Document






UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 

 

FORM 8-K
 
CURRENT REPORT
 
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
February 20, 2019
Date of Report (Date of earliest event reported)
 
ENERGY TRANSFER LP
(Exact name of Registrant as specified in its charter)
 
 
 
 
 
 
Delaware
 
1-32740
 
30-0108820
(State or other jurisdiction of incorporation)
 
(Commission File Number)
 
(IRS Employer Identification Number)
 
8111 Westchester Drive, Suite 600,
Dallas, Texas 75225
(Address of principal executive offices) (zip code)
(214) 981-0700
(Registrant’s telephone number, including area code)


Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company. ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new of revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨






Item 2.02. Results of Operations and Financial Condition.
On February 20, 2019, Energy Transfer LP (the “Partnership”) issued a press release announcing its financial and operating results for the fourth quarter ended December 31, 2018. A copy of this press release is furnished as Exhibit 99.1 to this report and is incorporated herein by reference.
In accordance with General Instruction B.2 of Form 8-K, the information set forth in this Item 2.02 and in the attached exhibit shall be deemed to be “furnished” and not be deemed to be “filed” for purposes of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits. In accordance with General Instruction B.2 of Form 8-K, the information set forth in the attached Exhibit 99.1 is deemed to be “furnished” and shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act.
Exhibit Number
 
Description of the Exhibit
 





SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


 
 
ENERGY TRANSFER LP
 
 
By:
LE GP, LLC, its general partner
 
 
 
 
Date:
February 20, 2019
By:
/s/ Thomas E. Long
 
 
 
Thomas E. Long
 
 
 
Chief Financial Officer (duly
authorized to sign on behalf of the registrant)


Exhibit


http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12723098&doc=3
ENERGY TRANSFER REPORTS FOURTH QUARTER 2018 RESULTS WITH RECORD PERFORMANCE AND CONTINUED GROWTH
Net income attributable to partners of $617 million, reflecting an increase over previous periods primarily due to the impact of the Merger.
Record Adjusted EBITDA of $2.67 billion, up 29 percent from the fourth quarter of 2017.
Record Distributable Cash Flow attributable to partners of $1.52 billion, up 29 percent from the fourth quarter of 2017.
Distribution coverage ratio of 1.90x, yielding excess coverage of $716 million of Distributable Cash Flow attributable to partners in excess of distributions.
Reaffirms 2019 outlook for Adjusted EBITDA of $10.6 billion to $10.8 billion and capital expenditures of approximately $5 billion.
Dallas - February 20, 2019 - Energy Transfer LP (NYSE:ET) (“ET” or the “Partnership”) today reported financial results for the quarter and year ended December 31, 2018.
ET reported net income attributable to partners for the three months ended December 31, 2018 of $617 million, an increase of $366 million compared to the three months ended December 31, 2017. For the prior period, net income attributable to partners continues to reflect only the amount of net income attributable to the legacy ETE partners prior to the Merger, as discussed below.
Adjusted EBITDA for the three months ended December 31, 2018 was $2.67 billion, an increase of $592 million compared to the three months ended December 31, 2017. Results were supported by increases in all of the Partnership’s core operations, with record operating performance in ET’s NGL, interstate and intrastate businesses.
On a pro forma basis for the Merger, Distributable Cash Flow attributable to partners, as adjusted, for the three months ended December 31, 2018 was a record $1.52 billion, an increase of $338 million compared to the three months ended December 31, 2017. The increase was primarily due to the increase in Adjusted EBITDA.
Key accomplishments and current developments:
Strategic
ET and Energy Transfer Operating, L.P. (“ETO”, formerly Energy Transfer Partners, L.P. or “ETP”) completed a simplification merger transaction on October 19, 2018 (the “Merger”) whereby the publicly held common units of ETP were exchanged for 1.28 common units of ET. Consequently, the former common unitholders of ETP, along with the existing common unitholders of ET, now comprise the current common unitholders of ET.
Operational
Frac VI, a 150,000 barrel per day fractionator at Mont Belvieu, was placed in service in February 2019.
Bakken Pipeline completed a successful open season in January 2019 to bring the current system capacity to 570,000 barrels per day.
The North Texas natural gas pipeline 160,000 MMBtu per day expansion was placed in service in January 2019.
Mariner East 2, a 350-mile NGL pipeline, was placed into service for both intrastate and interstate service in December 2018.
Construction of a 150,000 barrel per day fractionator (Frac VII) at Mont Belvieu and Lone Star Express 352-mile NGL pipeline expansion were announced in November 2018.
Financial
In January 2019, ET announced a quarterly distribution of $0.305 per unit ($1.220 annualized) on ET common units for the quarter ended December 31, 2018.
In January 2019, ETO issued an aggregate $4.00 billion principal amount of senior notes and used the net proceeds to repay in full ET’s outstanding senior secured term loan, redeem certain outstanding senior notes at maturity, repay a portion of the borrowings outstanding under ET’s revolving credit facility and for general partnership purposes.

1



As of December 31, 2018, ETO’s $6.00 billion revolving credit facilities had an aggregate $2.24 billion of available capacity, and ETO’s leverage ratio, as defined by its credit agreement, was 3.38x.
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 a quarter of the Partnership’s consolidated Adjusted EBITDA in 2018. 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, February 21, 2019 to discuss its fourth 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 the Partnership’s website for a limited time.
Subsequent to the Merger, substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in the limited and general partner interests in Sunoco LP and USA Compression Partners LP (“USAC”), as well as its ownership of Lake Charles LNG Company, LLC (“Lake Charles LNG”).
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 U.S. 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, natural gas liquids (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., formerly known as Energy Transfer Partners, L.P., also owns 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 39.7 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 that distributes motor fuel to approximately 10,000 convenience stores, independent dealers, commercial customers and distributors located in more than 30 states. 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)
 
December 31, 2018
 
December 31, 2017
ASSETS
 
 
 
Current assets
$
6,750

 
$
10,683

 
 
 
 
Property, plant and equipment, net
66,963

 
61,088

 
 
 
 
Advances to and investments in unconsolidated affiliates
2,642

 
2,705

Other non-current assets, net
1,006

 
886

Intangible assets, net
6,000

 
6,116

Goodwill
4,885

 
4,768

Total assets
$
88,246

 
$
86,246

LIABILITIES AND EQUITY
 
 
 
Current liabilities
$
9,310

 
$
7,897

 
 
 
 
Long-term debt, less current maturities
43,373

 
43,671

Non-current derivative liabilities
104

 
145

Deferred income taxes
2,926

 
3,315

Other non-current liabilities
1,184

 
1,217

 
 
 
 
Commitments and contingencies
 
 
 
Redeemable noncontrolling interests
499

 
21

 
 
 
 
Equity:
 
 
 
Total partners’ capital (deficit)
20,559

 
(1,196
)
Noncontrolling interest
10,291

 
31,176

Total equity
30,850

 
29,980

Total liabilities and equity
$
88,246

 
$
86,246


3



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,
 
2018
 
2017
 
2018
 
2017
REVENUES
$
13,573

 
$
11,451

 
$
54,087

 
$
40,523

COSTS AND EXPENSES:
 
 
 
 
 
 
 
Cost of products sold
9,977

 
8,721

 
41,658

 
30,966

Operating expenses
809

 
704

 
3,089

 
2,644

Depreciation, depletion and amortization
750

 
677

 
2,859

 
2,554

Selling, general and administrative
187

 
119

 
702

 
599

Impairment losses
431

 
940

 
431

 
1,039

Total costs and expenses
12,154

 
11,161

 
48,739

 
37,802

OPERATING INCOME
1,419

 
290

 
5,348

 
2,721

OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Interest expense, net of interest capitalized
(544
)
 
(482
)
 
(2,055
)
 
(1,922
)
Equity in earnings (losses) of unconsolidated affiliates
86

 
(84
)
 
344

 
144

Impairment of investment in unconsolidated affiliate

 
(313
)
 

 
(313
)
Losses on extinguishments of debt
(6
)
 
(64
)
 
(112
)
 
(89
)
Gains (losses) on interest rate derivatives
(70
)
 
(9
)
 
47

 
(37
)
Other, net
(35
)
 
73

 
62

 
206

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)
850

 
(589
)
 
3,634

 
710

Income tax expense (benefit) from continuing operations
(2
)
 
(1,747
)
 
4

 
(1,833
)
INCOME FROM CONTINUING OPERATIONS
852

 
1,158

 
3,630

 
2,543

Income (loss) from discontinued operations, net of income taxes

 
10

 
(265
)
 
(177
)
NET INCOME
852

 
1,168

 
3,365

 
2,366

Less: Net income attributable to noncontrolling interest
220

 
917

 
1,632

 
1,412

Less: Net income attributable to redeemable noncontrolling interests
15

 

 
39

 

NET INCOME ATTRIBUTABLE TO PARTNERS
617

 
251

 
1,694

 
954

Convertible Unitholders’ interest in income

 
12

 
33

 
37

General Partner’s interest in net income

 

 
3

 
2

Limited Partners’ interest in net income
$
617

 
$
239

 
$
1,658

 
$
915

NET INCOME PER LIMITED PARTNER UNIT:
 
 
 
 
 
 
 
Basic
$
0.26

 
$
0.22

 
$
1.16

 
$
0.85

Diluted
$
0.26

 
$
0.22

 
$
1.15

 
$
0.83

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING:
 
 
 
 
 
 
 
Basic
2,332.1

 
1,079.2

 
1,423.8

 
1,078.2

Diluted
2,339.4

 
1,151.5

 
1,461.4

 
1,150.8


4



ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
(Dollars and units in millions)
(unaudited)
 
Three Months Ended
December 31,
 
Year Ended
December 31,
 
2018
 
2017
 
2018
 
2017
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (a) (b):
 
 
 
 
 
 
 
Net income
$
852

 
$
1,168

 
$
3,365

 
$
2,366

(Income) loss from discontinued operations

 
(10
)
 
265

 
177

Interest expense, net
544

 
482

 
2,055

 
1,922

Impairment losses
431

 
940

 
431

 
1,039

Income tax expense (benefit) from continuing operations
(2
)
 
(1,747
)
 
4

 
(1,833
)
Depreciation, depletion and amortization
750

 
677

 
2,859

 
2,554

Non-cash compensation expense
23

 
23

 
105

 
99

(Gains) losses on interest rate derivatives
70

 
9

 
(47
)
 
37

Unrealized (gains) losses on commodity risk management activities
(244
)
 
(37
)
 
11

 
(59
)
Losses on extinguishments of debt
6

 
64

 
112

 
89

Inventory valuation adjustments
135

 
(16
)
 
85

 
(24
)
Impairment of investment in an unconsolidated affiliate

 
313

 

 
313

Equity in (earnings) losses of unconsolidated affiliates
(86
)
 
84

 
(344
)
 
(144
)
Adjusted EBITDA related to unconsolidated affiliates
152

 
162

 
655

 
716

Adjusted EBITDA from discontinued operations

 
44

 
(25
)
 
223

Other, net
38

 
(79
)
 
(21
)
 
(155
)
Adjusted EBITDA (consolidated)
2,669

 
2,077

 
9,510

 
7,320

Adjusted EBITDA related to unconsolidated affiliates
(152
)
 
(162
)
 
(655
)
 
(716
)
Distributable Cash Flow from unconsolidated affiliates
95

 
102

 
407

 
431

Interest expense, net
(544
)
 
(497
)
 
(2,057
)
 
(1,958
)
Subsidiary preferred unitholders’ distributions
(54
)
 
(12
)
 
(170
)
 
(12
)
Current income tax expense
(7
)
 
(10
)
 
(472
)
 
(39
)
Transaction-related income taxes

 

 
470

 

Maintenance capital expenditures
(137
)
 
(157
)
 
(510
)
 
(479
)
Other, net
19

 
5

 
49

 
67

Distributable Cash Flow (consolidated)
1,889

 
1,346

 
6,572

 
4,614

Distributable Cash Flow attributable to Sunoco LP (100%)
(115
)
 
(89
)
 
(446
)
 
(449
)
Distributions from Sunoco LP
43

 
68

 
166

 
259

Distributable Cash Flow attributable to USAC (100%)
(55
)
 

 
(148
)
 

Distributions from USAC
21

 

 
73

 

Distributable Cash Flow attributable to PennTex Midstream Partners, LP (“PennTex”) (100%) (c)

 

 

 
(19
)
Distributions from PennTex to ETO (c)

 

 

 
8

Distributable Cash Flow attributable to noncontrolling interest in other non-wholly-owned consolidated subsidiaries
(294
)
 
(151
)
 
(874
)
 
(350
)
Distributable Cash Flow attributable to the partners of ET – pro forma for the Merger (a)
1,489

 
1,174

 
5,343

 
4,063

Transaction-related expenses
27

 
4

 
52

 
57

Distributable Cash Flow attributable to the partners of ET, as adjusted – pro forma for the Merger (a)
$
1,516

 
$
1,178

 
$
5,395

 
$
4,120


5



 
Three Months Ended
December 31,
 
Year Ended
December 31,
 
2018
 
2017
 
2018
 
2017
Distributions to partners – pro forma for the Merger (a):
 
 
 
 
 
 
 
Limited Partners (d)
$
799

 
$
708

 
$
3,104

 
$
2,669

General Partner
1

 
1

 
4

 
4

Total distributions to be paid to partners
$
800

 
$
709

 
$
3,108

 
$
2,673

Common Units outstanding – end of period – pro forma for the Merger (a)
2,619.4

 
2,532.5

 
2,619.4

 
2,532.5

Distribution coverage ratio – pro forma for the Merger (a)(b)
1.90x

 
1.66x

 
1.74x

 
1.54x

(a)
The closing of the Merger (as discussed above) 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. In order to provide information on a comparable basis for pre-Merger and post-Merger periods, the Partnership has included certain pro forma information.
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, as follows).
Distributions from Sunoco LP and USAC include distributions to both ET and ETO.
Distributions from PennTex are separately included in Distributable Cash Flow attributable to partners.
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 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.
For the year ended December 31, 2017, the calculation of Distributable Cash Flow and the amounts reflected for distributions to partners and common units outstanding also reflect the pro forma impacts of the Sunoco Logistics Merger as though the merger had occurred on January 1, 2017.
(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, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on our proportionate ownership.

6



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, 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 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 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)
Beginning with the second quarter of 2017, PennTex became a wholly-owned subsidiary of ETO.  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.
(d)
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.

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 and currently reflect the following segments.
 
Three Months Ended
December 31,
 
2018
 
2017
Segment Adjusted EBITDA:
 
 
 
Intrastate transportation and storage
$
306

 
$
146

Interstate transportation and storage
479

 
342

Midstream
402

 
393

NGL and refined products transportation and services
569

 
433

Crude oil transportation and services
636

 
544

Investment in Sunoco LP
180

 
158

Investment in USAC
104

 

All other
(7
)
 
61

Total Segment Adjusted EBITDA
$
2,669

 
$
2,077

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.

8



Following is a reconciliation of Segment Margin to operating income, as reported in the Partnership’s consolidated statements of operations:
 
Three Months Ended
December 31,
 
2018
 
2017
Segment Margin:
 
 
 
Intrastate transportation and storage
$
350

 
$
205

Interstate transportation and storage
495

 
317

Midstream
609

 
568

NGL and refined products transportation and services
840

 
582

Crude oil transportation and services
939

 
683

Investment in Sunoco LP
183

 
277

Investment in USAC
149

 

All other
45

 
102

Intersegment eliminations
(14
)
 
(4
)
Total segment margin
3,596

 
2,730

 
 
 
 
Less:
 
 
 
Operating expenses
809

 
704

Depreciation, depletion and amortization
750

 
677

Selling, general and administrative
187

 
119

Impairment losses
431

 
940

Operating income
$
1,419

 
$
290

Intrastate Transportation and Storage
 
Three Months Ended
December 31,
 
2018
 
2017
Natural gas transported (BBtu/d)
11,708

 
8,944

Revenues
$
1,127

 
$
741

Cost of products sold
777

 
536

Segment margin
350

 
205

Unrealized (gains) losses on commodity risk management activities
5

 
(21
)
Operating expenses, excluding non-cash compensation expense
(48
)
 
(44
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(7
)
 
(5
)
Adjusted EBITDA related to unconsolidated affiliates
6

 
11

Segment Adjusted EBITDA
$
306

 
$
146

Transported volumes increased primarily due to favorable market pricing spreads, as well as the impact of reflecting Regency Intrastate Gas LP (“RIGS”) as a consolidated subsidiary. RIGS was previously reflected as an unconsolidated affiliate until ETO acquired the remaining interest in April 2018.
Segment Adjusted EBITDA. For the three months ended December 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 $154 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; and
a net increase of $13 million due to the consolidation of RIGS beginning in April 2018, resulting in increases in transportation fees, retained fuel revenues, operating expenses, and selling, general and administrative expenses of $24 million, $2 million,

9



$5 million and $2 million, respectively, and a decrease of $6 million in Adjusted EBITDA related to unconsolidated affiliates; partially offset by
a decrease of $7 million in realized storage margin primarily due to lower realized derivative gains; and
a decrease of $2 million in transportation fees, excluding the impact of consolidating RIGS as discussed above, primarily due to a non-recurring adjustment to a transportation services agreement, partially offset by Red Bluff Express coming online and new contracts.
Interstate Transportation and Storage
 
Three Months Ended
December 31,
 
2018
 
2017
Natural gas transported (BBtu/d)
11,062

 
7,185

Natural gas sold (BBtu/d)
18

 
18

Revenues
$
495

 
$
317

Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(120
)
 
(80
)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(8
)
 
(7
)
Adjusted EBITDA related to unconsolidated affiliates
118

 
115

Other
(6
)
 
(3
)
Segment Adjusted EBITDA
$
479

 
$
342

Transported volumes reflected an increase of 2,223 BBtu/d as a result of the initiation of service on the Rover pipeline; increases of 506 BBtu/d and 475 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to increased utilization of higher contracted capacity; an increase of 309 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale; and an increase of 264 BBtu/d on the Transwestern pipeline as a result of favorable market opportunities in the West, midcontinent, and Waha areas from the Permian supply basin.
Segment Adjusted EBITDA. For the three months ended December 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 impacts of the following:
an increase of $112 million associated with the Rover pipeline with increases of $149 million in revenues, $35 million in net operating expenses and $2 million in selling, general and administrative expenses;
an aggregate increase of $29 million in revenues, excluding the incremental revenue related to the Rover pipeline discussed above, primarily due to capacity sold at higher rates on the Transwestern, Panhandle and Trunkline pipelines;
an increase of $3 million in Adjusted EBITDA related to unconsolidated affiliates primarily related to higher sales of capacity on Citrus; and
a decrease of $1 million in selling, general and administrative expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to a reduction in insurance reserves; partially offset by
an increase of $5 million in operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to system gas expenses and increases in maintenance project costs due to scope and level of activity.

10



Midstream
 
Three Months Ended
December 31,
 
2018
 
2017
Gathered volumes (BBtu/d)
12,827

 
11,525

NGLs produced (MBbls/d)
558

 
505

Equity NGLs (MBbls/d)
25

 
27

Revenues
$
1,781

 
$
1,926

Cost of products sold
1,172

 
1,358

Segment margin
609

 
568

Unrealized losses on commodity risk management activities

 
3

Operating expenses, excluding non-cash compensation expense
(193
)
 
(168
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(22
)
 
(18
)
Adjusted EBITDA related to unconsolidated affiliates
8

 
8

Segment Adjusted EBITDA
$
402

 
$
393

Gathered volumes and NGL production increased primarily due to increases in the North Texas, Permian and Northeast regions, partially offset by smaller declines in other regions.
Segment Adjusted EBITDA. For the three months ended December 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 $49 million in fee-based margin due to growth in the North Texas, Permian and Northeast regions, offset by declines in the Ark-La-Tex and midcontinent/Panhandle regions; and
an increase of $14 million in non-fee-based margin due to increased throughput volume in the North Texas and Permian regions; partially offset by
a decrease of $25 million in non-fee-based margin primarily due to lower NGL prices;
an increase of $25 million in operating expenses due to an increase of $8 million in materials, $6 million in outside services, $6 million in ad valorem taxes and $5 million in expense projects; and
an increase of $4 million in selling, general and administrative expenses due to a change in capitalized overhead.

11



NGL and Refined Products Transportation and Services
 
Three Months Ended
December 31,
 
2018
 
2017
NGL transportation volumes (MBbls/d)
1,115

 
963

Refined products transportation volumes (MBbls/d)
601

 
618

NGL and refined products terminal volumes (MBbls/d)
898

 
792

NGL fractionation volumes (MBbls/d)
594

 
455

Revenues
$
2,946

 
$
2,533

Cost of products sold
2,106

 
1,951

Segment margin
840

 
582

Unrealized gains on commodity risk management activities
(112
)
 
(28
)
Operating expenses, excluding non-cash compensation expense
(156
)
 
(120
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(22
)
 
(15
)
Adjusted EBITDA related to unconsolidated affiliates
19

 
14

Segment Adjusted EBITDA
$
569

 
$
433

NGL transportation volumes increased primarily due to increased volumes from the Permian region resulting from a ramp up in production from existing customers, higher throughput volumes on Mariner West driven by end user facility constraints in the prior period and higher throughput from Mariner South resulting from increased export volumes. Refined products transportation volumes decreased primarily due to the timing of turnarounds at third-party refineries in the Midwest and Northeast regions.
NGL and refined products terminal volumes increased primarily due to more volumes loaded at our Nederland terminal as export demand increased, as well as higher throughput volumes at our Marcus Hook Industrial Complex.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased primarily due to increased volumes from the Permian region, as well as an increase in fractionation capacity as our fifth fractionator at Mont Belvieu came online in July 2018.
Segment Adjusted EBITDA. For the three months ended December 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 impacts of the following:
an increase of $85 million in transportation margin primarily due to a $70 million increase resulting from higher producer volumes from the Permian region on our Texas NGL pipelines, a $9 million increase due to higher throughput volumes on Mariner West driven by end-user facility constraints in the prior period, a $5 million increase due to higher throughput volumes from the Barnett region, a $4 million increase resulting from a reclassification between our transportation and fractionation margins and a $3 million increase due to higher throughput volumes on Mariner South as a result of increased export volumes. These increases were partially offset by a $6 million decrease resulting from the timing of deficiency revenue recognition;
an increase of $32 million in fractionation and refinery services margin primarily due to a $43 million increase resulting from the commissioning of our fifth fractionator in July 2018 and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a $5 million decrease in blending gains as a result of less favorable market pricing, a $4 million decrease resulting from a reclassification between our transportation and fractionation margins and a $2 million decrease from planned downtime at a customer facility that lowered the supply to our refinery services facility;
an increase of $28 million in marketing margin due to a $31 million increase from our butane blending operations and an $12 million increase in NGL sales from our Marcus Hook Industrial Complex. These increases were partially offset by a $15 million decrease from the timing of optimization gains from our Mont Belvieu fractionators; and
an increase of $26 million in terminal services margin due to a $13 million increase from higher throughput at our Marcus Hook Industrial Complex, an $11 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses and a $2 million increase at our Nederland terminal due to increased export demand; partially offset by

12



an increase of $36 million in operating expenses primarily due to a $14 million increase in operating costs primarily due to higher throughput on our NGL pipelines and fractionators and the commissioning of our fifth fractionator in July 2018, an $11 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, a $3 million increase in costs relating to an outside storage lease and a $3 million increase in certain allocated overhead costs; and
an increase of $7 million in selling, general and administrative expenses due to a $6 million increase in overhead costs allocated to the segment and $1 million increase in legal fees.
Crude Oil Transportation and Services
 
Three Months Ended
December 31,
 
2018
 
2017
Crude transportation volumes (MBbls/d)
4,330

 
3,872

Crude terminals volumes (MBbls/d)
2,202

 
2,059

Revenues
$
4,346

 
$
3,938

Cost of products sold
3,407

 
3,255

Segment margin
939

 
683

Unrealized (gains) losses on commodity risk management activities
(132
)
 
4

Operating expenses, excluding non-cash compensation expense
(150
)
 
(125
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(22
)
 
(20
)
Adjusted EBITDA related to unconsolidated affiliates
1

 
2

Segment Adjusted EBITDA
$
636

 
$
544

Crude transportation volumes increased due to placing the Bakken pipeline in service in June 2017 as well as higher throughput on existing pipelines due to increased production in West Texas. Crude terminal volumes benefited from an increase in barrels delivered to our Nederland crude terminal from the Bakken pipeline and from increased West Texas production.
Segment Adjusted EBITDA. For the three months ended December 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 net impacts of the following:
an increase of $120 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to the following: a $102 million increase resulting from higher throughput on the Bakken pipeline and a $125 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from Permian producers. These increases were partially offset by a $107 million decrease to segment margin (excluding a net change of $136 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business; partially offset by
an increase of $25 million in operating expenses due to a $23 million increase due to higher throughput related expenses on existing assets and a $2 million increase from the expansion of our Permian Express 3 pipeline in service in the fourth quarter of 2018; and
an increase of $2 million in selling, general and administrative expenses primarily due to increases in allocated shared service charges.

13



Investment in Sunoco LP
 
Three Months Ended
December 31,
 
2018
 
2017
Revenues
$
3,877

 
$
2,959

Cost of products sold
3,694

 
2,682

Segment margin
183

 
277

Unrealized losses on commodity risk management activities
5

 
2

Operating expenses, excluding non-cash compensation expense
(111
)
 
(113
)
Selling, general and administrative, excluding non-cash compensation expense
(36
)
 
(36
)
Inventory fair value adjustments
135

 
(16
)
Adjusted EBITDA from discontinued operations

 
44

Other, net
4

 

Segment Adjusted EBITDA
$
180

 
$
158

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended December 31, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP increased due to the net impacts of the following:
an increase of $60 million in margin (excluding a $154 million change in inventory fair value adjustments and unrealized losses on commodity risk management activities) primarily due to increases in fuel margins and fuel volumes; partially offset by
a decrease of $44 million in Adjusted EBITDA from discontinued operations primarily due to Sunoco LP’s retail divestment in January 2018.
Investment in USAC
 
Three Months Ended
December 31,
 
2018
 
2017
Revenues
$
172

 
$

Cost of products sold
23

 

Segment margin
149

 

Operating expenses, excluding non-cash compensation expense
(30
)
 

Selling, general and administrative, excluding non-cash compensation expense
(16
)
 

Other, net
1

 

Segment Adjusted EBITDA
$
104

 
$

Amounts reflected above for the three months ended December 31, 2018 represents the consolidated results of operations for USAC. Changes between periods are due to the consolidation of USAC beginning April 2, 2018.

14



All Other
 
Three Months Ended
December 31,
 
2018
 
2017
Revenues
$
630

 
$
652

Cost of products sold
585

 
550

Segment margin
45

 
102

Unrealized (gains) losses on commodity risk management activities
(11
)
 
3

Operating expenses, excluding non-cash compensation expense
(6
)
 
(31
)
Selling, general and administrative expenses, excluding non-cash compensation expense
(41
)
 
(28
)
Adjusted EBITDA related to unconsolidated affiliates

 
12

Other and eliminations
6

 
3

Segment Adjusted EBITDA
$
(7
)
 
$
61

Segment Adjusted EBITDA. For the three months ended December 31, 2018 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 $35 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;
a decrease of $29 million due to merger and acquisition expenses related to the Merger in 2018;
a decrease of $13 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in PES primarily due to our lower ownership in PES subsequent to its reorganization, which resulted in PES no longer being reflected as an affiliate beginning in the third quarter of 2018; and
a decrease of $6 million due to a decrease in power trading gains; partially offset by
an increase of $5 million in joint venture management fees; and
an increase of $4 million from transport fees and gains from storage and park and loan activity.

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 which incurred certain changes in connection with the Merger. We also have consolidated subsidiaries with revolving credit facilities which are not included.
 
Facility Size
 
Funds Available at December 31, 2018
 
Maturity Date
ETO Five-Year Revolving Credit Facility
$
5,000

 
$
1,243

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

 
1,000

 
November 30, 2019
 
$
6,000

 
$
2,243

 
 

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,
 
2018
 
2017
Equity in earnings (losses) of unconsolidated affiliates:
 
 
 
Citrus
$
39

 
$
58

FEP
14

 
14

MEP
7

 
9

HPC (1)(2)

 
(185
)
Other
26

 
20

Total equity in earnings (losses) of unconsolidated affiliates
$
86

 
$
(84
)
 
 
 
 
Adjusted EBITDA related to unconsolidated affiliates:
 
 
 
Citrus
$
81

 
$
74

FEP
18

 
19

MEP
19

 
22

HPC (2)

 
6

Other
34

 
41

Total Adjusted EBITDA related to unconsolidated affiliates
$
152

 
$
162

 
 
 
 
Distributions received from unconsolidated affiliates:
 
 
 
Citrus
$
46

 
$
43

FEP
18

 
19

MEP
8

 
8

HPC (2)

 
13

Other
35

 
22

Total distributions received from unconsolidated affiliates
$
107

 
$
105

(1) 
For the three months ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
(2) 
The partnership previously owned a 49.99% interest in HPC, which owns RIGS. In April 2018, we acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in our financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in our financial statements.


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,
 
2018
 
2017
Adjusted EBITDA of non-wholly-owned subsidiaries (100%) (a)
$
669

 
$
381

Our proportionate share of Adjusted EBITDA of non-wholly-owned subsidiaries (b)
351

 
212

 
 
 
 
Distributable Cash Flow of non-wholly-owned subsidiaries (100%) (c)
$
626

 
$
346

Our proportionate share of Distributable Cash Flow of non-wholly-owned subsidiaries (d)
332

 
194

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
%
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