decrease of $4 million in fee-based revenue due to declines in South Texas, North Texas and the Mid-Continent/Panhandle regions offset by growth in the Permian, Northeast and the impact of acquisitions, including PennTex;
• a decrease of $3 million (excluding unrealized losses of $13 million) due to lower benefit from settled derivatives used to hedge commodity margins; and
• an increase in general and administrative expenses of $34 million primarily due to year-end accruals and costs associated with the acquisition of PennTex; partially offset by
• an increase of $31 million in non-fee based margins due to higher crude oil and NGL prices; and
• a decrease in operating expenses of $15 million primarily due to lower ad valorem taxes and lower employee costs.

Liquids Transportation and Services

   

Three Months EndedDecember 31,

2016     2015 Liquids transportation volumes (Bbls/d) 669,694 523,285 NGL fractionation volumes (Bbls/d) 393,663 249,566 Revenues $ 1,561 $ 975 Cost of products sold   1,235     715   Gross margin 326 260 Unrealized losses on commodity risk management activities 12 6 Operating expenses, excluding non-cash compensation expense (51 ) (38 ) Selling, general and administrative expenses, excluding non-cash compensation expense (6 ) (4 ) Adjusted EBITDA related to unconsolidated affiliates (1 ) 2 Other   1     —   Segment Adjusted EBITDA $ 281   $ 226    

For the three months ended December 31, 2016 compared to the same period last year, NGL transportation volumes increased in several of the major producing regions including the Permian, North Texas and Louisiana. Crude transportation volumes increased as we placed Phase I of the Bayou Bridge crude pipeline in service in the second quarter of 2016 and transported approximately 72,000 Bbls/d during the three months ended December 31, 2016. In addition, we placed certain West Texas crude assets into service in 2016, which collectively resulted in an increase of 23,000 Bbls/d during the three months ended December 31, 2016.

Average daily fractionated volumes increased approximately 144,000 Bbls/d for the three months ended December 31, 2016 compared to the same period last year primarily due to the ramp-up of our third 100,000 Bbls/d fractionator at Mont Belvieu, Texas, which was commissioned in late December 2015, as well as increased producer volumes as mentioned above. In addition, we placed a fourth fractionator in-service in the fourth quarter of 2016.

For the three months ended December 31, 2016 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:

• an increase of $40 million in transportation margin due to higher NGL and crude transportation volumes. NGL volumes were higher from several major producing regions, with the increases from the Permian region being the most significant. These increases in NGL transportation volumes resulted in a $22 million increase in transportation fees. In addition, crude transportation fees increased $8 million due to new assets being placed in-service, including the first phase of the Bayou Bridge pipeline in April 2016 and crude gathering assets in West Texas during 2016;
• an increase of $38 million in processing and fractionation margin (excluding changes in unrealized losses of $9 million) primarily due to increased producer volumes, primarily from the West Texas region along with an increase in our fractionation capacity due to the placing in service of our third fractionator in December 2015 and our fourth fractionator in October 2016; and
• an increase of $12 million in storage margin due to an increase in volumes from our Mont Belvieu fractionators. Throughput volumes, on which we earn a fee in our storage assets, increased 26%, which resulted in an increase in margin of $6 million. We also realized an increase of $2 million due to increased demand for our leased storage capacity as a result of more favorable market conditions. In addition, we realized increased terminal and pipeline fees revenue of $4 million compared to the prior year; partially offset by
• a decrease of $14 million in other margin (excluding changes in unrealized losses of $3 million) primarily due to the timing of the withdrawal and sale of NGL component inventory;
• an increase of $13 million in operating expenses primarily due to increased costs associated with our third fractionator at Mont Belvieu; and
• an increase of $2 million in selling, general and administrative expenses due to lower capitalized overhead as a result of reduced capital spending.

Interstate Transportation and Storage

   

Three Months EndedDecember 31,

2016     2015 Natural gas transported (MMBtu/d) 5,322,091 5,739,157 Natural gas sold (MMBtu/d) 17,190 18,665 Revenues $ 240 $ 258 Operating expenses, excluding non-cash compensation, amortization and accretion expenses (79 ) (83 ) Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (11 ) (9 ) Adjusted EBITDA related to unconsolidated affiliates 118 117 Other   1     —   Segment Adjusted EBITDA $ 269   $ 283     Distributions from unconsolidated affiliates $ 68 $ 75  

For the three months ended December 31, 2016 compared to the same period last year, transported volumes decreased 222,289 MMBtu/d on the Trunkline pipeline and 171,369 MMBtu/d in the West and San Juan areas on the Transwestern pipeline primarily due to lower utilization resulting from lower customer demand with declines in volumes on the Transwestern pipeline partially offset by opportunities in the Texas Intrastate markets. Transported volumes on the Tiger pipeline increased 127,974 MMBtu/d due to increased demand in the upper Midwest due to gas prices and weather.

For the three months ended December 31, 2016 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net effect of the following:

• a decrease of $11 million in revenues due to lower contracted capacity and rates on the Panhandle and Trunkline pipelines due to weak transportation spreads and lower contracted capacity on the Transwestern pipeline due to mild weather, a decrease of $9 million in revenues due to contract restructuring on the Tiger pipeline, and a decrease of $2 million on the Sea Robin pipeline due to declines in production and third party maintenance. These decreases were partially offset by higher reservation revenues on the Transwestern pipeline of $4 million from a growth project; partially offset by
• a decrease of $4 million in operating expenses primarily due to lower maintenance projects.

The decrease in cash distributions from unconsolidated affiliates is due to higher Citrus cash taxes.

Intrastate Transportation and Storage

   

Three Months EndedDecember 31,

2016     2015 Natural gas transported (MMBtu/d) 7,913,134 7,926,907 Revenues $ 756 $ 503 Cost of products sold   565     327   Gross margin 191 176 Unrealized gains on commodity risk management activities (5 ) (23 ) Operating expenses, excluding non-cash compensation expense (45 ) (42 ) Selling, general and administrative expenses, excluding non-cash compensation expense (5 ) (4 ) Adjusted EBITDA related to unconsolidated affiliates   16     15   Segment Adjusted EBITDA $ 152   $ 122    

For the three months ended December 31, 2016 compared to the same period last year, transported volumes decreased compared to the same period last year primarily due to lower production volumes, primarily in the Barnett Shale region, partially offset by increased volumes related to significant new long-term transportation contracts, as well as the addition of a new short-haul transport pipeline delivering volumes into our Houston Pipeline system.

For the three months ended December 31, 2016 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:

• an increase of $17 million (excluding unrealized losses of $9 million) due to higher realized gains from the buying and selling of gas along our system;
• an increase of $2 million from the sale of retained fuel as a fee along our system, primarily due to higher rates in the current period, which was partially offset by lower throughput volumes; and
• an increase of $11 million in storage margin (excluding unrealized losses of $8 million) due to the timing of withdrawals and sales of natural gas from our Bammel storage cavern.

Investment in Sunoco Logistics

   

Three Months EndedDecember 31,

2016     2015 Revenue $ 2,917 $ 2,305 Cost of products sold   2,542     2,067   Gross margin 375 238 Unrealized losses on commodity risk management activities 6 13 Operating expenses, excluding non-cash compensation expense (23 ) (42 ) Selling, general and administrative expenses, excluding non-cash compensation expense (24 ) (24 ) Inventory valuation adjustments (27 ) 118 Adjusted EBITDA related to unconsolidated affiliates   20     14   Segment Adjusted EBITDA $ 327   $ 317    

For the three months ended December 31, 2016 compared to the same period last year, Segment Adjusted EBITDA related to Sunoco Logistics increased due to the following:

• an increase of $30 million from Sunoco Logistics’ crude oil operations, primarily due to improved results from Sunoco Logistics’ crude oil pipelines which benefited from the Delaware Basin Extension and Permian Longview and Louisiana Extension pipelines that commenced operations in the third quarter 2016. Also contributing to the increase were higher contributions from Sunoco Logistics’ crude oil terminals, and increased earnings attributable to the acquisition from Vitol, Inc. and Sunoco Logistics’ joint venture interests. These positive factors were partially offset by lower operating results from Sunoco Logistics’ crude oil acquisition and marketing activities, which includes transportation and storage fees related to Sunoco Logistics’ crude oil pipelines and terminal facilities, resulting from lower crude oil differentials compared to the prior year period; and
• an increase of $2 million from Sunoco Logistics’ refined products operations, primarily due to improved operating results from Sunoco Logistics’ refined products pipelines which benefited from higher volumes on Sunoco Logistics’ Allegheny Access pipeline; offset by
• a decrease of $22 million from Sunoco Logistics’ NGL operations, primarily due to lower operating results from Sunoco Logistics’ NGLs acquisition and marketing activities driven by decreased volumes and margins. These factors were partially offset by increased volumes and fees from Sunoco Logistics’ Mariner NGLs projects, which includes Sunoco Logistics’ NGLs pipelines and Marcus Hook and Nederland facilities.

All Other

   

Three Months EndedDecember 31,

2016     2015 Revenue $ 750 $ 1,630 Cost of products sold   679     1,403   Gross margin 71 227 Unrealized (gains) losses on commodity risk management activities 7 (3 ) Operating expenses, excluding non-cash compensation expense (22 ) (116 ) Selling, general and administrative expenses, excluding non-cash compensation expense (26 ) (43 ) Adjusted EBITDA related to unconsolidated affiliates 77 74 Inventory valuation adjustments — 2 Other 24 24 Elimination   15     (13 ) Segment Adjusted EBITDA $ 146   $ 152     Distributions from unconsolidated affiliates $ 39 $ 85  

Amounts reflected in our all other segment primarily include:

• our retail marketing operations prior to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016;
• our equity method investment in limited partnership units of Sunoco LP consisting of 43.5 million units, representing 44.3% of Sunoco LP’s total outstanding common units;
• our natural gas marketing and compression operations;
• a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and
• our investment in Coal Handling, an entity that owns and operates end-user coal handling facilities.

Segment Adjusted EBITDA. For the three months ended December 31, 2016 compared to the same period last year, Segment Adjusted EBITDA decreased primarily due to the net impact of the following:

• a decrease of $156 million in gross margin primarily resulting from a decrease in revenue-generating horsepower and lower project revenue from our compression operations and unfavorable results from our natural resources operations. This decrease in margin was partially offset by a decrease in operating expenses of $94 million; and
• a decrease of $17 million in selling, general and administrative expenses resulting from lower transaction-related expenses.

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, 2016:

    Growth     Maintenance     Total Direct(1): Midstream $ 1,133 $ 122 $ 1,255 Liquids transportation and services(2) 2,296 20 2,316 Interstate transportation and storage(2) 191 89 280 Intrastate transportation and storage 53 23 76 All other (including eliminations)   93   51   144 Total direct capital expenditures 3,766 305 4,071 Indirect(1): Investment in Sunoco Logistics   1,676   63   1,739 Total capital expenditures $ 5,442 $ 368 $ 5,810

(1)

  Indirect capital expenditures comprise those funded by our publicly traded subsidiary; all other capital expenditures are reflected as direct capital expenditures.

(2)

Includes capital expenditures related to the Bakken, Rover and Bayou Bridge pipeline projects, which includes $572 million related to Sunoco Logistics’ proportionate ownership in the Bakken and Bayou Bridge projects. Capital expenditures include $961 million funded to the Bakken pipeline project by ETP and Sunoco Logistics under a promissory note, which amount was repaid to ETP and Sunoco Logistics in 2017.    

We currently expect capital expenditures for the full year 2017 to be within the following ranges:

    Growth       Maintenance Low     High Low     High Direct(1): Midstream $ 935 $ 985 $ 120 $ 130 Liquids transportation and services: NGL 370 390 20 25 Crude (2) 200 230 — 5 Interstate transportation and storage (2) 1,750 1,790 100 110 Intrastate transportation and storage 30 40 20 25 All other (including eliminations)   70     80     65   70 Total direct capital expenditures 3,355 3,515 325 365 Less: Project level non-recourse financing   (600 )   (600 )   —   — Partnership level capital funding $ 2,755   $ 2,915   $ 325 $ 365

(1)

 

Direct capital expenditures exclude those funded by our publicly traded subsidiary.

(2)

Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.      

SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES(In millions)(unaudited)

 

Three Months EndedDecember 31,

2016     2015 Equity in earnings (losses) of unconsolidated affiliates: Citrus $ 22 $ 20 FEP 13 14 PES (1 ) (25 ) MEP 9 12 HPC 8 8 AmeriGas (1 ) (5 ) Sunoco, LLC — 3 Sunoco LP(1) (265 ) 85 Other   14     (31 ) Total equity in earnings (losses) of unconsolidated affiliates $ (201 ) $ 81     Adjusted EBITDA related to unconsolidated affiliates(2): Citrus $ 78 $ 73 FEP 19 19 PES 8 (16 ) MEP 21 25 HPC 16 15 Sunoco, LLC — 38 Sunoco LP 63 56 Other   30     16   Total Adjusted EBITDA related to unconsolidated affiliates $ 235   $ 226     Distributions received from unconsolidated affiliates: Citrus $ 32 $ 37 FEP 18 18 PES — 42 MEP 18 20 HPC 13 11 AmeriGas 3 3 Sunoco LP 36 39 Other   17     12   Total distributions received from unconsolidated affiliates $ 137   $ 182  

(1)

  For the three months ended December 31, 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $277 million.

(2)

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.  

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Investor Relations:Energy TransferHelen Ryoo, Lyndsay Hannah or Brent Ratliff, 214-981-0795orMedia Relations:Granado Communications GroupVicki Granado, 214-599-8785Cell: 214-498-9272