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Energy Transfer Partners Reports First Quarter Results

DALLAS--(BUSINESS WIRE)--May 9, 2018-- Energy Transfer Partners, L.P. (NYSE: ETP) (“ETP” or the “Partnership”) today reported its financial results for the quarter ended March 31, 2018. For the three months ended March 31, 2018, net income was $879 million and Adjusted EBITDA was $1.88 billion. Adjusted EBITDA increased $436 million compared to the three months ended March 31, 2017, reflecting an increase of $277 million in Adjusted EBITDA from the crude oil transportation and services segment, as well as higher results from several of the other segments, as discussed in the segment results analysis below. Net income increased $486 million compared to the three months ended March 31, 2017, primarily due to increased operating income in addition to a $172 million pre-tax gain on Sunoco LP units that were repurchased by Sunoco LP from ETP in February 2018. Distributable Cash Flow attributable to partners, as adjusted, for the three months ended March 31, 2018 totaled $1.22 billion, an increase of $278 million compared to the three months ended March 31, 2017, primarily due to the increase in Adjusted EBITDA.

ETP’s other recent key accomplishments include the following:

  • In May 2018, ETP announced the formation of a joint venture to resume service on the Old Ocean natural gas pipeline and expand its jointly owned North Texas 36-inch pipeline that will provide more capacity from West Texas for deliveries into the Old Ocean Pipeline.
  • In May 2018, ETP announced the receipt of approval to place a portion of Phase 2 of the Rover pipeline in service, allowing for the full commercial operation capability of the Market Zone North Segment.
  • In April 2018, ETP completed the previously announced contribution transaction of certain compression assets to USA Compression Partners, LP for an aggregate consideration of $1.7 billion, consisting of $1.23 billion in cash and the remaining in equity.
  • In April 2018, ETP issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $450 million.
  • In April 2018, ETP announced a quarterly distribution of $0.565 per unit ($2.260 annualized) on ETP common units for the quarter ended March 31, 2018.
  • In March 2018, ETP announced the formation of a joint venture, Orbit Gulf Coast NGL Exports, LLC, with Satellite Petrochemical USA Corp. (“Satellite”), with the purpose of constructing a new export terminal on the United States Gulf Coast to provide ethane to Satellite for consumption at their ethane cracking facilities in China. Subject to Chinese Governmental approval, it is anticipated that the Orbit export terminal will be ready for commercial service in the fourth quarter of 2020.
  • In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased approximately 17.3 million Sunoco LP common units owned by ETP for proceeds of approximately $540 million.
  • As of March 31, 2018, ETP’s $5.00 billion revolving credit facilities had $2.76 billion of outstanding borrowings, and its leverage ratio, as defined by the credit agreement, was 3.89x.

An analysis of ETP’s segment results and other supplementary data is provided after the financial tables shown below. ETP has scheduled a conference call for 8:00 a.m. Central Time, Thursday, May 10, 2018 to discuss the first quarter 2018 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. Strategically positioned in all of the major U.S. production basins, ETP owns and operates a geographically diverse portfolio of complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (NGL) and refined product transportation and terminalling assets; NGL fractionation; and various acquisition and marketing assets. 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 that 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). ETE also owns Lake Charles LNG Company and the general partner of USA Compression Partners, LP (NYSE: USAC). On a consolidated basis, ETE’s family of companies owns and operates a diverse portfolio of natural gas, natural gas liquids, crude oil and refined products assets, as well as retail and wholesale motor fuel operations and LNG terminalling. For more information, visit the Energy Transfer Equity, L.P. website at www.energytransfer.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 SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(unaudited)

 
    March 31,     December 31,
2018 2017
ASSETS
 
Current assets $ 5,748 $ 6,528
 
Property, plant and equipment, net 59,373 58,437
 
Advances to and investments in unconsolidated affiliates 3,258 3,816
Other non-current assets, net 758 758
Intangible assets, net 5,243 5,311
Goodwill   3,115   3,115
Total assets $ 77,495 $ 77,965
 
LIABILITIES AND EQUITY
 
Current liabilities $ 6,223 $ 6,994
 
Long-term debt, less current maturities 33,109 32,687
Non-current derivative liabilities 97 145
Deferred income taxes 2,860 2,883
Other non-current liabilities 1,100 1,084
 
Commitments and contingencies
Redeemable noncontrolling interests 21 21
 
Equity:
Total partners’ capital 27,999 28,269
Noncontrolling interest   6,086   5,882
Total equity   34,085   34,151
Total liabilities and equity $ 77,495 $ 77,965
 
 

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit data)

(unaudited)

 
    Three Months Ended
March 31,
2018    

2017 (a)

REVENUES $ 8,280 $ 6,895
COSTS AND EXPENSES:
Cost of products sold 5,988 5,050
Operating expenses 604 492
Depreciation, depletion and amortization 603 560
Selling, general and administrative   112     110  
Total costs and expenses   7,307     6,212  
OPERATING INCOME 973 683
OTHER INCOME (EXPENSE):
Interest expense, net (346 ) (332 )
Equity in earnings (losses) of unconsolidated affiliates (72 ) 73
Gain on Sunoco LP common unit repurchase 172
Gains on interest rate derivatives 52 5
Other, net   60     19  
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 839 448
Income tax expense (benefit)   (40 )   55  
NET INCOME 879 393
Less: Net income attributable to noncontrolling interest   164     62  
NET INCOME ATTRIBUTABLE TO PARTNERS 715 331
General Partner’s interest in net income 402 206
Series A Preferred Unitholders’ interest in net income 15
Series B Preferred Unitholders’ interest in net income 9
Class H Unitholder’s interest in net income       93  
Common Unitholders’ interest in net income $ 289   $ 32  
NET INCOME PER COMMON UNIT:
Basic $ 0.24 $ 0.03
Diluted $ 0.24 $ 0.03
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
Basic 1,163.8 822.3
Diluted 1,167.8 824.5
(a)   During the fourth quarter of 2017, the Partnership changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories associated with the legacy Sunoco Logistics business were changed from the LIFO method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported. Certain other prior period amounts have also been reclassified to conform to the current period presentation, including a reclassification between capitalized interest and AFUDC from the three months ended March 31, 2017.
 
 

SUPPLEMENTAL INFORMATION

(Dollars and units in millions)

(unaudited)

 
    Three Months Ended
March 31,
2018    

2017 (a)(b)

Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (c):
Net income $ 879 $ 393
Interest expense, net 346 332
Income tax expense (benefit) (40 ) 55
Depreciation, depletion and amortization 603 560
Non-cash compensation expense 20 23
Gains on interest rate derivatives (52 ) (5 )
Unrealized (gains) losses on commodity risk management activities 87 (64 )
Gain on Sunoco LP common unit repurchase (172 )
Equity in (earnings) losses of unconsolidated affiliates 72 (73 )
Adjusted EBITDA related to unconsolidated affiliates 185 239
Other, net   (47 )   (15 )
Adjusted EBITDA (consolidated) 1,881 1,445
Adjusted EBITDA related to unconsolidated affiliates (185 ) (239 )
Distributable cash flow from unconsolidated affiliates 125 144
Interest expense, net (346 ) (332 )
Preferred unitholders’ distributions (24 )
Current income tax expense (1 )
Maintenance capital expenditures (88 ) (60 )
Other, net   3     15  
Distributable Cash Flow (consolidated) 1,366 972
Distributable Cash Flow attributable to PennTex Midstream Partners, LP (“PennTex”) (100%) (d) (19 )
Distributions from PennTex to ETP (d) 8
Distributable cash flow attributable to noncontrolling interest in other consolidated subsidiaries   (147 )   (23 )
Distributable Cash Flow attributable to the partners of ETP 1,219 938
Transaction-related expenses   4     7  
Distributable Cash Flow attributable to the partners of ETP, as adjusted $ 1,223   $ 945  
 
Distributions to partners:
Limited Partners:
Common Units held by public $ 642 $ 567
Common Units held by parent 16 15
General Partner interests and Incentive Distribution Rights (“IDRs”) held by parent 449 381
IDR relinquishments   (42 )   (157 )
Total distributions to be paid to partners $ 1,065   $ 806  
Common Units outstanding – end of period (e)   1,164.0     1,084.6  
Distribution coverage ratio (f) 1.15x 1.17x

(a) For the three months ended March 31, 2017, the calculation of Distributable Cash Flow and the amounts reflected for distributions to partners and common units outstanding reflect the pro forma impacts of the Sunoco Logistics Merger as though the merger had occurred on January 1, 2017. As a result, the prior period amounts reported above differ from information previously reported by legacy ETP, as follows:

  • Distributable cash flow attributable to the partners of ETP includes amounts attributable to the partners of both legacy ETP and legacy Sunoco Logistics. Previously, the calculation of distributable cash flow attributable to the partners of ETP (as previously reported by legacy ETP) excluded the distributable cash flow attributable to Sunoco Logistics and only included distributions from legacy Sunoco Logistics to legacy ETP.
  • Distributable cash flow attributable to noncontrolling interest in other consolidated subsidiaries includes amounts attributable to the noncontrolling interests in the other consolidated subsidiaries of both legacy ETP and legacy Sunoco Logistics.
  • The transaction-related expenses adjustment in distributable cash flow attributable to the partners of ETP, as adjusted, includes amounts incurred by both legacy ETP and legacy Sunoco Logistics.
  • Distributions to limited partners include distributions paid on the common units of both legacy ETP and legacy Sunoco Logistics but exclude the following distributions in the prior periods on units that were cancelled in the merger, which comprise the following: (i) distributions paid by legacy Sunoco Logistics on its common units held legacy ETP and (ii) distributions paid by legacy ETP on its Class H units held by ETE.
  • Distributions on General Partner interests and incentive distribution rights are reflected on a pro forma basis, based on the pro forma cash distributions to limited partners and the current distribution waterfall per the limited partnership agreement (i.e., the legacy Sunoco Logistics distribution waterfall).
  • Common units outstanding for the pre-merger periods reflect (i) the legacy ETP common units outstanding at the end of the period multiplied by a factor of 1.5x and (ii) the legacy Sunoco Logistics common units outstanding at the end of the period minus 67.1 million legacy Sunoco Logistics common units held by ETP, which were cancelled in connection with the closing of the merger.

(b) During the fourth quarter of 2017, the Partnership changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories associated with the legacy Sunoco Logistics business were changed from the LIFO method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported. Certain other prior period amounts have also been reclassified to conform to the current period presentation, including a reclassification between capitalized interest and AFUDC from the three months ended March 31, 2017.

(c) 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 segment margin, operating income, net income, and cash flow from operating activities.

Definition of Adjusted EBITDA

We define 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. 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 our 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

We define 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, amortization included in interest 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 our subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to our partners, we have reported Distributable Cash Flow attributable to partners, 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 our partners 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 partners is net of distributions to be paid by the subsidiary to the noncontrolling interests.

For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related and non-recurring expenses that are included in net income are excluded.

(d) Beginning with the second quarter of 2017, PennTex became a wholly-owned subsidiary of ETP. The amounts reflected above for PennTex relate only to the first quarter of 2017, and no distributable cash flow has been attributed to noncontrolling interests in PennTex subsequent to March 31, 2017.

(e) For the three months ended March 31, 2017, reflects the sum of (i) the ETP Common Units outstanding at the end of period multiplied by a factor of 1.5x and (ii) the Sunoco Logistics Common Units outstanding at end of period minus 67.1 million Sunoco Logistics Common Units held by ETP, which units were cancelled in connection with the closing of the merger.

(f) Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to partners, 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)

 
    Three Months Ended
March 31,
2018     2017
Segment Adjusted EBITDA:
Intrastate transportation and storage $ 192 $ 169
Interstate transportation and storage 323 265
Midstream 377 320
NGL and refined products transportation and services (1) 451 381
Crude oil transportation and services (1) 464 187
All other   74   123
$ 1,881 $ 1,445

(1)

 

Subsequent to the Sunoco Logistics Merger, the Partnership’s reportable segments were revised. Amounts reflected in prior periods have been retrospectively adjusted to conform to the current reportable segment presentation for NGL and refined products transportation and services and crude oil transportation and services.

 

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment Margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment Margin is similar to the GAAP measure of gross margin, except that Segment Margin excludes charges for depreciation, depletion and amortization.

In addition, for certain segments, the sections below include information on the components of Segment Margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of Segment Margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of Segment Margin are calculated consistent with the calculation of Segment Margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.

Following is a reconciliation of segment margin to operating income, as reported in the Partnership’s consolidated statements of operations:

   
Three Months Ended
March 31,
  2018         2017  
Intrastate transportation and storage $ 171 $ 182
Interstate transportation and storage 316 235
Midstream 553 513
NGL and refined products transportation and services 600 559
Crude oil transportation and services 568 272
All other 95 102
Intersegment eliminations   (11 )   (18 )
Total segment margin 2,292 1,845
 
Less:
Operating expenses 604 492
Depreciation, depletion and amortization 603 560
Selling, general and administrative   112     110  
Operating income $ 973   $ 683  
 
 

Intrastate Transportation and Storage

   
Three Months Ended
March 31,
  2018         2017  
Natural gas transported (BBtu/d) 9,271 7,870
Withdrawals from storage natural gas inventory (BBtu) 17,703 23,093
Revenues $ 875 $ 816
Cost of products sold   704     634  
Segment margin 171 182
Unrealized losses on commodity risk management activities 53 15
Operating expenses, excluding non-cash compensation expense (39 ) (38 )
Selling, general and administrative expenses, excluding non-cash compensation expense (6 ) (6 )
Adjusted EBITDA related to unconsolidated affiliates   13     16  
Segment Adjusted EBITDA $ 192   $ 169  
 

Transported volumes increased primarily due to higher demand for exports to Mexico, the addition of new pipelines and more favorable market pricing.

Segment Adjusted EBITDA. For the three months ended March 31, 2018 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 $58 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; offset by
  • a decrease of $24 million in realized storage margin primarily due to an adjustment to the Bammel storage inventory;
  • a decrease of $7 million in transportation fees due to renegotiated contracts resulting in lower billed volumes;
  • an increase of $1 million in operating expenses primarily due to higher expense projects; and
  • a decrease of $3 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a decrease of $3 million from lower demand volumes related to renegotiation of a contract and a decrease of $3 million due to a reserve recorded in the prior period pursuant to the bankruptcy filing of a transport customer, partially offset by an increase of $3 million related to two new joint venture pipelines placed in service in 2017.

Interstate Transportation and Storage

   
Three Months Ended
March 31,
  2018         2017  
Natural gas transported (BBtu/d) 8,204 5,656
Natural gas sold (BBtu/d) 17 17
Revenues $ 316 $ 235
Operating expenses, excluding non-cash compensation, amortization and accretion expenses (94 ) (74 )
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (17 ) (12 )
Adjusted EBITDA related to unconsolidated affiliates 116 115
Other   2     1  
Segment Adjusted EBITDA $ 323   $ 265  
 

Transported volumes reflected an increase of 1,470 BBtu/d as a result of the partial in service of the Rover pipeline, an increase of 444 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale and deliveries into third party storage and the intrastate markets, and an increase of 402 BBtu/d and 229 BBtu/d on the Panhandle and Trunkline pipelines, respectively, resulting from higher demand due to colder weather.

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net effect of the following:

  • an increase of $49 million due to the partial in service of the Rover pipeline which reflected increases of $82 million in revenues, $26 million in operating expenses and $7 million in general and administrative expenses;
  • a decrease of $6 million in operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to lower allocated costs, reduction in project maintenance work and lower transportation and storage related expenses; and
  • a decrease of $2 million in general and administrative expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to lower allocated costs and insurance reserves.

Midstream

   
Three Months Ended
March 31,
  2018         2017  
Gathered volumes (BBtu/d) 11,306 10,232
NGLs produced (MBbls/d) 503 445
Equity NGLs (MBbls/d) 28 26
Revenues $ 1,614 $ 1,637
Cost of products sold   1,061     1,124  
Segment margin 553 513
Unrealized gains on commodity risk management activities (16 )
Operating expenses, excluding non-cash compensation expense (164 ) (161 )
Selling, general and administrative expenses, excluding non-cash compensation expense (20 ) (23 )
Adjusted EBITDA related to unconsolidated affiliates 7 7
Other   1      
Segment Adjusted EBITDA $ 377   $ 320  
 

Gathered volumes and NGL production increased primarily due to increases in the Permian and Northeast regions, partially offset by basin declines in the Ark-La-Tex, North Texas and Mid-Continent/Panhandle regions.

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net effects of the following:

  • an increase of $27 million in non fee-based margin due to increased throughput volumes in the Permian and South Texas regions;
  • an increase of $16 million in non fee-based margin due to an $11 million increase resulting from higher crude and NGL prices and a $5 million increase in settled price risk management activity;
  • an increase of $13 million in fee-based revenue due to growth in the Permian and Northeast regions, offset by declines in Ark-La-Tex, North Texas and the Mid-Continent/Panhandle regions; and
  • a decrease of $3 million in selling, general and administrative expenses due to lower employee costs and professional fees; offset by
  • an increase of $3 million in operating expenses primarily due to an increase of $2 million in employee costs and an increase of $1 million in ad valorem taxes.

NGL and Refined Products Transportation and Services

   
Three Months Ended
March 31,
  2018         2017  
NGL transportation volumes (MBbls/d) 936 816
Refined products transportation volumes (MBbls/d) 620 624
NGL and refined products terminal volumes (MBbls/d) 702 790
NGL fractionation volumes (MBbls/d) 472 433
Revenues $ 2,546 $ 2,266
Cost of products sold   1,946     1,707  
Segment margin 600 559
Unrealized gains on commodity risk management activities (13 ) (50 )
Operating expenses, excluding non-cash compensation expense (139 ) (127 )
Selling, general and administrative expenses, excluding non-cash compensation expense (18 ) (19 )
Adjusted EBITDA related to unconsolidated affiliates 21 17
Other       1  
Segment Adjusted EBITDA $ 451   $ 381  
 

NGL transportation volumes increased primarily from the Permian region, Mariner West pipeline and Mariner South pipeline, partially offset by decreased throughput volumes on Mariner East I due to system downtime in March 2018. Refined products transportation volumes decreased slightly primarily due to lower throughput volumes from the Midwest and Northeast regions, partially offset by increased throughput volumes from the Southwest region.

NGL and refined products terminal volumes decreased primarily due to the sale of one of our refined product marketing terminals in April 2017, lower volumes loaded for export at our Nederland terminal and lower throughput volumes at our Marcus Hook Industrial Complex due to system downtime on our Mariner East I pipeline in March 2018.

Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased 11% primarily due to increased volumes from Permian producers.

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to net impact of the following:

  • an increase of $33 million in transportation margin due to a $33 million increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines and a $6 million increase due to higher throughput on Mariner West driven by end user facility constraints in the prior period. These increases were offset by a $6 million decrease resulting from lower throughput on Mariner East I due to system downtime in March 2018;
  • an increase of $25 million in marketing margin due to gains of $9 million from optimizing sales of purity product from our Mont Belvieu fractionators, as well as an $8 million increase from our butane blending operations and an $8 million increase from sales of domestic propane and other products at our Marcus Hook Industrial Complex;
  • an increase of $14 million in fractionation and refinery services margin primarily due to an $8 million increase resulting from higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility and a $7 million increase from blending gains as a result of improved market pricing;
  • an increase of $7 million in terminal services margin due to a $10 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018. This increase was offset by a $3 million decrease from our marketing terminal volumes primarily due to the sale of one of our terminals in April 2017; and
  • an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to annual true-up payments from one of our unconsolidated refined product pipelines recorded in January 2018; offset by
  • an increase of $12 million in operating expenses primarily due to a change in the classification of certain customer reimbursements previously recorded in operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018.

Crude Oil Transportation and Services

   
Three Months Ended
March 31,
  2018         2017  
Crude transportation volumes (MBbls/d) 3,827 3,042
Crude terminals volumes (MBbls/d) 1,940 1,777
Revenues $ 3,745 $ 2,575
Cost of products sold   3,177     2,303  
Segment margin 568 272
Unrealized losses on commodity risk management activities 43
Operating expenses, excluding non-cash compensation expense (127 ) (72 )
Selling, general and administrative expenses, excluding non-cash compensation expense (22 ) (17 )
Adjusted EBITDA related to unconsolidated affiliates   2     4  
Segment Adjusted EBITDA $ 464   $ 187  
 

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the following:

  • an increase of $339 million in segment margin (excluding unrealized losses on commodity risk management activities) due to a $222 million increase resulting primarily from placing our Bakken pipeline in service in the second quarter of 2017 as well as a $25 million increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets; an $85 million increase (excluding $43 million in unrealized losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets; and a $7 million increase from higher ship loading and throughput fees at our Nederland terminal due to an increase in exports; offset by
  • an increase of $55 million in operating expenses primarily due to a $26 million increase resulting from placing our Bakken pipeline in service in the second quarter of 2017; a $12 million increase resulting from the addition of certain joint venture crude transportation assets in the second quarter of 2017; and a $15 million increase from existing transportation assets mainly due to higher ad valorem taxes, management fees and pipeline loss allowance; and
  • an increase of $5 million in selling, general and administrative expenses due primarily to insurance and Bakken management fees.

All Other

   
Three Months Ended
March 31,
  2018         2017  
Revenues $ 571 $ 770
Cost of products sold   476     668  
Segment margin 95 102
Unrealized (gains) losses on commodity risk management activities 4 (13 )
Operating expenses, excluding non-cash compensation expense (31 ) (21 )
Selling, general and administrative expenses, excluding non-cash compensation expense (18 ) (21 )
Adjusted EBITDA related to unconsolidated affiliates 26 80
Other and eliminations   (2 )   (4 )
Segment Adjusted EBITDA $ 74   $ 123  
 

Amounts reflected in our all other segment primarily include:

  • our equity method investment in limited partnership units of Sunoco LP consisting of 26.2 million and 43.5 million units, representing 31.8% and 43.7% of Sunoco LP’s total outstanding common units as of March 31, 2018 and March 31, 2017, respectively;
  • 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 facilities.

Segment Adjusted EBITDA. For the three months ended March 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased primarily due to the net impact of the following:

  • a decrease of $54 million in Adjusted EBITDA related to unconsolidated affiliates, primarily reflecting a decrease of $30 million from our investment in PES due to lower earnings and a decrease of $25 million from our investment in Sunoco LP primarily due to Sunoco LP’s sale of retail assets, as well as a decrease in our ownership interest in Sunoco LP subsequent to the repurchase of common units by Sunoco LP in February 2018;
  • an increase of $10 million in operating expenses primarily attributable to an increase of $8 million in the compression business; offset by
  • an increase of $11 million from commodity trading activities; and
  • a decrease of $3 million in selling, general and administrative expenses due to lower merger and acquisition costs.
 
 

SUPPLEMENTAL INFORMATION ON LIQUIDITY

(In millions)

(unaudited)

 
        Funds Available at    
Facility Size March 31, 2018 Maturity Date
ETP Five-Year Revolving Credit Facility $ 4,000 $ 1,089 December 1, 2022
ETP 364-Day Revolving Credit Facility   1,000   1,000 November 30, 2018
$ 5,000 $ 2,089
 
 

SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES

(In millions)

(unaudited)

 
    Three Months Ended
March 31,
2018     2017
Equity in earnings (losses) of unconsolidated affiliates:
Citrus $ 27 $ 21
FEP 14 12
MEP 9 10
HPC 3 7
Sunoco LP (151) (14)
Other   26   37
Total equity in earnings (losses) of unconsolidated affiliates $ (72) $ 73
 
Adjusted EBITDA related to unconsolidated affiliates:
Citrus $ 75 $ 75
FEP 19 18
MEP 22 22
HPC 9 15
Sunoco LP 29 54
Other   31   55
Total Adjusted EBITDA related to unconsolidated affiliates $ 185 $ 239
 
Distributions received from unconsolidated affiliates:
Citrus $ 46 $ 41
FEP 17
MEP 13 73
Sunoco LP 36 35
Other   21   23
Total distributions received from unconsolidated affiliates $ 133 $ 172
 

Source: Energy Transfer Partners, L.P.

Energy Transfer
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Lyndsay Hannah, Brent Ratliff, Helen Ryoo, 214-981-0795
or
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