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ENERGY TRANSFER REPORTS SOLID FOURTH QUARTER 2019 RESULTS
Net income attributable to partners of $1.01 billion, reflecting an increase over the prior period primarily due to higher operating income.
Adjusted EBITDA of $2.81 billion, up 5 percent from the fourth quarter of 2018.
Distributable Cash Flow attributable to partners of $1.55 billion, up 2 percent from the fourth quarter of 2018.
Distribution coverage ratio of 1.88x, yielding excess coverage of $725 million of Distributable Cash Flow attributable to partners in excess of distributions.
Provides 2020 outlook for Adjusted EBITDA of $11.0 billion to $11.4 billion.
2020 growth capital expenditures outlook, updated to include $300 million of capital expenditures related to the acquisition of SemGroup Corporation (“SemGroup”), expected to range from $3.9 billion to $4.1 billion.
Reduces expected annual run-rate growth capital expenditures for 2021 and beyond to $2 billion to $2.5 billion based on increased project returns threshold.
Dallas - February 19, 2020 - Energy Transfer LP (NYSE:ET) (“ET” or the “Partnership”) today reported financial results for the quarter and year ended December 31, 2019.
ET reported net income attributable to partners for the three months ended December 31, 2019 of $1.01 billion, an increase of $395 million compared to the three months ended December 31, 2018. For the three months ended December 31, 2019, net income per limited partner unit (basic and diluted) was $0.38 per unit.
Adjusted EBITDA for the three months ended December 31, 2019 was $2.81 billion, an increase of $138 million compared to the three months ended December 31, 2018. Results were supported by continued strong performance among several of the Partnership’s core segments, with additional record operating performance in our NGL and refined products transportation and services segment.
Distributable Cash Flow attributable to partners, as adjusted, for the three months ended December 31, 2019 was $1.55 billion, an increase of $30 million compared to the three months ended December 31, 2018. The increase was primarily due to the increase in Adjusted EBITDA.
Key accomplishments and recent developments:
Operational
In October 2019, the Permian Express 4 pipeline expansion went into full service.
In December 2019, ET and Shell US LNG, LLC (“Shell”) announced that a comprehensive commercial tender package has been issued to engineering, procurement and construction contractors to submit final commercial bids for the proposed Lake Charles LNG liquefaction project being jointly developed by ET and Shell on a 50/50 basis. The project would modify ET’s existing LNG import facility in Lake Charles, Louisiana to add LNG liquefaction capacity of 16.45 million tonnes per annum for export to global markets.
In February 2020, Frac VII was placed in service, bringing the total fractionation capacity at Mont Belvieu to over 900,000 barrels per day.
Strategic
On December 5, 2019, ET successfully acquired SemGroup and as a result of the merger, ET issued approximately 57.6 million of its common units to SemGroup stockholders. The combined operations of the two companies are expected to generate annual run-rate efficiencies of more than $170 million, consisting of commercial and operational synergies of $80 million, financial savings of $50 million and cost savings of $40 million.
Financial
In January 2020, Energy Transfer Operating, LP (“ETO”) completed a registered offering of $4.5 billion of its senior notes, consisting of $1.0 billion aggregate principal amount of 2.90% senior notes due 2025, $1.5 billion aggregate principal amount of 3.75% senior notes due 2030 and $2.0 billion aggregate principal amount of 5.0% senior notes due 2050. ETO also

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completed a public offering of 500,000 of its 6.75% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units at a price of $1,000 per unit and 1,100,000 of its 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units at a price of $1,000 per unit. ETO used the aggregate net proceeds of approximately $6.04 billion from both offerings to repay certain of its outstanding indebtedness, including prepayment of certain senior indebtedness, and for general partnership purposes.
In January 2020, ET announced a quarterly distribution of $0.305 per unit ($1.220 annualized) on ET common units for the quarter ended December 31, 2019.
As of December 31, 2019, ETO’s $6.00 billion revolving credit facilities had an aggregate $1.71 billion of available capacity, and ETO’s leverage ratio, as defined by its credit agreement, was 3.96x.
Energy Transfer 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% of the Partnership’s consolidated Adjusted EBITDA in 2019. The vast 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 4:00 p.m. Central Time/5:00 p.m. Eastern Time on Wednesday, February 19, 2020 to discuss its
fourth quarter 2019 results. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfer.com or ir.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 natural gas 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 natural gas 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.

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Contacts
Energy Transfer
Investor Relations:
Bill Baerg, Brent Ratliff, Lyndsay Hannah, 214-981-0795
or
Media Relations:
Vicki Granado, 214-840-5820

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ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(unaudited)
 
December 31, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
$
7,867

 
$
6,750

 
 
 
 
Property, plant and equipment, net
74,193

 
66,963

 
 
 
 
Advances to and investments in unconsolidated affiliates
3,460

 
2,642

Lease right-of-use assets, net (a)
964

 

Other non-current assets, net
1,075

 
1,006

Intangible assets, net
6,154

 
6,000

Goodwill
5,167

 
4,885

Total assets
$
98,880

 
$
88,246

LIABILITIES AND EQUITY
 
 
 
Current liabilities
$
7,724

 
$
9,310

 
 
 
 
Long-term debt, less current maturities
51,028

 
43,373

Non-current derivative liabilities
273

 
104

Non-current operating lease liabilities (a)
901

 

Deferred income taxes
3,208

 
2,926

Other non-current liabilities
1,162

 
1,184

 
 
 
 
Commitments and contingencies
 
 
 
Redeemable noncontrolling interests
739

 
499

 
 
 
 
Equity:
 
 
 
Total partners’ capital
21,827

 
20,559

Noncontrolling interest
12,018

 
10,291

Total equity
33,845

 
30,850

Total liabilities and equity
$
98,880

 
$
88,246

(a) 
Lease-related balances as of December 31, 2019 were recorded in connection with the required adoption of the new lease accounting principles (referred to as ASC 842) on January 1, 2019.

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ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(unaudited)
 
Three Months Ended
December 31,
 
Year Ended
December 31,
 
2019
 
2018
 
2019
 
2018
REVENUES
$
13,720

 
$
13,573

 
$
54,213

 
$
54,087

COSTS AND EXPENSES:
 
 
 
 
 
 
 
Cost of products sold
10,120

 
9,977

 
39,727

 
41,658

Operating expenses
888

 
809

 
3,294

 
3,089

Depreciation, depletion and amortization
804

 
750

 
3,147

 
2,859

Selling, general and administrative
195

 
187

 
694

 
702

Impairment losses
12

 
431

 
74

 
431

Total costs and expenses
12,019

 
12,154

 
46,936

 
48,739

OPERATING INCOME
1,701

 
1,419

 
7,277

 
5,348

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest expense, net of interest capitalized
(584
)
 
(544
)
 
(2,331
)
 
(2,055
)
Equity in earnings of unconsolidated affiliates
78

 
86

 
302

 
344

Losses on extinguishments of debt

 
(6
)
 
(18
)
 
(112
)
Gains (losses) on interest rate derivatives
130

 
(70
)
 
(241
)
 
47

Other, net
6

 
(35
)
 
105

 
62

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)
1,331

 
850

 
5,094

 
3,634

Income tax expense (benefit) from continuing operations
(19
)
 
(2
)
 
195

 
4

INCOME FROM CONTINUING OPERATIONS
1,350

 
852

 
4,899

 
3,630

Loss from discontinued operations, net of income taxes

 

 

 
(265
)
NET INCOME
1,350

 
852

 
4,899

 
3,365

Less: Net income attributable to noncontrolling interest
325

 
220

 
1,256

 
1,632

Less: Net income attributable to redeemable noncontrolling interests
13

 
15

 
51

 
39

NET INCOME ATTRIBUTABLE TO PARTNERS
1,012

 
617

 
3,592

 
1,694

Convertible Unitholders’ interest in income

 

 

 
33

General Partner’s interest in net income
1

 

 
4

 
3

Limited Partners’ interest in net income
$
1,011

 
$
617

 
$
3,588

 
$
1,658

NET INCOME PER LIMITED PARTNER UNIT:
 
 
 
 
 
 
 
Basic
$
0.38

 
$
0.26

 
$
1.37

 
$
1.16

Diluted
$
0.38

 
$
0.26

 
$
1.36

 
$
1.15

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING:
 
 
 
 
 
 
 
Basic
2,646.2

 
2,332.1

 
2,628.0

 
1,423.8

Diluted
2,653.3

 
2,339.4

 
2,637.6

 
1,461.4


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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
(Dollars and units in millions)
(unaudited)
 
Three Months Ended
December 31,
 
Year Ended
December 31,
 
2019
 
2018
 
2019
 
2018
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (b):
 
 
 
 
 
 
 
Net income
$
1,350

 
$
852

 
$
4,899

 
$
3,365

Loss from discontinued operations

 

 

 
265

Interest expense, net of interest capitalized
584

 
544

 
2,331

 
2,055

Impairment losses
12

 
431

 
74

 
431

Income tax expense (benefit) from continuing operations
(19
)
 
(2
)
 
195

 
4

Depreciation, depletion and amortization
804

 
750

 
3,147

 
2,859

Non-cash compensation expense
28

 
23

 
113

 
105

(Gains) losses on interest rate derivatives
(130
)
 
70

 
241

 
(47
)
Unrealized (gains) losses on commodity risk management activities
95

 
(244
)
 
5

 
11

Losses on extinguishments of debt

 
6

 
18

 
112

Inventory valuation adjustments
(8
)
 
135

 
(79
)
 
85

Equity in earnings of unconsolidated affiliates
(78
)
 
(86
)
 
(302
)
 
(344
)
Adjusted EBITDA related to unconsolidated affiliates
156

 
152

 
626

 
655

Adjusted EBITDA from discontinued operations

 

 

 
(25
)
Other, net
13

 
38

 
(54
)
 
(21
)
Adjusted EBITDA (consolidated)
2,807

 
2,669

 
11,214

 
9,510

Adjusted EBITDA related to unconsolidated affiliates
(156
)
 
(152
)
 
(626
)
 
(655
)
Distributable Cash Flow from unconsolidated affiliates
108

 
95

 
415

 
407

Interest expense, net of interest capitalized
(584
)
 
(544
)
 
(2,331
)
 
(2,057
)
Subsidiary preferred unitholders’ distributions
(68
)
 
(54
)
 
(253
)
 
(170
)
Current income tax (expense) benefit
45

 
(7
)
 
22

 
(472
)
Transaction-related income taxes
(31
)
 

 
(31
)
 
470

Maintenance capital expenditures
(215
)
 
(137
)
 
(655
)
 
(510
)
Other, net(c)
30

 
19

 
85

 
49

Distributable Cash Flow (consolidated)
1,936

 
1,889

 
7,840

 
6,572

Distributable Cash Flow attributable to Sunoco LP (100%)
(120
)
 
(115
)
 
(450
)
 
(446
)
Distributions from Sunoco LP
42

 
43

 
165

 
166

Distributable Cash Flow attributable to USAC (100%)
(58
)
 
(55
)
 
(222
)
 
(148
)
Distributions from USAC
24

 
21

 
90

 
73

Distributable Cash Flow attributable to noncontrolling interest in other non-wholly-owned consolidated subsidiaries
(286
)
 
(294
)
 
(1,113
)
 
(874
)
Distributable Cash Flow attributable to the partners of ET – pro forma for the ETO Merger (a)
1,538

 
1,489

 
6,310

 
5,343

Transaction-related expenses
8

 
27

 
14

 
52

Distributable Cash Flow attributable to the partners of ET, as adjusted – pro forma for the ETO Merger (a)
$
1,546

 
$
1,516

 
$
6,324

 
$
5,395


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Three Months Ended
December 31,
 
Year Ended
December 31,
 
2019
 
2018
 
2019
 
2018
Distributions to partners – pro forma for the
ETO Merger (a):
 
 
 
 
 
 
 
Limited Partners (d)
$
820

 
$
799

 
$
3,221

 
$
3,104

General Partner
1

 
1

 
4

 
4

Total distributions to be paid to partners
$
821

 
$
800

 
$
3,225

 
$
3,108

Common Units outstanding – end of period
2,689.6

 
2,619.4

 
2,689.6

 
2,619.4

Distribution coverage ratio – pro forma for the ETO Merger (a)
1.88x

 
1.90x

 
1.96x

 
1.74x

(a) 
The closing of the restructuring transaction in October 2018 (the “ETO Merger”) 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 months and year ended December 31, 2018. In order to provide information on a comparable basis for pre-ETO Merger and post-ETO Merger periods, the Partnership has included certain pro forma information for the year ended December 31, 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 interest 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 ETO 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 ETO 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 any such measure 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 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 unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.

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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.
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; and
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 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) 
For the three months and year ended December 31, 2019, “Other, net” includes $19 million of Distributable Cash Flow attributable to the operations of SemGroup for October 1 through December 4, 2019, which represents amounts distributable to ET’s common unitholders (including the holders of the common units issued in the SemGroup acquisition) with respect the fourth quarter 2019 distribution.
(d) 
The amount reflected for the year ended December 31, 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. The quarter ended March 31, 2018 was the final quarter of participation in the plan.

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ENERGY TRANSFER LP AND SUBSIDIARIES
SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)
 
Three Months Ended
December 31,
 
2019
 
2018
Segment Adjusted EBITDA:
 
 
 
Intrastate transportation and storage
$
222

 
$
306

Interstate transportation and storage
434

 
479

Midstream
397

 
402

NGL and refined products transportation and services
743

 
569

Crude oil transportation and services
715

 
636

Investment in Sunoco LP
168

 
180

Investment in USAC
110

 
104

All other
18

 
(7
)
Total Segment Adjusted EBITDA
$
2,807

 
$
2,669

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. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.
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.
Intrastate Transportation and Storage
 
Three Months Ended
December 31,
 
2019
 
2018
Natural gas transported (BBtu/d)
13,098

 
11,708

Revenues
$
714

 
$
1,127

Cost of products sold
436

 
777

Segment margin
278

 
350

Unrealized (gains) losses on commodity risk management activities
(1
)
 
5

Operating expenses, excluding non-cash compensation expense
(53
)
 
(48
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(9
)
 
(7
)
Adjusted EBITDA related to unconsolidated affiliates
7

 
6

Segment Adjusted EBITDA
$
222

 
$
306

For the three months ended December 31, 2019 compared to the same period last year, transported volumes increased primarily due to increased utilization of our Texas pipelines.

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Segment Adjusted EBITDA. For the three months ended December 31, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impacts of the following:
a decrease of $101 million in realized natural gas sales and other primarily due to lower realized gains from pipeline optimization activity;
an increase of $5 million in operating expenses primarily due to a $3 million increase in maintenance projects costs, a $3 million increase in outside services and materials and a $2 million increase in ad valorem tax expense, partially offset by lower allocated overhead costs and a decrease in cost of fuel consumption;
a decrease of $4 million in retained fuel revenues due to lower gas prices; and
a decrease of $1 million in realized storage margin primarily due to lower realized optimization; partially offset by
an increase of $28 million in transportation fees primarily due to new contracts, as well as volume ramp-ups on Red Bluff Express. The increase also included the impact of a non-recurring adjustment to a transportation services agreement in the prior period.
Interstate Transportation and Storage
 
Three Months Ended
December 31,
 
2019
 
2018
Natural gas transported (BBtu/d)
11,620

 
11,062

Natural gas sold (BBtu/d)
17

 
18

Revenues
$
493

 
$
495

Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(144
)
 
(120
)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(23
)
 
(8
)
Adjusted EBITDA related to unconsolidated affiliates
109

 
118

Other
(1
)
 
(6
)
Segment Adjusted EBITDA
$
434

 
$
479

Transported volumes reflected an increase due to stronger demand for delivery to markets in the Western U.S., the successful addition of new contracted volumes for delivery out of the Haynesville Shale, and higher volumes on the Rover pipeline; offset by lower utilization of contracted capacity on the Panhandle Eastern and Trunkline pipelines.
Segment Adjusted EBITDA. For the three months ended December 31, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:
an increase of $24 million in operating expenses primarily due to an increase in ad valorem tax expense of $25 million on the Rover pipeline system due to placing the final portions of this asset into service in November 2018 and additional operating expenses of $3 million for assets acquired in 2019, offset by lower gas imbalances and system gas activity of $6 million;
an increase of $15 million in selling, general and administrative expenses primarily due to an increase of $5 million resulting from the reclassification of an OPEB funding requirement adjustment, an increase of $5 million in insurance expense, an increase of $4 million in overhead allocations and an increase of $2 million related to assets acquired in 2019; and
a decrease of $9 million in Adjusted EBITDA related to unconsolidated affiliates primarily resulting from the re-contracting of expiring contracts on Midcontinent Express Pipeline, partially offset by gains on the Citrus pipeline system; partially offset by
an increase of $5 million in other primarily due to the reclassification of an OPEB funding requirement adjustment.

10



Midstream
 
Three Months Ended
December 31,
 
2019
 
2018
Gathered volumes (BBtu/d)
14,000

 
12,827

NGLs produced (MBbls/d)
583

 
558

Equity NGLs (MBbls/d)
29

 
25

Revenues
$
1,535

 
$
1,781

Cost of products sold
899

 
1,172

Segment margin
636

 
609

Operating expenses, excluding non-cash compensation expense
(217
)
 
(193
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(27
)
 
(22
)
Adjusted EBITDA related to unconsolidated affiliates
6

 
8

Other
(1
)
 

Segment Adjusted EBITDA
$
397

 
$
402

For the three months ended December 31, 2019 compared to the same period last year, gathered volumes increased primarily due to increases in the Northeast, Permian, Ark-La-Tex, South Texas and North Texas regions. NGL production increased due to increases in the Permian region, partially offset by ethane rejection in the South Texas and North Texas regions.
Segment Adjusted EBITDA. For the three months ended December 31, 2019 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 $18 million in non fee-based margin due to lower NGL prices of $8 million and lower gas prices of $21 million, partially offset by an increase of $11 million in non fee-based margin due to increased throughput volume in the Permian region;
an increase of $45 million in fee-based margin due to volume growth in the Northeast, Permian and South Texas regions;
an increase of $24 million in operating expenses due to increases of $17 million in maintenance project costs, $6 million in outside services and $2 million in materials; and
an increase of $5 million in selling, general and administrative expenses due to an increase of $3 million in insurance expense and a decrease of $2 million in capitalized overhead.

11



NGL and Refined Products Transportation and Services
 
Three Months Ended
December 31,
 
2019
 
2018
NGL transportation volumes (MBbls/d)
1,325

 
1,115

Refined products transportation volumes (MBbls/d)
535

 
601

NGL and refined products terminal volumes (MBbls/d)
935

 
898

NGL fractionation volumes (MBbls/d)
734

 
594

Revenues
$
3,120

 
$
2,946

Cost of products sold
2,257

 
2,106

Segment margin
863

 
840

Unrealized (gains) losses on commodity risk management activities
66

 
(112
)
Operating expenses, excluding non-cash compensation expense
(185
)
 
(156
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(26
)
 
(22
)
Adjusted EBITDA related to unconsolidated affiliates
23

 
19

Other
2

 

Segment Adjusted EBITDA
$
743

 
$
569

For the three months ended December 31, 2019 compared to the same period last year, NGL transportation volumes on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions. In addition, NGL transportation volumes on our Northeast assets increased due to the initiation of service on our Mariner East 2 pipeline system.
Refined products transportation volumes decreased for the three months ended December 31, 2019 compared to the same period last year primarily due to the closure of a third-party refinery, negatively impacting supply on our system in 2019. These decreases are partially offset by the initiation of service on the JC Nolan Pipeline in the third quarter of 2019.
NGL and refined products terminal volumes increased for the three months ended December 31, 2019 compared to the same period last year primarily due to the initiation of service on our Mariner East 2 pipeline system which commenced operations in December 2018. This increase was partially offset by lower volumes from our refined products marketing terminals due to the closure of a third-party refinery and lower volumes exported out of our Nederland terminal.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased for the three months ended December 31, 2019 compared to the same period last year primarily due to the commissioning of our sixth fractionator in February 2019.
Segment Adjusted EBITDA. For the three months ended December 31, 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 $102 million in transportation margin primarily due to a $77 million increase from the initiation of service on our Mariner East 2 pipeline, which commenced in December 2018, and a $33 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines. These increases were partially offset by lower propane throughput during the fourth quarter of 2019, as well as a $7 million decrease due to the closure of the a third-party refinery during 2019, which negatively impacted supply to our refined product transportation system;
an increase of $29 million in fractionators and refinery services margin primarily due to the commissioning of our sixth fractionator in February 2019 and higher NGL volumes from the Permian and North Texas regions feeding our Mont Belvieu fractionation facility;
an increase of $61 million in marketing margin primarily due to optimization gains of $85 million related to the sale of NGL component products at our Mont Belvieu facility due to higher volumes and more favorable market conditions, a $6 million increase from our butane and gasoline blending operations, and a $3 million increase due to the initiation of service on the JC Nolan Pipeline. These increases were partially offset by a $35 million decrease due to capacity lease fees incurred by our marketing affiliate on our Mariner East 2 pipeline;
an increase of $10 million in terminal services margin primarily due to a $40 million increase primarily resulting from the initiation of service on our Mariner East 2 pipeline which commenced operations in December 2018. This increase was

12



partially offset by a $7 million decrease due to fewer vessels exported out of our Nederland terminal, a $7 million decrease in expense reimbursements from third parties on Mariner East 1, a $6 million decrease due to lower volumes from third party pipelines and lower truck and rail deliveries into our to our Marcus Hook Industrial Terminal, a $5 million decrease resulting from the timing of affiliate vessels loaded at Marcus Hook, and a $3 million negative adjustment for product losses; partially offset by
an increase of $29 million in operating expenses primarily due to a $10 million increase in employee and ad valorem tax expenses on our terminals, fractionators, and transport operations, a $8 million increase in maintenance project costs, a $6 million increase due to the write-off of a customer reimbursement, a $4 million increase in contract services expenses, and a $2 million increase in material costs. These increases were partially offset by an $8 million decrease in allocated overhead costs;
an increase in general and administrative expenses of $4 million primarily due to a $3 million increase in allocated overhead costs and a $3 million increase in insurance expenses.
Crude Oil Transportation and Services
 
Three Months Ended
December 31,
 
2019
 
2018
Crude transportation volumes (MBbls/d)
4,734

 
4,330

Crude terminals volumes (MBbls/d)
1,923

 
2,202

Revenues
$
4,762

 
$
4,346

Cost of products sold
3,901

 
3,407

Segment margin
861

 
939

Unrealized (gains) losses on commodity risk management activities
31

 
(132
)
Operating expenses, excluding non-cash compensation expense
(160
)
 
(150
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(24
)
 
(22
)
Adjusted EBITDA related to unconsolidated affiliates
8

 
1

Other
(1
)
 

Segment Adjusted EBITDA
$
715

 
$
636

Segment Adjusted EBITDA. For the three months ended December 31, 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 $85 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a favorable inventory valuation adjustment of $59 million for the current period compared to an unfavorable inventory valuation adjustment of $139 million for the prior period, partially offset by a reduction of $101 million due to lower basis spreads, net of hedges. We also realized gains of $23 million from our Bayou Bridge Pipeline and increased revenues from Permian gathering activity of $13 million, offset by losses of $23 million from our Oklahoma assets resulting from a non-recurring deficiency payment recognized in the prior period and $21 million from our Texas crude pipelines system resulting from lower rates, offset by higher volumes; and
an increase of $7 million in Adjusted EBITDA related to unconsolidated affiliates due to higher margin from jet fuel sales by our joint ventures; partially offset by
an increase of $2 million in selling, general and administrative expenses primarily due to an increase in insurance expense.

13



Investment in Sunoco LP
 
Three Months Ended
December 31,
 
2019
 
2018
Revenues
$
4,098

 
$
3,877

Cost of products sold
3,813

 
3,694

Segment margin
285

 
183

Unrealized (gains) losses on commodity risk management activities
(1
)
 
5

Operating expenses, excluding non-cash compensation expense
(84
)
 
(111
)
Selling, general and administrative, excluding non-cash compensation expense
(32
)
 
(36
)
Adjusted EBITDA related to unconsolidated affiliates
3

 

Inventory fair value adjustments
(8
)
 
135

Other, net
5

 
4

Segment Adjusted EBITDA
$
168

 
$
180

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended December 31, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP decreased due to the net impacts of the following:
a decrease of $47 million in margin (excluding the change in inventory fair value adjustments and unrealized losses on commodity risk management activities) primarily due to lower fuel margins, partially offset by an increase in volumes sold; partially offset by
a decrease of $27 million in operating expense, excluding non-cash compensation expense primarily as a result of the May 2019 sale of Sunoco LP’s ethanol plant in Fulton, New York.
Investment in USAC
 
Three Months Ended
December 31,
 
2019
 
2018
Revenues
$
178

 
$
172

Cost of products sold
22

 
23

Segment margin
156

 
149

Operating expenses, excluding non-cash compensation expense
(32
)
 
(30
)
Selling, general and administrative, excluding non-cash compensation expense
(14
)
 
(16
)
Other, net

 
1

Segment Adjusted EBITDA
$
110

 
$
104

The Investment in USAC segment reflects the consolidated results of operations for USAC.
Segment Adjusted EBITDA. For the three months ended December 31, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC increased primarily due to an increase in demand for compression services driven by increased U.S. production of crude oil and natural gas, and an increase in average revenue per revenue generating horsepower per month.

14



All Other
 
Three Months Ended
December 31,
 
2019
 
2018
Revenues
$
413

 
$
630

Cost of products sold
366

 
585

Segment margin
47

 
45

Unrealized gains on commodity risk management activities

 
(11
)
Operating expenses, excluding non-cash compensation expense
(25
)
 
(6
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(24
)
 
(41
)
Adjusted EBITDA related to unconsolidated affiliates
1

 

Other and eliminations
19

 
6

Segment Adjusted EBITDA
$
18

 
$
(7
)
Segment Adjusted EBITDA. For the three months ended December 31, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased due to the net impacts of the following:
an increase of $3 million in gains from park and loan and storage activity;
an increase of $16 million related to a legal settlement;
an increase of $3 million from the acquisition of SemGroup, for which the impact to our all other segment included adjusted EBITDA from SemCAMS, offset by SemGroup corporate expenses; and
a decrease of $21 million in merger and acquisition expenses; partially offset by
a decrease of $6 million due to lower gas prices and increased power costs; and
a decrease of $7 million due to lower revenue from our compressor equipment business.


15



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 consolidated subsidiaries with revolving credit facilities which are not included.
 
Facility Size
 
Funds Available at December 31, 2019
 
Maturity Date
ETO Five-Year Revolving Credit Facility
$
5,000

 
$
709

 
December 1, 2023
ETO 364-Day facility
1,000

 
1,000

 
November 27, 2020
 
$
6,000

 
$
1,709

 
 

16



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
December 31,
 
2019
 
2018
Equity in earnings of unconsolidated affiliates:
 
 
 
Citrus
$
33

 
$
39

FEP
16

 
14

MEP

 
7

Other
29

 
26

Total equity in earnings of unconsolidated affiliates
$
78

 
$
86

 
 
 
 
Adjusted EBITDA related to unconsolidated affiliates:
 
 
 
Citrus
$
82

 
$
81

FEP
19

 
18

MEP
8

 
19

Other
47

 
34

Total Adjusted EBITDA related to unconsolidated affiliates
$
156

 
$
152

 
 
 
 
Distributions received from unconsolidated affiliates:
 
 
 
Citrus
$
50

 
$
46

FEP
20

 
18

MEP
3

 
8

Other
21

 
34

Total distributions received from unconsolidated affiliates
$
94

 
$
106


17



ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON NON-WHOLLY-OWNED JOINT VENTURE SUBSIDIARIES
(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, which are non-wholly-owned subsidiaries that are publicly traded.
 
Three Months Ended
December 31,
 
2019
 
2018
Adjusted EBITDA of non-wholly-owned subsidiaries (100%) (a)
$
642

 
$
669

Our proportionate share of Adjusted EBITDA of non-wholly-owned subsidiaries (b)
335

 
351

 
 
 
 
Distributable Cash Flow of non-wholly-owned subsidiaries (100%) (c)
$
601

 
$
626

Our proportionate share of Distributable Cash Flow of non-wholly-owned subsidiaries (d)
315

 
332

Below is our 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 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.

18

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