EX-99.1 2 ex991eterq22019.htm EXHIBIT 99.1 Exhibit


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ENERGY TRANSFER REPORTS SECOND QUARTER 2019 RESULTS
•
Net income attributable to partners of $878 million, reflecting an increase over previous period primarily due to higher operating income and the impact of the simplification transaction.
•
Record Adjusted EBITDA of $2.82 billion, up 25 percent from the second quarter of 2018.
•
Distributable Cash Flow attributable to partners of $1.60 billion, up 23 percent from the second quarter of 2018.
•
Distribution coverage ratio of 2.00x, yielding excess coverage of $800 million of Distributable Cash Flow attributable to partners in excess of distributions.
•
Increases 2019 outlook for Adjusted EBITDA to approximately $10.8 billion to $11.0 billion and reduces capital expenditures to approximately $4.6 billion to $4.8 billion.
Dallas - August 7, 2019 - Energy Transfer LP (NYSE:ET) (“ET” or the “Partnership”) today reported financial results for the quarter ended June 30, 2019.
ET reported net income attributable to partners for the three months ended June 30, 2019 of $878 million, an increase of $523 million compared to the three months ended June 30, 2018. For the prior period, net income attributable to partners continues to reflect only the amount of net income attributable to the legacy Energy Transfer LP partners prior to the simplification merger transaction of ET and Energy Transfer Operating, L.P. (“ETO”) on October 19, 2018 (the “Merger”).
Adjusted EBITDA for the three months ended June 30, 2019 was $2.82 billion, an increase of $562 million compared to the three months ended June 30, 2018. Results were supported by significant increases in four of the Partnership’s five core segments, with record operating performance in the Partnership’s NGL and refined products segment.
Distributable Cash Flow attributable to partners, as adjusted, for the three months ended June 30, 2019 was $1.60 billion, an increase of $301 million compared to the three months ended June 30, 2018. The increase was primarily due to the increase in Adjusted EBITDA.
Key accomplishments and current developments:
Operational
•
ET announces its eighth natural gas liquids (NGL) fractionation facility at Mont Belvieu, Texas.  Fractionator VIII will be a 150,000 barrel per day fractionator that is scheduled to be in service in the second quarter of 2021. With the addition of Fractionator VIII, ET will have more than one million barrels per day of fractionation capacity at Mont Belvieu.
•
ET announced a binding supplemental open season in July 2019 to solicit additional shipper commitments that would further support a capacity optimization on the Bakken pipeline system.
•
The Permian Express 4 expansion is ongoing, and ET expects to have the project, which adds 120,000 barrels per day of capacity from the Permian Basin to Gulf Coast markets, in-service by the end of the third quarter of 2019.
•
ET and Sunoco LP closed on the JC Nolan Pipeline joint venture in July 2019 and successfully commissioned the diesel fuel pipeline in West Texas this week.
•
Construction is ongoing at ET’s ethane storage tank and chilling facilities in Nederland, Texas with an expected in-service date in the fourth quarter of 2020.
Strategic
•
ET opened an office in Beijing in April and continues to expand its international marketing efforts to meet growing demand for LNG and NGL products.
Financial
•
In July 2019, ET announced a quarterly distribution of $0.305 per unit ($1.220 annualized) on ET common units for the quarter ended June 30, 2019. The distribution coverage ratio for the second quarter of 2019 is 2.00x.
•
As of June 30, 2019, ETO’s $6.00 billion revolving credit facilities had an aggregate $3.56 billion of available capacity, and ETO’s leverage ratio, as defined by its credit agreement, was 3.61x.

1


ET benefits from a portfolio of assets with exceptional product and geographic diversity. The Partnership’s multiple segments generate high-quality, balanced earnings with no single segment contributing more than 30 percent of the Partnership’s consolidated Adjusted EBITDA for the three months ended June 30, 2019. The great majority of the Partnership’s segment margins are fee-based and therefore have limited commodity price sensitivity.
Conference Call information:
The Partnership has scheduled a conference call for 8:00 a.m. Central Time, Thursday, August 8, 2019 to discuss its second quarter 2019 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 the Partnership’s website for a limited time.
Energy Transfer LP (NYSE: ET) owns and operates one of the largest and most diversified portfolios of energy assets in the United States, with a strategic footprint in all of the major domestic production basins. ET is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, NGL and refined product transportation and terminalling assets; NGL fractionation; and various acquisition and marketing assets.  ET, through its ownership of Energy Transfer Operating, L.P., also owns Lake Charles LNG Company, as well as the general partner interests, the incentive distribution rights and 28.5 million common units of Sunoco LP (NYSE: SUN), and the general partner interests and 46.1 million common units of USA Compression Partners, LP (NYSE: USAC). For more information, visit the Energy Transfer LP website at www.energytransfer.com.
Sunoco LP (NYSE: SUN) is a master limited partnership with core operations that include the distribution of motor fuel to approximately 10,000 convenience stores, independent dealers, commercial customers and distributors located in more than 30 states, as well as refined product transportation and terminalling assets. SUN’s general partner is owned by Energy Transfer Operating, L.P., a subsidiary of Energy Transfer LP (NYSE: ET). For more information, visit the Sunoco LP website at www.sunocolp.com.
USA Compression Partners, LP (NYSE: USAC) is a growth-oriented Delaware limited partnership that is one of the nation’s largest independent providers of compression services in terms of total compression fleet horsepower. USAC partners with a broad customer base composed of producers, processors, gatherers and transporters of natural gas and crude oil. USAC focuses on providing compression services to infrastructure applications primarily in high-volume gathering systems, processing facilities and transportation applications. For more information, visit the USAC website at www.usacompression.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.
Contacts
Energy Transfer
Investor Relations:
Bill Baerg, Brent Ratliff, Lyndsay Hannah, 214-981-0795
or
Media Relations:
Vicki Granado, 214-840-5820

2


ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(unaudited)
 
June 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
$
7,198

 
$
6,750

 
 
 
 
Property, plant and equipment, net
68,187

 
66,963

 
 
 
 
Advances to and investments in unconsolidated affiliates
2,838

 
2,642

Lease right-of-use assets, net (a)
853

 
—

Other non-current assets, net
1,026

 
1,006

Intangible assets, net
5,827

 
6,000

Goodwill
4,883

 
4,885

Total assets
$
90,812

 
$
88,246

LIABILITIES AND EQUITY
 
 
 
Current liabilities
$
6,429

 
$
9,310

 
 
 
 
Long-term debt, less current maturities
46,499

 
43,373

Non-current derivative liabilities
354

 
104

Non-current operating lease liabilities (a)
803

 
—

Deferred income taxes
3,071

 
2,926

Other non-current liabilities
1,139

 
1,184

 
 
 
 
Commitments and contingencies
 
 
 
Redeemable noncontrolling interests
500

 
499

 
 
 
 
Equity:
 
 
 
Total partners’ capital
20,834

 
20,559

Noncontrolling interests
11,183

 
10,291

Total equity
32,017

 
30,850

Total liabilities and equity
$
90,812

 
$
88,246

(a)
Lease-related balances as of June 30, 2019 were recorded in connection with the required adoption of the new lease accounting principles (referred to as ASC 842) on January 1, 2019.


3


ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
REVENUES
$
13,877

 
$
14,118

 
$
26,998

 
$
26,000

COSTS AND EXPENSES:
 
 
 
 
 
 
 
Cost of products sold
10,302

 
11,343

 
19,717

 
20,588

Operating expenses
792

 
772

 
1,600

 
1,496

Depreciation, depletion and amortization
785

 
694

 
1,559

 
1,359

Selling, general and administrative
179

 
183

 
326

 
331

Impairment losses
—

 
—

 
50

 
—

Total costs and expenses
12,058

 
12,992

 
23,252

 
23,774

OPERATING INCOME
1,819

 
1,126

 
3,746

 
2,226

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest expense, net of interest capitalized
(578
)
 
(510
)
 
(1,168
)
 
(976
)
Equity in earnings of unconsolidated affiliates
77

 
92

 
142

 
171

Losses on extinguishments of debt
—

 
—

 
(18
)
 
(106
)
Gains (losses) on interest rate derivatives
(122
)
 
20

 
(196
)
 
72

Other, net
46

 
(1
)
 
42

 
56

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE
1,242

 
727

 
2,548

 
1,443

Income tax expense from continuing operations
34

 
68

 
160

 
58

INCOME FROM CONTINUING OPERATIONS
1,208

 
659

 
2,388

 
1,385

Loss from discontinued operations, net of income taxes
—

 
(26
)
 
—

 
(263
)
NET INCOME
1,208

 
633

 
2,388

 
1,122

Less: Net income attributable to noncontrolling interests
317

 
278

 
614

 
404

Less: Net income attributable to redeemable noncontrolling interests
13

 
—

 
26

 
—

NET INCOME ATTRIBUTABLE TO PARTNERS
878

 
355

 
1,748

 
718

Series A Convertible Preferred Unitholders’ interest in income
—

 
12

 
—

 
33

General Partner’s interest in net income
1

 
1

 
2

 
2

Limited Partners’ interest in net income
$
877

 
$
342

 
$
1,746

 
$
683

NET INCOME PER LIMITED PARTNER UNIT:
 
 
 
 
 
 
 
Basic
$
0.33

 
$
0.31

 
$
0.67

 
$
0.62

Diluted
$
0.33

 
$
0.31

 
$
0.66

 
$
0.62

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING:
 
 
 
 
 
 
 
Basic
2,621.2

 
1,114.8

 
2,620.3

 
1,097.1

Diluted
2,631.0

 
1,158.2

 
2,630.1

 
1,158.2


4


ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
(Dollars and units in millions)
(unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2019
 
2018
 
2019
 
2018
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (b):
 
 
 
 
 
 
 
Net income
$
1,208

 
$
633

 
$
2,388

 
$
1,122

Loss from discontinued operations
—

 
26

 
—

 
263

Interest expense, net of capitalized interest
578

 
510

 
1,168

 
976

Impairment losses
—

 
—

 
50

 
—

Income tax expense from continuing operations
34

 
68

 
160

 
58

Depreciation, depletion and amortization
785

 
694

 
1,559

 
1,359

Non-cash compensation expense
29

 
32

 
58

 
55

Losses (gains) on interest rate derivatives
122

 
(20
)
 
196

 
(72
)
Unrealized losses (gains) on commodity risk management activities
23

 
265

 
(26
)
 
352

Losses on extinguishments of debt
—

 
—

 
18

 
106

Inventory valuation adjustments
(4
)
 
(32
)
 
(97
)
 
(57
)
Equity in earnings of unconsolidated affiliates
(77
)
 
(92
)
 
(142
)
 
(171
)
Adjusted EBITDA related to unconsolidated affiliates
163

 
168

 
309

 
324

Adjusted EBITDA from discontinued operations
—

 
(5
)
 
—

 
(25
)
Other, net
(37
)
 
15

 
(20
)
 
(26
)
Adjusted EBITDA (consolidated)
2,824

 
2,262

 
5,621

 
4,264

Adjusted EBITDA related to unconsolidated affiliates
(163
)
 
(168
)
 
(309
)
 
(324
)
Distributable cash flow from unconsolidated affiliates
107

 
99

 
200

 
203

Interest expense, net of capitalized interest
(578
)
 
(510
)
 
(1,168
)
 
(978
)
Preferred unitholders’ distributions
(64
)
 
(41
)
 
(117
)
 
(65
)
Current income tax (expense) benefit
7

 
27

 
(21
)
 
(441
)
Transaction-related income taxes
—

 
(10
)
 
—

 
470

Maintenance capital expenditures
(170
)
 
(126
)
 
(262
)
 
(217
)
Other, net
19

 
7

 
37

 
14

Distributable Cash Flow (consolidated)
1,982

 
1,540

 
3,981

 
2,926

Distributable Cash Flow attributable to Sunoco LP (100%)
(101
)
 
(99
)
 
(198
)
 
(183
)
Distributions from Sunoco LP
41

 
41

 
82

 
82

Distributable Cash Flow attributable to USAC (100%)
(54
)
 
(46
)
 
(109
)
 
(46
)
Distributions from USAC
21

 
31

 
42

 
31

Distributable Cash Flow attributable to noncontrolling interests in other non-wholly-owned consolidated subsidiaries
(293
)
 
(181
)
 
(544
)
 
(328
)
Distributable Cash Flow attributable to the partners of ET – pro forma for the Merger (a)
1,596

 
1,286

 
3,254

 
2,482

Transaction-related adjustments
5

 
14

 
3

 
13

Distributable Cash Flow attributable to the partners of ET, as adjusted – pro forma for the Merger (a)
$
1,601

 
$
1,300

 
$
3,257

 
$
2,495

 
 
 
 
 
 
 
 
Distributions to partners – pro forma for the Merger (a):
 
 
 
 
 
 
 
Limited Partners (c)
$
800

 
$
798

 
$
1,599

 
$
1,507

General Partner
1

 
1

 
2

 
2

Total distributions to be paid to partners
$
801

 
$
799

 
$
1,601

 
$
1,509

Common Units outstanding – end of period – pro forma for the Merger (a)
2,623.2

 
2,616.0

 
2,623.2

 
2,616.0

Distribution coverage ratio – pro forma for the Merger (a)
2.00x

 
1.63x

 
2.03x

 
1.65x


5


(a)
The closing of the Merger has impacted the Partnership’s calculation of Distributable Cash Flow attributable to partners, as well as the number of ET Common Units outstanding and the amount of distributions to be paid to partners for the three and six months ended June 30, 2018. In order to provide information on a comparable basis for pre-Merger and post-Merger periods, the Partnership has included certain pro forma information for the three and six months ended June 30, 2018.
Pro forma Distributable Cash Flow attributable to partners reflects the following merger related impacts:
•
ETO is reflected as a wholly-owned subsidiary and pro forma Distributable Cash Flow attributable to partners reflects ETO’s consolidated Distributable Cash Flow (less certain other adjustments);
•
Distributions from Sunoco LP and USAC include distributions to both ET and ETO; and
•
Distributable Cash Flow attributable to noncontrolling interests in our other non-wholly-owned subsidiaries is subtracted from consolidated Distributable Cash Flow to calculate Distributable Cash Flow attributable to partners.
Pro forma distributions to partners include actual distributions to legacy ET partners, as well as pro forma distributions to legacy ETO partners. Pro forma distributions to ETO partners are calculated assuming (i) historical ETO common units converted under the terms of the Merger and (ii) distributions on such converted common units were paid at the historical rate paid on ET Common Units.
Pro forma Common Units outstanding include actual Common Units outstanding, in addition to Common Units assumed to be issued in the Merger, which are based on historical ETO common units converted under the terms of the Merger.
(b)
Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio are non-GAAP financial measures used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of ET’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, Distributable Cash Flow and distribution coverage ratio, 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, Distributable Cash Flow and distribution coverage ratio 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, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. 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 distributions to preferred unitholders and 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, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and deferred income taxes. 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.

6


On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ET’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, other than ETO, 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 subsidiaries, but Distributable Cash Flow attributable to partners reflects only the amount of Distributable Cash Flow of such subsidiaries that is attributable to our ownership interest.
For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related adjustments and non-recurring expenses that are included in net income are excluded.
Definition of Distribution Coverage Ratio
Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to partners, as adjusted, divided by distributions expected to be paid to the partners of ET in respect of such period.
(c)
The amounts reflected for the six months ended June 30, 2018 includes distributions to unitholders who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units and reinvest those distributions in ETE Series A convertible preferred units representing limited partner interests in the Partnership for the six months ended June 30, 2018. The quarter ended March 31, 2018 was the final quarter of participation in the plan.

7


ENERGY TRANSFER LP AND SUBSIDIARIES
SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)
As a result of the Merger in October 2018, our reportable segments were reevaluated during the quarter ended December 31, 2018 and currently reflect the following segments.
 
Three Months Ended
June 30,
 
2019
 
2018
Segment Adjusted EBITDA:
 
 
 
Intrastate transportation and storage
$
290

 
$
208

Interstate transportation and storage
460

 
375

Midstream
412

 
414

NGL and refined products transportation and services
644

 
461

Crude oil transportation and services
751

 
548

Investment in Sunoco LP
152

 
140

Investment in USAC
105

 
95

All other
10

 
21

Total Segment Adjusted EBITDA
$
2,824

 
$
2,262

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.
Following is a reconciliation of our segment margin to operating income, as reported in the Partnership’s consolidated statements of operations:
 
Three Months Ended
June 30,
 
2019
 
2018
Segment Margin:
 
 
 
Intrastate transportation and storage
$
365

 
$
267

Interstate transportation and storage
493

 
378

Midstream
614

 
593

NGL and refined products transportation and services
764

 
587

Crude oil transportation and services
909

 
442

Investment in Sunoco LP
269

 
310

Investment in USAC
150

 
147

All other
48

 
57

Intersegment eliminations
(37
)
 
(6
)
Total segment margin
3,575

 
2,775

 
 
 
 
Less:
 
 
 
Operating expenses
792

 
772

Depreciation, depletion and amortization
785

 
694

Selling, general and administrative
179

 
183

Operating income
$
1,819

 
$
1,126


8


Intrastate Transportation and Storage
 
Three Months Ended
June 30,
 
2019
 
2018
Natural gas transported (BBtu/d)
12,115

 
10,327

Revenues
$
765

 
$
813

Cost of products sold
400

 
546

Segment margin
365

 
267

Unrealized gains on commodity risk management activities
(26
)
 
(8
)
Operating expenses, excluding non-cash compensation expense
(47
)
 
(51
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(7
)
 
(7
)
Adjusted EBITDA related to unconsolidated affiliates
5

 
7

Segment Adjusted EBITDA
$
290

 
$
208

Transported volumes increased primarily due to the impact of the Red Bluff Express pipeline coming online in May 2018, as well as the impact of favorable market pricing spreads.
Segment Adjusted EBITDA. For the three months ended June 30, 2019 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 $65 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; and
•
an increase of $14 million in transportation fees primarily due to new contracts, as well as the impact of the Red Bluff Express pipeline coming online in May 2018.
Interstate Transportation and Storage
 
Three Months Ended
June 30,
 
2019
 
2018
Natural gas transported (BBtu/d)
10,825

 
8,707

Natural gas sold (BBtu/d)
17

 
17

Revenues
$
493

 
$
378

Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(138
)
 
(110
)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(18
)
 
(17
)
Adjusted EBITDA related to unconsolidated affiliates
125

 
123

Other
(2
)
 
1

Segment Adjusted EBITDA
$
460

 
$
375

Transported volumes reflected an increase of 2,118 BBtu/d as a result of the following: the Rover pipeline being placed fully in-service in November 2018; production increases in the Haynesville Shale and deliveries to intrastate markets resulting in increased deliveries off of our Tiger pipeline; and increased utilization of higher contracted capacity on the Panhandle and Trunkline pipelines.
Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:
•
an increase of $69 million from placing the Rover pipeline fully in-service, resulting in an increase of $101 million in revenues, partially offset by an increase of $32 million in operating expenses;
•
increases of $5 million and $3 million from higher utilization of our Transwestern and Trunkline pipeline systems, respectively;
•
an increase of $3 million for additional gas processing revenues on our Panhandle system;

9


•
an increase of $3 million from additional volume delivered from our Sea Robin pipeline as a result of fewer third-party supply interruptions; and
•
an increase of $2 million in Adjusted EBITDA from unconsolidated affiliates primarily due to new fixed transportation contracts on Citrus.
Midstream
 
Three Months Ended
June 30,
 
2019
 
2018
Gathered volumes (BBtu/d)
13,148

 
11,576

NGLs produced (MBbls/d)
565

 
513

Equity NGLs (MBbls/d)
30

 
31

Revenues
$
1,198

 
$
1,874

Cost of products sold
584

 
1,281

Segment margin
614

 
593

Operating expenses, excluding non-cash compensation expense
(189
)
 
(169
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(23
)
 
(20
)
Adjusted EBITDA related to unconsolidated affiliates
9

 
9

Other
1

 
1

Segment Adjusted EBITDA
$
412

 
$
414

Gathered volumes and NGL production increased primarily due to increases in the Northeast, North Texas, South Texas, Permian and Ark-La-Tex regions, partially offset by smaller declines in the Mid-Continent/Panhandle regions.
Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased slightly due to the net effects of the following:
•
a decrease of $30 million in non-fee-based margin due to lower NGL prices of $35 million and lower gas prices of $15 million, partially offset by the impact of increased throughput volume in the Permian region of $20 million;
•
an increase of $20 million in operating expenses due to an increase of $10 million in outside services, $7 million in maintenance project costs, and $3 million in employee costs; and
•
an increase of $3 million in selling, general and administrative expenses due to an increase in allocated overhead and an insurance payment received in the second quarter of 2018; partially offset by
•
an increase of $51 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions, offset by declines in the Mid-Continent/Panhandle regions.


10


NGL and Refined Products Transportation and Services
 
Three Months Ended
June 30,
 
2019
 
2018
NGL transportation volumes (MBbls/d)
1,305

 
967

Refined products transportation volumes (MBbls/d)
628

 
637

NGL and refined products terminal volumes (MBbls/d)
988

 
789

NGL fractionation volumes (MBbls/d)
701

 
473

Revenues
$
2,612

 
$
2,568

Cost of products sold
1,848

 
1,981

Segment margin
764

 
587

Unrealized losses on commodity risk management activities
39

 
13

Operating expenses, excluding non-cash compensation expense
(155
)
 
(141
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(26
)
 
(17
)
Adjusted EBITDA related to unconsolidated affiliates
21

 
19

Other
1

 
—

Segment Adjusted EBITDA
$
644

 
$
461

NGL transportation volumes increased as a result of placing Mariner East 2 pipeline in service and higher throughput volumes on our Texas NGL pipeline system resulting primarily from increased production in the Permian and North Texas regions.
Refined products transportation volumes decreased slightly primarily due to refinery turnarounds in the Northeast and Midwest regions.
NGL and refined products terminal volumes increased primarily at Marcus Hook due to the initiation of service on our Mariner East 2 pipeline which commenced operations in the fourth quarter of 2018, an increase in volumes loaded at our Nederland terminal due to increased export demand and higher throughput volumes at our refined product terminals in the Northeast.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased primarily due to the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively.
Segment Adjusted EBITDA. For the three months ended June 30, 2019 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 impacts of the following:
•
an increase of $132 million in transportation margin primarily due to a $67 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $55 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $7 million increase due to higher throughput volumes received from the Barnett region and a $3 million increase due to higher throughput volumes received from the Eagle Ford region;
•
an increase of $55 million in terminal services margin primarily due to a $51 million increase at Marcus Hook resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018 and a $3 million increase due to higher throughput at our refined product terminals in the Northeast;
•
an increase of $46 million in fractionation and refinery services margin primarily due to a $50 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a $3 million decrease primarily resulting from a reclassification between our fractionation and storage margins; and
•
an increase of $5 million in storage margin primarily due to a $3 million increase resulting from a reclassification between our storage and fractionation margins and a $2 million increase from throughput pipeline fees collected at our Mont Belvieu storage facility; partially offset by
•
a decrease of $35 million in marketing margin primarily due to a decrease of $16 million from the write down of the value of stored NGL inventory, as well as lower optimization gains due to less favorable market conditions;

11


•
an increase of $14 million in operating expenses primarily due to a $4 million increase resulting from to the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, an aggregate increase of $7 million in ad valorem and employee expenses on our terminal and fractionation assets, and a $2 million increase in allocated costs; and
•
an increase of $9 million in selling, general and administrative expenses primarily due to a $4 million increase in allocated overhead costs, a $2 million increase in legal fees, a $1 million increase in employee costs and a $1 million increase in insurance expenses.
Crude Oil Transportation and Services
 
Three Months Ended
June 30,
 
2019
 
2018
Crude transportation volumes (MBbls/d)
4,728

 
4,242

Crude terminals volumes (MBbls/d)
2,383

 
2,103

Revenues
$
5,046

 
$
4,803

Cost of products sold
4,137

 
4,361

Segment margin
909

 
442

Unrealized losses on commodity risk management activities
11

 
262

Operating expenses, excluding non-cash compensation expense
(150
)
 
(144
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(20
)
 
(20
)
Adjusted EBITDA related to unconsolidated affiliates
1

 
8

Segment Adjusted EBITDA
$
751

 
$
548

Crude transportation and terminal volumes benefited from an increase in barrels through our existing Texas pipelines and our Bakken pipeline.
Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:
•
an increase of $216 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $142 million increase from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region, a $75 million increase from higher throughput on the Bakken pipeline, and a $9 million increase from higher throughput, ship loading and tank rental fees at our Nederland terminal; partially offset by a $10 million decrease (excluding a net change of $251 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from non-cash inventory valuation adjustments; partially offset by
•
an increase of $6 million in operating expenses primarily due to a $14 million increase in throughput-related costs on existing assets, partially offset by an $8 million decrease in ad valorem taxes and management fees; and
•
a decrease of $7 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.


12


Investment in Sunoco LP
 
Three Months Ended
June 30,
 
2019
 
2018
Revenues
$
4,475

 
$
4,607

Cost of products sold
4,206

 
4,297

Segment margin
269

 
310

Unrealized losses on commodity risk management activities
3

 
—

Operating expenses, excluding non-cash compensation expense
(89
)
 
(105
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(31
)
 
(31
)
Inventory valuation adjustments
(4
)
 
(32
)
Adjusted EBITDA related to discontinued operations
—

 
(5
)
Other
4

 
3

Segment Adjusted EBITDA
$
152

 
$
140

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impacts of the following:
•
a decrease of $16 million in operating expenses primarily as a result of lower salaries and benefits, maintenance, utilities, property tax, and environmental expenses as well as $7 million of acquisition costs in the prior periods; and
•
an increase of $5 million in Adjusted EBITDA from discontinued operations due to Sunoco LP’s retail divestment in January 2018; partially offset by
•
a decrease of $10 million in segment margin, excluding inventory valuation adjustments and unrealized gains and losses on commodity risk management activities, primarily due to a decrease in gross profit per gallon sold primarily as a result of an $8 million one-time charge related to a reserve for an open contractual dispute.
Investment in USAC
 
Three Months Ended
June 30,
 
2019
 
2018
Revenues
$
174

 
$
167

Cost of products sold
24

 
20

Segment margin
150

 
147

Operating expenses, excluding non-cash compensation expense
(32
)
 
(38
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(13
)
 
(19
)
Other
—

 
5

Segment Adjusted EBITDA
$
105

 
$
95

The Investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impacts of the following:
•
a decrease of $6 million in operating expenses primarily due to a decrease of ad valorem taxes as well as refunds received related to prior period ad valorem taxes;
•
a decrease of $6 million in selling, general administrative expenses primarily related to decreases of $4 million in transaction-related expenses and $2 million in employee expenses; and
•
an increase of $3 million in segment margin primarily due to an increase in demand for compression services resulting in an increase in average revenue generating horsepower.

13


All Other
 
Three Months Ended
June 30,
 
2019
 
2018
Revenues
$
391

 
$
502

Cost of products sold
343

 
445

Segment margin
48

 
57

Unrealized gains on commodity risk management activities
(4
)
 
(2
)
Operating expenses, excluding non-cash compensation expense
(6
)
 
(10
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(23
)
 
(28
)
Adjusted EBITDA related to unconsolidated affiliates
2

 
2

Other and eliminations
(7
)
 
2

Segment Adjusted EBITDA
$
10

 
$
21

Segment Adjusted EBITDA. For the three months ended June 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of the following:
•
a decrease of $7 million from power trading activities;
•
a decrease of $10 million due to lower revenue from our compressor equipment business;
•
a decrease of $4 million in optimized gains on residue gas sales; and
•
a decrease of $2 million from settled derivatives; partially offset by
•
an increase of $13 million in storage optimization gains.


14


ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON LIQUIDITY
(In millions)
(unaudited)
The following table is a summary of ETO’s revolving credit facilities. We also have other consolidated subsidiaries with revolving credit facilities which are not included in this table.
 
Facility Size
 
Funds Available at June 30, 2019
 
Maturity Date
ETO Five-Year Revolving Credit Facility
$
5,000

 
$
2,555

 
December 1, 2023
ETO 364-Day Revolving Credit Facility
1,000

 
1,000

 
November 29, 2019
 
$
6,000

 
$
3,555

 
 

15


ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions)
(unaudited)
The table below provides information on an aggregated basis for our unconsolidated affiliates, which are accounted for as equity method investments in the Partnership’s financial statements for the periods presented.
 
Three Months Ended
June 30,
 
2019
 
2018
Equity in earnings of unconsolidated affiliates:
 
 
 
Citrus
$
39

 
$
33

FEP
14

 
13

MEP
7

 
8

Other
17

 
38

Total equity in earnings of unconsolidated affiliates
$
77

 
$
92

 
 
 
 
Adjusted EBITDA related to unconsolidated affiliates:
 
 
 
Citrus
$
87

 
$
85

FEP
18

 
18

MEP
20

 
20

Other
38

 
45

Total Adjusted EBITDA related to unconsolidated affiliates
$
163

 
$
168

 
 
 
 
Distributions received from unconsolidated affiliates:
 
 
 
Citrus
$
39

 
$
27

FEP
16

 
15

MEP
15

 
18

Other
42

 
21

Total distributions received from unconsolidated affiliates
$
112

 
$
81


16


ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON NON-WHOLLY-OWNED JOINT VENTURE SUBSIDIARIES
(Dollars in millions)
(unaudited)
The table below provides information on an aggregated basis for our non-wholly-owned joint venture subsidiaries, which are reflected on a consolidated basis in our financial statements. The table below excludes Sunoco LP and USAC, our non-wholly-owned subsidiaries that are publicly traded.
 
Three Months Ended
June 30,
 
2019
 
2018
Adjusted EBITDA of non-wholly-owned subsidiaries (100%) (a)
$
695

 
$
432

Our proportionate share of Adjusted EBITDA of non-wholly-owned subsidiaries (b)
380

 
233

 
 
 
 
Distributable Cash Flow of non-wholly-owned subsidiaries (100%) (c)
$
657

 
$
399

Our proportionate share of Distributable Cash Flow of non-wholly-owned subsidiaries (d)
364

 
219

Below is our current ownership percentage of certain non-wholly-owned subsidiaries:
Non-wholly-owned subsidiary:
ET Percentage Ownership (e)
Bakken Pipeline
36.4
%
Bayou Bridge
60.0
%
Ohio River System
75.0
%
Permian Express Partners
87.7
%
Red Bluff Express
70.0
%
Rover
32.6
%
Others
various

(a)
Adjusted EBITDA of non-wholly-owned subsidiaries reflects the total Adjusted EBITDA of our non-wholly-owned subsidiaries on an aggregated basis. This is the amount of Adjusted EBITDA included in our consolidated non-GAAP measure of Adjusted EBITDA.
(b)
Our proportionate share of Adjusted EBITDA of non-wholly-owned subsidiaries reflects the amount of Adjusted EBITDA of such subsidiaries (on an aggregated basis) that is attributable to our ownership interest.
(c)
Distributable Cash Flow of non-wholly-owned subsidiaries reflects the total Distributable Cash Flow of our non-wholly-owned subsidiaries on an aggregated basis.
(d)
Our proportionate share of Distributable Cash Flow of non-wholly-owned subsidiaries reflects the amount of Distributable Cash Flow of such subsidiaries (on an aggregated basis) that is attributable to our ownership interest. This is the amount of Distributable Cash Flow included in our consolidated non-GAAP measure of Distributable Cash Flow attributable to the partners of ET.
(e)
Our ownership reflects the total economic interest held by us and our subsidiaries. In some cases, this percentage comprises ownership interests held in (or by) multiple entities.



17