Energy Transfer LP

Equities

ET

US29273V1008

Oil & Gas Transportation Services

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ENERGY TRANSFER LP : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-K)

February 21, 2020 at 01:50 pm EST

(Tabular dollar and unit amounts, except per unit data, are in millions) Energy Transfer LP is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol "ET." ET was formed in September 2002 and completed its initial public offering in February 2006.

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The following discussion of our historical consolidated financial condition and
results of operations should be read in conjunction with our historical
consolidated financial statements and accompanying notes thereto included in
"Item 8. Financial Statements and Supplementary Data" of this report. This
discussion includes forward-looking statements that are subject to risk and
uncertainties. Actual results may differ substantially from the statements we
make in this section due to a number of factors that are discussed in "Item 1A.
Risk Factors" of this report.
Unless the context requires otherwise, references to "we," "us," "our," the
"Partnership" and "ET" mean Energy Transfer LP and its consolidated
subsidiaries, which include ETO, ETP GP, ETP LLC, Panhandle, Sunoco LP and Lake
Charles LNG. References to the "Parent Company" mean Energy Transfer LP on a
stand-alone basis.
OVERVIEW
Energy Transfer LP directly and indirectly owns equity interests in ETO, Sunoco
LP and USAC, all of which are limited partnerships engaged in diversified
energy-related services. Sunoco LP and USAC have publicly traded common units.
The Parent Company's principal sources of cash flow are derived from its direct
and indirect investments in the limited partner and general partner interests in
ETO. ETO's earnings and cash flows are generated by its subsidiaries, including
ETO's investments in Sunoco LP and USAC. The amount of cash that ETO, Sunoco LP
and USAC distribute to their respective partners, including the Parent Company,
each quarter is based on earnings from their respective business activities and
the amount of available cash, as discussed below.
In order to fully understand the financial condition and results of operations
of the Parent Company on a stand-alone basis, we have included discussions of
Parent Company matters apart from those of our consolidated group.
General
Our primary objective is to increase the level of our distributable cash flow to
our unitholders over time by pursuing a business strategy that is currently
focused on growing our subsidiaries' natural gas and liquids businesses through,
among other things, pursuing certain construction and expansion opportunities
relating to our subsidiaries' existing infrastructure and acquiring certain
strategic operations and businesses or assets. The actual amounts of cash that
we will have available for distribution will primarily depend on the amount of
cash our subsidiaries generate from their operations.
Our reportable segments are as follows:
• intrastate transportation and storage;

• interstate transportation and storage;

• midstream;

• NGL and refined products transportation and services;

• crude oil transportation and services;

• investment in Sunoco LP;

• investment in USAC; and

• all other.




The general partner of ETO has separate operating management and boards of
directors. We control ETO through our owner ship of its respective general
partners.
Recent Developments
ETO Series F and Series G Preferred Units Issuance
On January 22, 2020, ETO issued 500,000 of its 6.750% Series F Preferred Units
at a price of $1,000 per unit and 1,100,000 of its 7.125% Series G Preferred
Units at a price of $1,000 per unit. The net proceeds were used to repay amounts
outstanding under ETO's revolving credit facility and for general partnership
purposes.
ETO January 2020 Senior Notes Offering and Redemption
On January 22, 2020, ETO completed a registered offering (the "January 2020
Senior Notes Offering") of $1.00 billion aggregate principal amount of ETO's
2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of ETO's
3.750% Senior Notes due 2030, and $2.00 billion aggregate principal amount of
ETO's 5.000% Senior Notes due 2050, (collectively, the "Notes").

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The Notes are fully and unconditionally guaranteed by the Partnership's
wholly-owned subsidiary, Sunoco Logistics Partners Operations L.P., on a senior
unsecured basis.
Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its
$400 million aggregate principal amount of 5.75% Senior Notes due September 1,
2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due
October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior
Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50%
Senior Notes due February 15, 2020, ET's $52 million aggregate principal amount
of 7.50% Senior Notes due October 15, 2020 and Transwestern's $175 million
aggregate principal amount of 5.36% Senior Notes due December 9, 2020.
ETO Term Loan
On October 17, 2019, ETO entered into a term loan credit agreement (the "ETO
Term Loan") providing for a $2.00 billion three-year term loan credit facility.
Borrowings under the term loan agreement mature on October 17, 2022 and are
available for working capital purposes and for general partnership purposes. The
term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco
Logistics Partners Operations L.P.
As of December 31, 2019, the ETO Term Loan had $2.00 billion outstanding and was
fully drawn. The weighted average interest rate on the total amount outstanding
as of December 31, 2019 was 2.78%.
SemGroup Acquisition and ET Contribution of SemGroup Assets to ETO
On December 5, 2019, ET completed the acquisition of SemGroup pursuant to the
terms of the Agreement and Plan of Merger, dated as of September 15, 2019 (the
"Merger Agreement"). Under the terms of the Merger Agreement, a wholly owned
subsidiary of ET merged with and into SemGroup (the "SemGroup Transaction"),
with SemGroup surviving the Merger. At the effective time of the SemGroup
Transaction on December 5, 2019, each share of class A common stock, par value
$0.01 per share, of SemGroup issued and outstanding immediately prior to the
effective time was converted into the right to receive (i) $6.80 in cash,
without interest, and (ii) 0.7275 ET Common Units representing limited partner
interests in ET. Each share of Series A Cumulative Perpetual Convertible
Preferred Stock, par value $0.01 per share, of SemGroup that was issued and
outstanding as of immediately prior to the effective time was redeemed by
SemGroup for cash at a price per share equal to 101% of the liquidation
preference.
During the first quarter of 2020, ET contributed certain SemGroup assets to ETO
through sale and contribution transactions.
JC Nolan Pipeline
On July 1, 2019, ETO and Sunoco LP entered into a joint venture on the JC Nolan
diesel fuel pipeline to West Texas and the JC Nolan terminal. ETO operates the
pipeline for the joint venture, which transports diesel fuel from Hebert, Texas
to a terminal in the Midland, Texas area. The diesel fuel pipeline has an
initial capacity of 30,000 barrels per day and was successfully commissioned in
August 2019.
Series E Preferred Units Issuance
In April 2019, ETO issued 32 million of its 7.600% Series E Preferred Units at a
price of $25 per unit, including 4 million Series E Preferred Units pursuant to
the underwriters' exercise of their option to purchase additional preferred
units. The total gross proceeds from the Series E Preferred Unit issuance were
$800 million, including $100 million from the underwriters' exercise of their
option to purchase additional preferred units. The net proceeds were used to
repay amounts outstanding under ETO's revolving credit facility and for general
partnership purposes.
ET-ETO Senior Notes Exchange
In March 2019, ETO issued approximately $4.21 billion aggregate principal amount
of senior notes to settle and exchange approximately 97% of ET's outstanding
senior notes. In connection with this exchange, ETO issued $1.14 billion
aggregate principal amount of 7.50% senior notes due 2020, $995 million
aggregate principal amount of 4.25% senior notes due 2023, $1.13 billion
aggregate principal amount of 5.875% senior notes due 2024 and $956 million
aggregate principal amount of 5.50% senior notes due 2027.
ETO 2019 Senior Notes Offering and Redemption
In January 2019, ETO issued $750 million aggregate principal amount of 4.50%
senior notes due 2024, $1.50 billion aggregate principal amount of 5.25% senior
notes due 2029 and $1.75 billion aggregate principal amount of 6.25% senior
notes due 2049. The $3.96 billion net proceeds from the offering were used to
repay in full ET's outstanding senior secured term loan, to redeem outstanding
senior notes, to repay a portion of the borrowings under the Partnership's
revolving credit facility and for general partnership purposes.

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Panhandle Senior Notes Redemption
In June 2019, Panhandle's $150 million aggregate principal amount of 8.125%
senior notes matured and were repaid with borrowings under an affiliate loan
agreement with ETO.
Bakken Senior Notes Offering
In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary
of Dakota Access, issued $650 million aggregate principal amount of 3.625%
senior notes due 2022, $1.00 billion aggregate principal amount of 3.90% senior
notes due 2024 and $850 million aggregate principal amount of 4.625% senior
notes due 2029. The $2.48 billion in net proceeds from the offering were used to
repay in full all amounts outstanding on the Bakken credit facility and the
facility was terminated.
Sunoco LP Senior Notes Offering
In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00%
senior notes due 2027 in a private placement to eligible purchasers. The net
proceeds from this offering were used to repay a portion of Sunoco LP's existing
borrowings under its credit facility. In July 2019, Sunoco LP completed an
exchange of these notes for registered notes with substantially identical terms.
USAC Senior Notes Offering
In March 2019, USAC issued $750 million aggregate principal amount of 6.875%
senior notes due 2027 in a private placement, and in December 2019, USAC
exchanged those notes for substantially identical senior notes registered under
the Securities Act. The net proceeds from this offering were used to repay a
portion of USAC's existing borrowings under its credit facility and for general
partnership purposes.
Regulatory Update
Interstate Natural Gas Transportation Regulation
Rate Regulation
Effective January 2018, the 2017 Tax and Jobs Act (the "Tax Act") changed
several provisions of the federal tax code, including a reduction in the maximum
corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC
addressed treatment of federal income tax allowances in regulated entity rates.
The FERC issued a Revised Policy Statement on Treatment of Income Taxes
("Revised Policy Statement") stating that it will no longer permit master
limited partnerships to recover an income tax allowance in their cost of service
rates. The FERC issued the Revised Policy Statement in response to a remand from
the United States Court of Appeals for the District of Columbia Circuit in
United Airlines v. FERC, in which the court determined that the FERC had not
justified its conclusion that a pipeline organized as a master limited
partnership would not "double recover" its taxes under the current policy by
both including an income-tax allowance in its cost of service and earning a
return on equity calculated using the discounted cash flow methodology. On July
18, 2018, the FERC issued an order denying requests for rehearing and
clarification of its Revised Policy Statement. In the rehearing order, the FERC
clarified that a pipeline organized as a master limited partnership will not be
not be precluded in a future proceeding from arguing and providing evidentiary
support that it is entitled to an income tax allowance and demonstrating that
its recovery of an income tax allowance does not result in a double-recovery of
investors' income tax costs. In light of the rehearing order, the impacts of the
FERC's policy on the treatment of income taxes may have on the rates ETO can
charge for the FERC-regulated transportation services are unknown at this time.
The FERC also issued a Notice of Inquiry ("2017 Tax Law NOI") on March 15, 2018,
requesting comments on the effect of the Tax Act on FERC jurisdictional rates.
The 2017 Tax Law NOI states that of particular interest to the FERC is whether,
and if so how, the FERC should address changes relating to accumulated deferred
income taxes and bonus depreciation. Comments in response to the 2017 Tax Law
NOI were due on or before May 21, 2018.
In March 2019, following the decision of the D.C. Circuit in Emera Maine v.
Federal Energy Regulatory Commission, the FERC issued a Notice of Inquiry
regarding its policy for determining return on equity ("ROE"). The FERC
specifically sought information and stakeholder views to help the FERC explore
whether, and if so how, it should modify its policies concerning the
determination of ROE to be used in designing jurisdictional rates charged by
public utilities. The FERC also expressly sought comment on whether any changes
to its policies concerning public utility ROEs should be applied to interstate
natural gas and oil pipelines. Initial comments were due in June 2019, and reply
comments were due in July 2019. The FERC has not taken any further action with
respect to the Notice of Inquiry as of this time, and therefore we cannot
predict what effect, if any, such development could have on our cost-of-service
rates in the future.

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Also included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking
("NOPR") proposing rules for implementation of the Revised Policy Statement and
the corporate income tax rate reduction with respect to natural gas pipeline
rates. On July 18, 2018, the FERC issued a Final Rule adopting procedures that
are generally the same as proposed in the NOPR with a few clarifications and
modifications. With limited exceptions, the Final Rule requires all
FERC-regulated natural gas pipelines that have cost-based rates for service to
make a one-time Form No. 501-G filing providing certain financial information
and to make an election on how to treat its existing rates. The Final Rule
suggests that this information will allow the FERC and other stakeholders to
evaluate the impacts of the Tax Act and the Revised Policy Statement on each
individual pipeline's rates. The Final Rule also requires that each
FERC-regulated natural gas pipeline select one of four options to address
changes to the pipeline's revenue requirements as a result of the tax
reductions: file a limited Natural Gas Act ("NGA") Section 4 filing reducing its
rates to reflect the reduced tax rates, commit to filing a general NGA Section 4
rate case in the near future, file a statement explaining why an adjustment to
rates is not needed, or take no other action. For the limited NGA Section 4
option, the FERC clarified that, notwithstanding the Revised Policy Statement, a
pipeline organized as a master limited partnership does not need to eliminate
its income tax allowance but, instead, can reduce its rates to reflect the
reduction in the maximum corporate tax rate. Trunkline, ETC Tiger Pipeline, LLC
and Panhandle filed their respective FERC Form No. 501-Gs on October 11, 2018.
FEP, Lake Charles LNG and certain other operating subsidiaries filed their
respective FERC Form No. 501-Gs on or about November 8, 2018, and Rover, FGT,
Transwestern and MEP filed their respective FERC Form No. 501-Gs on or about
December 6, 2018.
By order issued January 16, 2019, the FERC initiated a review of Panhandle's
existing rates pursuant to Section 5 of the Natural Gas Act to determine whether
the rates currently charged by Panhandle are just and reasonable and set the
matter for hearing.  Panhandle filed a cost and revenue study on April 1,
2019. Panhandle filed a NGA Section 4 rate case on August 30, 2019.
By order issued October 1, 2019, the Panhandle Section 5 and Section 4 cases
were consolidated. An initial decision is expected to be issued in the first
quarter of 2021. By order issued February 19, 2019, the FERC initiated a review
of Southwest Gas' existing rates pursuant to Section 5 of the Natural Gas Act to
determine whether the rates currently charged by Southwest Gas are just and
reasonable and set the matter for hearing.  Southwest Gas filed a cost and
revenue study on May 6, 2019.  On July 10, 2019, Southwest filed an Offer of
Settlement in this Section 5 proceeding, which settlement was supported or not
opposed by Commission Trial Staff and all active parties. The settlement was
approved on October 29, 2019.
Sea Robin Pipeline Company filed a Section 4 rate case on November 30, 2018.  A
procedural schedule was ordered with a hearing date in the 4th quarter of 2019.
Sea Robin Pipeline Company has reached a settlement of this proceeding, with a
settlement filed July 22, 2019. The settlement was approved by the FERC by order
dated October 17, 2019.
Even without action on the 2017 Tax Law NOI or as contemplated in the Final
Rule, the FERC or our shippers may challenge the cost of service rates we
charge. The FERC's establishment of a just and reasonable rate is based on many
components, and tax-related changes will affect two such components, the
allowance for income taxes and the amount for accumulated deferred income taxes,
while other pipeline costs also will continue to affect the FERC's determination
of just and reasonable cost of service rates. Although changes in these two tax
related components may decrease, other components in the cost of service rate
calculation may increase and result in a newly calculated cost of service rate
that is the same as or greater than the prior cost of service rate. Moreover, we
receive revenues from our pipelines based on a variety of rate structures,
including cost of service rates, negotiated rates, discounted rates and
market-based rates. Many of our interstate pipelines, such as ETC Tiger
Pipeline, LLC, MEP and FEP, have negotiated market rates that were agreed to by
customers in connection with long-term contracts entered into to support the
construction of the pipelines. Other systems, such as FGT, Transwestern and
Panhandle, have a mix of tariff rate, discount rate, and negotiated rate
agreements. We do not expect market-based rates, negotiated rates or discounted
rates that are not tied to the cost of service rates to be affected by the
Revised Policy Statement or any final regulations that may result from the March
15, 2018 proposals. The revenues we receive from natural gas transportation
services we provide pursuant to cost of service based rates may decrease in the
future as a result of the ultimate outcome of the NOI, the Final Rule, and the
Revised Policy Statement, combined with the reduced corporate federal income tax
rate established in the Tax Act. The extent of any revenue reduction related to
our cost of service rates, if any, will depend on a detailed review of all of
ETO's cost of service components and the outcomes of any challenges to our rates
by the FERC or our shippers.
Pipeline Certification
The FERC issued a Notice of Inquiry on April 19, 2018 ("Pipeline Certification
NOI"), thereby initiating a review of its policies on certification of natural
gas pipelines, including an examination of its long-standing Policy Statement on
Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999,
that is used to determine whether to grant certificates for new pipeline
projects. We are unable to predict what, if any, changes may be proposed as a
result of the Pipeline Certification NOI that will affect our natural gas
pipeline business or when such proposals, if any, might become effective.
Comments in response to the Pipeline Certification NOI were due on or before
July 25, 2018. We do not expect that any change in this policy would affect us
in a materially different manner than any other natural gas pipeline company
operating in the United States.

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Interstate Common Carrier Regulation
The FERC utilizes an indexing rate methodology which, as currently in effect,
allows common carriers to change their rates within prescribed ceiling levels
that are tied to changes in the Producer Price Index, or PPI. The indexing
methodology is applicable to existing rates, with the exclusion of market-based
rates. The FERC's indexing methodology is subject to review every five years.
During the five-year period commencing July 1, 2016 and ending June 30, 2021,
common carriers charging indexed rates are permitted to adjust their indexed
ceilings annually by PPI plus 1.23 percent. Many existing pipelines utilize the
FERC liquids index to change transportation rates annually every July 1. With
respect to liquids and refined products pipelines subject to FERC jurisdiction,
the Revised Policy Statement requires the pipeline to reflect the impacts to its
cost of service from the Revised Policy Statement and the Tax Act on Page 700 of
FERC Form No. 6. This information will be used by the FERC in its next five year
review of the liquids pipeline index to generate the index level to be effective
July 1, 2021, thereby including the effect of the Revised Policy Statement and
the Tax Act in the determination of indexed rates prospectively, effective July
1, 2021. The FERC's establishment of a just and reasonable rate, including the
determination of the appropriate liquids pipeline index, is based on many
components, and tax related changes will affect two such components, the
allowance for income taxes and the amount for accumulated deferred income taxes,
while other pipeline costs also will continue to affect the FERC's determination
of the appropriate pipeline index. Accordingly, depending on the FERC's
application of its indexing rate methodology for the next five year term of
index rates, the Revised Policy Statement and tax effects related to the Tax Act
may impact our revenues associated with any transportation services we may
provide pursuant to cost of service based rates in the future, including indexed
rates.
Trends and Outlook
We continue to evaluate and execute strategies to enhance unitholder value
through growth, as well as the integration and optimization of our diversified
asset portfolio. We intend to target a minimum distribution coverage ratio of
1.50x, thereby promoting a prudent balance between distribution rates and
enhanced financial flexibility and strength while maintaining our investment
grade ratings. We anticipate continued earnings growth in 2020 from the recently
completed projects, as well as our current project backlog. We also continue to
seek asset optimization opportunities through strategic transactions among us
and our subsidiaries and/or affiliates, and we expect to continue to evaluate
and execute on such opportunities. As we have in the past, we will evaluate
growth projects and acquisitions as such opportunities may be identified in the
future, and we believe that the current capital markets are conducive to funding
such future projects.
With respect to commodity prices, natural gas prices have remained comparatively
low in recent months as associated gas from shale oil resources has provided
additional supply to the market, increasing domestic supply to highs above 100
Bcf/d. Global oil and natural gas demand growth is likely to continue into the
foreseeable future and will support U.S. production increases and, in turn U.S.
natural gas export projects to Mexico as well as LNG exports.
For crude oil, new pipelines that came online during 2019 have resulted in
Permian barrels now pricing closer to other regional hubs, which is a departure
from the substantial discounts seen a year ago. These pipelines have enabled
Permian producers to realize higher crude oil revenues, supporting continued
growth in the region. Crude oil exports from the U.S. are continuing to increase
as a result, providing additional opportunity for U.S. midstream sector growth.
Results of Operations
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures
of segment performance. We define Segment Adjusted EBITDA and consolidated
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. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect
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 Segment Adjusted EBITDA and consolidated 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.  The use of
Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates
as an analytical tool should be limited accordingly.
Segment Adjusted EBITDA, as reported for each segment in the table below, is
analyzed for each segment in the section titled "Segment Operating Results."
Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors,
lenders and rating agencies to assess the financial performance and the
operating results of the Partnership's fundamental business activities and

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should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures. Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018 Consolidated Results


                                                   Years Ended December 31,
                                                     2019             2018           Change
Segment Adjusted EBITDA:
Intrastate transportation and storage           $       999       $       927     $       72
Interstate transportation and storage                 1,792             1,680            112
Midstream                                             1,602             1,627            (25 )
NGL and refined products transportation and
services                                              2,666             1,979            687
Crude oil transportation and services                 2,972             2,330            642
Investment in Sunoco LP                                 665               638             27
Investment in USAC                                      420               289            131
All other                                                98                40             58
Total Segment Adjusted EBITDA                        11,214             9,510          1,704
Depreciation, depletion and amortization             (3,147 )          (2,859 )         (288 )
Interest expense, net of interest capitalized        (2,331 )          (2,055 )         (276 )
Impairment losses                                       (74 )            (431 )          357
Gains (losses) on interest rate derivatives            (241 )              47           (288 )
Non-cash compensation expense                          (113 )            (105 )           (8 )
Unrealized losses on commodity risk management
activities                                               (5 )             (11 )            6
Inventory valuation adjustments                          79               (85 )          164
Losses on extinguishments of debt                       (18 )            (112 )           94
Adjusted EBITDA related to unconsolidated
affiliates                                             (626 )            (655 )           29
Equity in earnings of unconsolidated affiliates         302               344            (42 )
Adjusted EBITDA related to discontinued
operations                                                -                25            (25 )
Other, net                                               54                21             33
Income from continuing operations before income
tax expense                                           5,094             3,634          1,460
Income tax expense from continuing operations          (195 )              (4 )         (191 )
Income from continuing operations                     4,899             3,630          1,269
Loss from discontinued operations, net of
income taxes                                              -              (265 )          265
Net income                                      $     4,899       $     3,365     $    1,534


Adjusted EBITDA (consolidated). For the year ended December 31, 2019 compared to
the prior year, Adjusted EBITDA increased approximately $1.7 billion, or 18%.
The increase was primarily due to the impact of multiple revenue-generating
assets being placed in service and recent acquisitions, as well as increased
demand for services on existing assets. The impact of new assets and
acquisitions was approximately $784 million, of which the largest increases were
from increased volumes to our Mariner East pipeline and terminal assets due to
the addition of pipeline capacity in the fourth quarter of 2018 (a $274 million
impact to the NGL and refined products transportation and services segment), the
commissioning of our fifth and sixth fractionators (a $131 million impact to the
NGL and refined products transportation and services segment), the ramp up of
volumes on our Bayou Bridge system due to placing phase II in service in the
second quarter of 2019 (a $60 million impact to our crude oil transportation and
services segment), the Rover pipeline (a $78 million impact to the interstate
transportation and storage segment), the addition of gas processing capacity to
our Arrowhead gas plant (a $31 million impact to our midstream segment), placing
our Permian Express 4 pipeline in service in October 2019 (a $26 million impact
to our crude oil transportation and services segment) and the acquisition of
USAC (a net impact of $131 million among the investment in USAC and all other
segments). The remainder of the increase in Adjusted EBITDA was primarily due to
stronger demand on existing assets, particularly due to increased throughput on
our Bakken Pipeline system as well as increased production in the Permian, which
impacted multiple segments. Additional discussion of these

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and other factors affecting Adjusted EBITDA is included in the analysis of
Segment Adjusted EBITDA in the "Segment Operating Results" section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased primarily due to additional depreciation from
assets recently placed in service and recent acquisitions.
Interest Expense, Net of Interest Capitalized. Interest expense, net of interest
capitalized, increased primarily due to the following:
•   an increase of $198 million recognized by the Partnership (excluding Sunoco

LP and USAC, which are discussed below) primarily due to increases in ETO's

long-term debt;

• an increase of $49 million recognized by USAC primarily attributable to

higher overall debt balances and higher interest rates on borrowings under

the credit agreement. These increases were partially offset by the decrease

in borrowings under the credit agreement; and

• an increase of $29 million recognized by Sunoco LP due to an increase in

total long-term debt; offset by




Impairment Losses. During the year ended December 31, 2019, the Partnership
recognized goodwill impairments of $12 million related to the Southwest Gas
operations within the interstate transportation and storage segment and $9
million related to our North Central operations within the midstream segment,
both of which were primarily due to changes in assumptions related to projected
future revenues and cash flows. Also during the year ended December 31, 2019,
Sunoco LP recognized a $47 million write-down on assets held for sale related to
its ethanol plant in Fulton, New York, and USAC recognized a $6 million fixed
asset impairment related to certain idle compressor assets.
During the year ended December 31, 2018, the Partnership recognized goodwill
impairments of $378 million and asset impairments of $4 million related to our
midstream operations and asset impairments of $9 million related to idle leased
assets in our crude operations. Sunoco LP recognized a $30 million
indefinite-lived intangible asset impairment related to contractual rights. USAC
recognized a $9 million fixed asset impairment related to certain idle
compressor assets. Additional discussion on these impairments is included in
"Estimates and Critical Accounting Policies" below.
Gains (Losses) on Interest Rate Derivatives. Our interest rate derivatives are
not designated as hedges for accounting purposes; therefore, changes in fair
value are recorded in earnings each period. Losses on interest rate derivatives
during the year ended December 31, 2019 resulted from a decrease in forward
interest rates and gains in 2018 resulted from an increase in forward interest
rates.
Unrealized Gains (Losses) on Commodity Risk Management Activities.  The
unrealized gains and losses on our commodity risk management activities include
changes in fair value of commodity derivatives and the hedged inventory included
in designated fair value hedging relationships.  Information on the unrealized
gains and losses within each segment are included in "Segment Operating Results"
below, and additional information on the commodity-related derivatives,
including notional volumes, maturities and fair values, is available in "Item
7A. Quantitative and Qualitative Disclosures About Market Risk" and in Note 13
to our consolidated financial statements included in "Item 8. Financial
Statements and Supplementary Data."
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were
recorded for the inventory associated with Sunoco LP primarily driven by changes
in fuel prices between periods.
Losses on Extinguishments of Debt. Amounts were related to Sunoco LP's senior
note and term loan redemption in January 2018.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of
Unconsolidated Affiliates. See additional information in "Supplemental
Information on Unconsolidated Affiliates" and "Segment Operation Results" below.
Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the
operations of Sunoco LP's retail business that were disposed of in January 2018.
Other, net. Other, net primarily includes amortization of regulatory assets and
other income and expense amounts.
Income Tax Expense. For the year ended December 31, 2019 compared to the same
period in the prior year, income tax expense increased due to an increase in
income before tax expense at our corporate subsidiaries and the recognition of a
favorable state tax rate change in the prior period.

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Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated
affiliates:
                                                         Years Ended December 31,
                                                            2019                   2018          Change
Equity in earnings of unconsolidated
affiliates:
Citrus                                          $        148                   $      141     $         7
FEP                                                       59                           55               4
MEP                                                       15                           31             (16 )
Other                                                     80                          117             (37 )
Total equity in earnings of unconsolidated
affiliates                                      $        302

$ 344 $ (42 )



Adjusted EBITDA related to unconsolidated
affiliates(1):
Citrus                                          $        342                   $      337     $         5
FEP                                                       75                           74               1
MEP                                                       60                           81             (21 )
Other                                                    149                          163             (14 )
Total Adjusted EBITDA related to unconsolidated
affiliates                                      $        626

$ 655 $ (29 )



Distributions received from unconsolidated
affiliates:
Citrus                                          $        178                   $      171     $         7
FEP                                                       73                           68               5
MEP                                                       36                           48             (12 )
Other                                                    101                          110              (9 )
Total distributions received from
unconsolidated affiliates                       $        388

$ 397 $ (9 )

(1) These amounts represent our proportionate share of the Adjusted EBITDA of

our unconsolidated affiliates and are based on our equity in earnings or

losses of our unconsolidated affiliates adjusted for our proportionate share

of the unconsolidated affiliates' interest, depreciation, depletion,

amortization, non-cash items and taxes.




Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we
believe is an important performance measure of the core profitability of our
operations. This measure represents the basis of our internal financial
reporting and is one of the performance measures used by senior management in
deciding how to allocate capital resources among business segments.
The tables below identify the components of Segment Adjusted EBITDA, which is
calculated as follows:
•   Segment margin, operating expenses, and selling, general and administrative

expenses. These amounts represent the amounts included in our consolidated

financial statements that are attributable to each segment.

• Unrealized gains or losses on commodity risk management activities and

inventory valuation adjustments. These are the unrealized amounts that are

included in cost of products sold to calculate segment margin. These amounts

are not included in Segment Adjusted EBITDA; therefore, the unrealized losses

are added back and the unrealized gains are subtracted to calculate the

segment measure.

• Non-cash compensation expense. These amounts represent the total non-cash

compensation recorded in operating expenses and selling, general and

administrative expenses. This expense is not included in Segment Adjusted

EBITDA and therefore is added back to calculate the segment measure.

• Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related

to unconsolidated affiliates excludes the same items with respect to the

unconsolidated affiliate as those excluded from the calculation of Segment

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



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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.
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.
For additional information regarding our business segments, see "Item 1.
Business" and Notes 1 and 16 to our consolidated financial statements in "Item
8. Financial Statements and Supplementary Data."
Segment Operating Results
Intrastate Transportation and Storage
                                                   Years Ended December 31,
                                                     2019             2018

Change


Natural gas transported (BBtu/d)                     12,442            10,873          1,569
Revenues                                        $     3,099       $     3,737     $     (638 )
Cost of products sold                                 1,909             2,665           (756 )
Segment margin                                        1,190             1,072            118
Unrealized losses on commodity risk management
activities                                                2                38            (36 )
Operating expenses, excluding non-cash
compensation expense                                   (190 )            (189 )           (1 )
Selling, general and administrative expenses,
excluding non-cash compensation expense                 (29 )             (27 )           (2 )
Adjusted EBITDA related to unconsolidated
affiliates                                               25                32             (7 )
Other                                                     1                 1              -
Segment Adjusted EBITDA                         $       999       $       927     $       72


Volumes. For the year ended December 31, 2019 compared to the prior year,
transported volumes increased primarily due to the impact of reflecting RIGS as
a consolidated subsidiary beginning April 2018 and the impact of the Red Bluff
Express pipeline coming online in May 2018, as well as the impact of favorable
market pricing spreads.
Segment Margin. The components of our intrastate transportation and storage
segment margin were as follows:
                                                   Years Ended December 31,
                                                     2019             2018           Change
Transportation fees                             $       614       $       525     $        89
Natural gas sales and other (excluding
unrealized gains and losses)                            505               510              (5 )
Retained fuel revenues (excluding unrealized
gains and losses)                                        50                59              (9 )
Storage margin, including fees (excluding
unrealized gains and losses)                             23                16               7
Unrealized losses on commodity risk management
activities                                               (2 )             (38 )            36
Total segment margin                            $     1,190       $     1,072     $       118



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Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the
prior year, Segment Adjusted EBITDA related to our intrastate transportation and
storage segment increased due to the net impacts of the following:
•   an increase of $64 million in transportation fees, excluding the impact of

consolidating RIGS beginning April 2018 as discussed below, primarily due to

the Red Bluff Express pipeline coming online in May 2018, as well as new

contracts;

• a net increase of $11 million primarily due to the consolidation of RIGS

beginning April 2018, resulting in increases in transportation fees, retained

fuel revenues and operating expenses of $24 million, $2 million and $6

million, respectively, partially offset by a decrease in Adjusted EBITDA

related to unconsolidated affiliates of $9 million; and

• an increase of $7 million in realized storage margin primarily due to a

realized adjustment to the Bammel storage inventory of $25 million in 2018

and higher storage fees, partially offset by a $20 million decrease due to

lower physical withdrawals; partially offset by

• a decrease of $9 million in retained fuel revenues primarily due to lower gas

prices; and

• a decrease of $5 million in realized natural gas sales and other due to lower

realized gains from pipeline optimization activity.

Interstate Transportation and Storage


                                                   Years Ended December 31,
                                                     2019             2018

Change


Natural gas transported (BBtu/d)                     11,346             9,542           1,804
Natural gas sold (BBtu/d)                                17                17               -
Revenues                                        $     1,963       $     1,682     $       281
Operating expenses, excluding non-cash
compensation, amortization and accretion
expenses                                               (569 )            (431 )          (138 )
Selling, general and administrative expenses,
excluding non-cash compensation, amortization
and accretion expenses                                  (72 )             (63 )            (9 )
Adjusted EBITDA related to unconsolidated
affiliates                                              477               492             (15 )
Other                                                    (7 )               -              (7 )
Segment Adjusted EBITDA                         $     1,792       $     1,680     $       112


Volumes. For the year ended December 31, 2019 compared to the prior year,
transported volumes increased as a result of the addition of new contracted
volumes for delivery out of the Haynesville Shale, higher volumes on our Rover
pipeline as a result of the full year availability of new supply connections,
and higher throughput on Trunkline and Panhandle due to increased utilization of
higher contracted capacity.
Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the
prior year, Segment Adjusted EBITDA related to our interstate transportation and
storage segment increased due to the net impacts of the following:
•   an increase in margin of $231 million from the Rover pipeline due to higher

reservation and usage resulting from additional connections and utilization

of additional compression;

• an increase of $40 million in reservation and usage fees due to improved

market conditions allowing us to successfully bring new volumes to the system

at improved rates, primarily on our Transwestern, Tiger and Panhandle Eastern

systems; and

• an increase of $6 million from the Sea Robin pipeline due to higher rates

resulting from the rate case filed in June 2019, as well as fewer third party

supply interruptions on the Sea Robin system; partially offset by

• an increase of $138 million in operating expense primarily due to an increase

in ad valorem taxes of $126 million on the Rover pipeline system resulting

from placing the final portions of this asset into service in November 2018,

an increase of $24 million in transportation expense on Rover due to an

increase in transportation volumes, an increase of $5 million in allocated

overhead costs and additional operating expense of $4 million for assets

acquired in June 2019, partially offset by lower gas imbalance and system gas

activity of $15 million and lower storage capacity leased on the Panhandle

Eastern system of $8 million;

• an increase of $9 million in selling, general and administrative expenses

primarily due to an increase in insurance expense of $8 million, an increase

in employee cost of $4 million, and an increase in allocated overhead costs

of $3 million, partially offset by lower Ohio excise tax on our Rover system;

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• a decrease of $15 million in adjusted EBITDA related to unconsolidated

affiliates primarily resulting from a $20 million decrease due to lower

earnings from MEP as a result of lower capacity being re-contracted at lower

rates on expiring contracts, partially offset by a $5 million increase from


    our Citrus joint venture as we brought new volumes to the system in 2019.


Midstream
                                                   Years Ended December 31,
                                                     2019             2018           Change
Gathered volumes (BBtu/d)                            13,460            12,126          1,334
NGLs produced (MBbls/d)                                 571               540             31
Equity NGLs (MBbls/d)                                    31                29              2
Revenues                                        $     6,031       $     7,522     $   (1,491 )
Cost of products sold                                 3,577             5,145         (1,568 )
Segment margin                                        2,454             2,377             77
Operating expenses, excluding non-cash
compensation expense                                   (791 )            (705 )          (86 )
Selling, general and administrative expenses,
excluding non-cash compensation expense                 (90 )             (81 )           (9 )
Adjusted EBITDA related to unconsolidated
affiliates                                               27                33             (6 )
Other                                                     2                 3             (1 )
Segment Adjusted EBITDA                         $     1,602       $     1,627     $      (25 )


Volumes. For the year ended December 31, 2019 compared to the prior 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 and North Texas regions partially offset by ethane
rejection in the South Texas region.
Segment Margin. The table below presents the components of our midstream segment
margin. For the year ended December 31, 2018, the amounts previously reported
for fee-based and non-fee-based margin have been adjusted to reflect
reclassification of certain contractual minimum fees from fee-based margin to
non-fee-based margin in order to conform to the current period classification.
                                                        Years Ended December 31,
                                                          2019                  2018          Change
Gathering and processing fee-based revenues     $       2,002               $    1,788     $       214
Non-fee based contracts and processing                    452                      589            (137 )
Total segment margin                            $       2,454               $    2,377     $        77


Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the
prior year, Segment Adjusted EBITDA related to our midstream segment decreased
due to the net impacts of the following:
•   a decrease of $137 million in non fee-based margin due to lower NGL prices of

$131 million and lower gas prices of $58 million, offset by an increase of

$52 million in non fee-based margin due to increased throughput volume in

North Texas, South Texas and Permian regions;

• an increase of $86 million in operating expenses due to increases of $33

million in outside services, $29 million in maintenance project costs, $17

million in employee costs and $6 million in office expenses and materials;

and

• an increase of $9 million in selling, general and administrative expenses

primarily due to a decrease of $5 million in capitalized overhead and an

increase of $4 million in insurance expense; partially offset by

• an increase of $214 million in fee-based margin due to volume growth in the


    Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions.




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NGL and Refined Products Transportation and Services


                                                    Years Ended December

31,


                                                     2019              2018

Change


NGL transportation volumes (MBbls/d)                   1,289             1,027             262
Refined products transportation volumes
(MBbls/d)                                                583               621             (38 )
NGL and refined products terminal volumes
(MBbls/d)                                                944               812             132
NGL fractionation volumes (MBbls/d)                      706               527             179
Revenues                                        $     11,641       $    11,123     $       518
Cost of products sold                                  8,393             8,462             (69 )
Segment margin                                         3,248             2,661             587
Unrealized (gains) losses on commodity risk
management activities                                     81               (86 )           167
Operating expenses, excluding non-cash
compensation expense                                    (656 )            (604 )           (52 )
Selling, general and administrative expenses,
excluding non-cash compensation expense                  (93 )             (74 )           (19 )
Adjusted EBITDA related to unconsolidated
affiliates                                                86                82               4
Segment Adjusted EBITDA                         $      2,666       $     1,979     $       687


Volumes. For the year ended December 31, 2019 compared to the prior year,
throughput barrels 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 the Mariner East 2 pipeline system.
Refined products transportation volumes decreased for the year ended
December 31, 2019 compared to prior year due to the closure of a third party
refinery during the third quarter of 2019, negatively impacting supply to our
refined products transportation system. These decreases in volumes 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 year ended
December 31, 2019 compared to the prior year primarily due to the initiation of
service on our Mariner East 2 pipeline system which commenced operations in the
fourth quarter of 2018.
Average volumes fractionated at our Mont Belvieu, Texas fractionation facility
increased for the year ended December 31, 2019 compared to the prior year
primarily due to the commissioning of our fifth and sixth fractionators in July
2018 and February 2019, respectively.
Segment Margin. The components of our NGL and refined products transportation
and services segment margin were as follows:
                                                    Years Ended December

31,


                                                     2019               2018           Change
Fractionators and refinery services margin      $        664       $        511     $       153
Transportation margin                                  1,716              1,233             483
Storage margin                                           223                211              12
Terminal Services margin                                 630                494             136
Marketing margin                                          96                126             (30 )
Unrealized gains (losses) on commodity risk
management activities                                    (81 )               86            (167 )
Total segment margin                            $      3,248       $      2,661     $       587


Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the
prior year, Segment Adjusted EBITDA related to our NGL and refined products
transportation and services segment increased due to the net impacts of the
following:
•   an increase of $483 million in transportation margin primarily due to a $265

million increase resulting from the initiation of service on our Mariner East

2 pipeline in the fourth quarter of 2018, a $212 million increase resulting

from higher throughput volumes received from the Permian region on our Texas

NGL pipelines, a $29 million increase due to higher throughput volumes from

the Barnett region, a $9 million increase from the Eagle Ford region, and a

$9 million increase due to the



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initiation of service on the JC Nolan Pipeline. These increases were partially
offset by a $21 million decrease resulting from Mariner East 1 pipeline
downtime, a $13 million decrease due to the closure of a third-party refinery
during the third quarter of 2019, negatively impacting refined product supply to
our system, and a $5 million decrease due to the timing of deficiency fees on
Mariner West;
•   an increase of $153 million in fractionation and refinery services margin

primarily due to a $167 million increase resulting from the commissioning of

our fifth and sixth fractionators in July 2018 and February 2019,

respectively, and higher NGL volumes from the Permian region feeding our Mont

Belvieu fractionation facility. This increase was partially offset by a

reclassification between our fractionation and storage margins;

• an increase of $136 million in terminal services margin primarily due to a

$171 million increase from the initiation of service of our Mariner East 2

pipeline which commenced operations in the fourth quarter of 2018 and a $7

million increase due to increased tank lease revenue from third-party

customers. These increases were partially offset by a $16 million decrease in

volumes and expense reimbursements from third parties on Mariner East 1, a

$16 million decrease due to lower volumes from third party pipeline, truck

and rail deliveries into our Marcus Hook terminal, a $5 million decrease due

to fewer vessels exported out of our Nederland terminal, and a $4 million

decrease due to the closure of a third party refinery during the third

quarter of 2019; and

• an increase of $12 million in storage margin primarily due to a

reclassification between our storage and fractionation margins; partially

offset by

• a decrease of $30 million in marketing margin primarily due to capacity lease

fees incurred by our marketing affiliate on our Mariner East 2 pipeline,


    offset by increased gains from our butane blending business due to more
    favorable market conditions and increased volumes, as well as increased
    optimization gains from the sale of NGL component products at our Mont
    Belvieu facility;

• an increase of $52 million in operating expenses primarily due to a $26

million increase in employee and ad valorem tax expenses on our terminals,

fractionation, and transportation operations, a $14 million increase in

utility costs to operate our pipelines and our fifth and sixth fractionators

which commenced July 2018 and February 2019, respectively, and an $8 million

increase in maintenance project costs due to the timing of multiple projects

on our transportation assets; and

• an increase of $19 million in general and administrative expenses primarily

due to a $10 million increase in allocated overhead costs, a $5 million

increase in insurance expenses, a $4 million increase in legal fees, and a $2

million increase in employee costs.

Crude Oil Transportation and Services


                                                    Years Ended December

31,


                                                     2019              2018

Change


Crude transportation volumes (MBbls/d)                 4,662             4,172            490
Crude terminals volumes (MBbls/d)                      2,068             2,096            (28 )
Revenue                                         $     18,447       $    17,332     $    1,115
Cost of products sold                                 14,758            14,439            319
Segment margin                                         3,689             2,893            796
Unrealized (gains) losses on commodity risk
management activities                                    (69 )              55           (124 )
Operating expenses, excluding non-cash
compensation expense                                    (570 )            (547 )          (23 )
Selling, general and administrative expenses,
excluding non-cash compensation expense                  (85 )             (86 )            1
Adjusted EBITDA related to unconsolidated
affiliates                                                 8                15             (7 )
Other                                                     (1 )               -             (1 )
Segment Adjusted EBITDA                         $      2,972       $     2,330     $      642


Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the
prior 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 $672 million in segment margin (excluding unrealized gains and

losses on commodity risk management activities) primarily due to a $282

million increase resulting from higher throughput on our Texas crude pipeline

system primarily due to increased production from the Permian region and

contributions from capacity expansion projects placed into service, a $219


    million increase in throughput on our Bakken pipeline, a favorable inventory
    valuation adjustment of



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$111 million for the 2019 year as compared to an unfavorable inventory
adjustment of $54 million for the 2018 year, partially offset by a $50 million
reduction due to lower pipeline basis spreads net of hedges. We also realized a
$66 million increase from higher volumes on our Bayou Bridge Pipeline, a $31
million increase due to the inclusion of assets acquired in 2019, and a $26
million increase primarily from higher throughput, ship loading and tank rental
fees at our Nederland terminal; partially offset by a $54 million decrease from
our Oklahoma assets resulting from lower volumes to the system as well as from
the timing of a deficiency payment made in the prior year, $12 million decrease
due to the closure of a third party refinery which was the primary customer
utilizing one of our northeast crude terminals. The remainder of the offsetting
decrease was primarily attributable to a change in the presentation of certain
intrasegment transactions, which were eliminated in the current period
presentation but were shown on a gross basis in revenues and operating expenses
in the prior period; partially offset by
•   an increase of $23 million in operating expenses primarily due to a $30

million increase in throughput-related costs on existing assets and a $10

million increase due to the inclusion of expenses acquired in 2019, partially

offset by a $14 million decrease in management fees as well as the impact of

certain intrasegment transactions discussed above;

• a decrease of $7 million in Adjusted EBITDA related to unconsolidated


    affiliates due to lower margin from jet fuel sales by our joint ventures.


Investment in Sunoco LP
                                                    Years Ended December 31,
                                                     2019              2018           Change
Revenues                                        $     16,596       $    16,994     $     (398 )
Cost of products sold                                 15,380            15,872           (492 )
Segment margin                                         1,216             1,122             94
Unrealized (gains) losses on commodity risk
management activities                                     (5 )               6            (11 )
Operating expenses, excluding non-cash
compensation expense                                    (365 )            (435 )           70
Selling, general and administrative, excluding
non-cash compensation expense                           (123 )            (129 )            6
Adjusted EBITDA related to unconsolidated
affiliates                                                 4                 -              4
Inventory valuation adjustments                          (79 )              85           (164 )
Adjusted EBITDA from discontinued operations               -               (25 )           25
Other, net                                                17                14              3
Segment Adjusted EBITDA                         $        665       $       638     $       27


The Investment in Sunoco LP segment reflects the consolidated results of Sunoco
LP.
Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the
prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP
segment increased due to the net impacts of the following:
•   a decrease in operating costs of $76 million, primarily as a result of the

conversion of 207 retail sites to commission agent sites during April 2018.

These expenses include other operating expense, general and administrative

expense and lease expense; and

• an increase of $25 million related to Adjusted EBITDA from discontinued

operations related to the divestment of 1,030 company-operated fuel sites to

7-Eleven in January 2018; and

• an increase of $4 million in Adjusted EBITDA related to unconsolidated

affiliates due to Sunoco LP's investment in the JC Nolan joint venture;

partially offset by

• a decrease in the gross profit on motor fuel sales of $76 million (excluding

the change in inventory fair value adjustments and unrealized gains and

losses on commodity risk management activities) primarily due to lower fuel

margins, a one-time benefit of approximately $25 million related to a cash

settlement with a fuel supplier recorded in 2018 and an $8 million one-time

charge related to a reserve for an open contractual dispute recorded in 2019,


    partially offset by an increase in gallons sold.





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Investment in USAC
                                                     Years Ended December 31,
                                                      2019                2018           Change
Revenues                                        $        698         $        508     $       190
Cost of products sold                                     91                   67              24
Segment margin                                           607                  441             166
Operating expenses, excluding non-cash
compensation expense                                    (134 )               (110 )           (24 )
Selling, general and administrative, excluding
non-cash compensation expense                            (53 )                (50 )            (3 )
Other, net                                                 -                    8              (8 )
Segment Adjusted EBITDA                         $        420         $        289     $       131


Amounts reflected above for the year ended December 31, 2019 represents the
results of operations for USAC from April 2, 2018, the date ET obtained control
of USAC, through December 31, 2019. Changes between periods are due to the
consolidation of USAC beginning April 2, 2018.
All Other
                                                   Years Ended December 31,
                                                     2019             2018           Change
Revenue                                         $     1,689       $     2,228     $     (539 )
Cost of products sold                                 1,504             2,006           (502 )
Segment margin                                          185               222            (37 )
Unrealized gains on commodity risk management
activities                                               (4 )              (2 )           (2 )
Operating expenses, excluding non-cash
compensation expense                                    (77 )             (56 )          (21 )
Selling, general and administrative expenses,
excluding non-cash compensation expense                 (66 )            (124 )           58
Adjusted EBITDA related to unconsolidated
affiliates                                                2                 1              1
Other and eliminations                                   58                (1 )           59
Segment Adjusted EBITDA                         $        98       $        40     $       58

Amounts reflected in our all other segment primarily include: • our natural gas marketing operations;

• our wholly-owned natural gas compression operations;

• a non-controlling interest in PES. Prior to PES's reorganization in August

2018, ETO's 33% interest in PES was reflected as an unconsolidated affiliate;

subsequent the August 2018 reorganization, ETO holds an approximately 7.4%

interest in PES and no longer reflects PES as an affiliate;

• our investment in coal handling facilities; and

• our Canadian operations, which were acquired in the SemGroup acquisition in

December 2019 and include natural gas gathering and processing assets.




Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the
prior year, Segment Adjusted EBITDA increased due to the net impact of the
following:
• an increase of $8 million in gains from park and loan and storage activity;

• an increase of $11 million in optimized gains on residue gas sales;

• an increase of $7 million from settled derivatives;

• an increase of $15 million from a legal settlement;

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• an increase of $12 million from payments related to the PES bankruptcy;

• an increase of $6 million from the recognition of deferred revenue related to

a bankruptcy;

• an increase of $3 million from power trading activities;

• an increase of $3 million from the SemCAMS joint venture for the period

subsequent to our acquisition of SemGroup on December 5, 2019, net of an

increase in SemGroup corporate expenses; and

• a decrease of $40 million in merger and acquisition expenses; partially

offset by

• a decrease of $36 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 $8 million due to lower gas prices and increased power costs;

and

• a decrease of $11 million due to lower revenue from our compressor equipment

business.




Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Consolidated Results
                                                   Years Ended December 31,
                                                     2018             2017            Change
Segment Adjusted EBITDA:
Intrastate transportation and storage           $       927       $       626     $        301
Interstate transportation and storage                 1,680             1,274              406
Midstream                                             1,627             1,481              146
NGL and refined products transportation and
services                                              1,979             1,641              338
Crude oil transportation and services                 2,330             1,379              951
Investment in Sunoco LP                                 638               732              (94 )
Investment in USAC                                      289                 -              289
All other                                                40               187             (147 )
Total                                                 9,510             7,320            2,190
Depreciation, depletion and amortization             (2,859 )          (2,554 )           (305 )

Interest expense, net of interest capitalized (2,055 ) (1,922 )

           (133 )
Impairment losses                                      (431 )          (1,039 )            608
Gains (losses) on interest rate derivatives              47               (37 )             84
Non-cash compensation expense                          (105 )             (99 )             (6 )
Unrealized gains (losses) on commodity risk
management activities                                   (11 )              59              (70 )
Inventory valuation adjustments                         (85 )              24             (109 )
Losses on extinguishments of debt                      (112 )             (89 )            (23 )
Adjusted EBITDA related to unconsolidated
affiliates                                             (655 )            (716 )             61
Equity in earnings of unconsolidated affiliates         344               144              200
Impairment of investments in unconsolidated
affiliates                                                -              (313 )            313
Adjusted EBITDA related to discontinued
operations                                               25              (223 )            248
Other, net                                               21               155             (134 )
Income from continuing operations before income
tax (expense) benefit                                 3,634               710            2,924
Income tax (expense) benefit from continuing
operations                                               (4 )           1,833           (1,837 )
Income from continuing operations                     3,630             2,543            1,087
Loss from discontinued operations, net of
income taxes                                           (265 )            (177 )            (88 )
Net income                                      $     3,365       $     2,366     $        999


Adjusted EBITDA (consolidated). For the year ended December 31, 2018 compared to
the prior year, Adjusted EBITDA increased approximately $2.2 billion, or 30%.
The increase was primarily due to the impact of multiple revenue-generating
assets being

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placed in service and recent acquisitions, as well as increased demand for
services on existing assets. The impact of new assets and acquisitions was
approximately $1.2 billion, of which the largest increases were from the Bakken
pipeline (a $546 million impact to the crude oil transportation and services
segment), the Rover pipeline (a $359 million impact to the interstate
transportation and storage segment) and the acquisition of USAC (a net impact of
$191 million among the investment in USAC and all other segments). The remainder
of the increase in Adjusted EBITDA was primarily due to stronger demand on
existing assets, particularly due to increased production in the Permian, which
impacted multiple segments. Additional discussion of these and other factors
affecting Adjusted EBITDA is included in the analysis of Segment Adjusted EBITDA
in the "Segment Operating Results" section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization increased primarily due to additional depreciation and amortization
from assets recently placed in service.
Interest Expense, Net of Interest Capitalized. Interest expense, net of interest
capitalized, increased primarily due to the following:
•   an increase of $121 million recognized by ETO primarily related to an

increase in long-term debt, including additional senior note issuances and

borrowings under our revolving credit facilities; and

• an increase of $78 million due to the acquisition of USAC on April 2, 2018;

partially offset by

• a decrease of $65 million recognized by Sunoco LP primarily due to the

repayment in full of its term loan and refinancing of its senior notes at

lower rates.




Impairment Losses. During the year ended December 31, 2018, the Partnership
recognized goodwill impairments of $378 million and asset impairments of $4
million related to our midstream operations and asset impairments of $9 million
related to our crude operations idle leased assets. Sunoco LP recognized a $30
million indefinite-lived intangible impairment related to its contractual
rights. USAC recognized a $9 million fixed asset impairment related to certain
idle compressor assets.
During the year ended December 31, 2017, the Partnership recorded goodwill
impairments of $223 million related to the compression business, $229 million
related to Panhandle, $262 million related to the interstate transportation and
storage segment and $79 million related to the NGL and refined products
transportation and services segment. Sunoco LP recognized goodwill impairments
of $387 million in 2017, of which $102 million was allocated to continuing
operations. In addition, during the year ended December 31, 2017, the
Partnership recorded an impairment to the property, plant and equipment of Sea
Robin of $127 million. Additional discussion on these impairments is included in
"Estimates and Critical Accounting Policies" below.
Gains (Losses) on Interest Rate Derivatives. Our interest rate derivatives are
not designated as hedges for accounting purposes; therefore, changes in fair
value are recorded in earnings each period. Gains (losses) on interest rate
derivatives during the years ended December 31, 2018 and 2017 resulted from an
increase in forward interest rates in 2018 and a decrease in forward interest
rates in 2017, which caused our forward-starting swaps to change in value.
Unrealized Gains (Losses) on Commodity Risk Management Activities. See
discussion of the unrealized gains (losses) on commodity risk management
activities included in the discussion of segment results below.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were
recorded for the inventory associated with Sunoco LP as a result of commodity
price changes in between periods.
Losses on Extinguishments of Debt. Amounts were related to Sunoco LP's senior
note and term loan redemption in January 2018.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of
Unconsolidated Affiliates. See additional information in "Supplemental
Information on Unconsolidated Affiliates" and "Segment Operation Results" below.
Impairment of Investments in Unconsolidated Affiliates. During the year ended
December 31, 2017, the Partnership recorded impairments to its investments in
FEP of $141 million and HPC of $172 million. Additional discussion on these
impairments is included in "Estimates and Critical Accounting Policies" below.
Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the
operations of Sunoco LP's retail business that were disposed of in January 2018.
Other, net. Other, net primarily includes amortization of regulatory assets and
other income and expense amounts.
Income Tax (Expense) Benefit. On December 22, 2017, the Tax Cuts and Jobs Act
was signed into law. Among other provisions, the highest corporate federal
income tax rate was reduced from 35% to 21% for taxable years beginning after
December 31, 2017. As a result, the Partnership recognized a deferred tax
benefit of 1.81 billion in December 2017. For the year ended December

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2018, the Partnership recorded an income tax expense due to pre-tax income at
its corporate subsidiaries, partially offset by a statutory rate reduction.
Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated
affiliates:
                                                         Years Ended December 31,
                                                           2018                   2017          Change
Equity in earnings (losses) of unconsolidated
affiliates:
Citrus                                          $        141                  $      144     $        (3 )
FEP                                                       55                          53               2
MEP                                                       31                          38              (7 )
HPC (1)(2)                                                 3                        (168 )           171
Other                                                    114                          77              37
Total equity in earnings of unconsolidated
affiliates                                      $        344

$ 144 $ 200



Adjusted EBITDA related to unconsolidated
affiliates(3):
Citrus                                          $        337                  $      336     $         1
FEP                                                       74                          74               -
MEP                                                       81                          88              (7 )
HPC (2)                                                    9                          46             (37 )
Other                                                    154                         172             (18 )
Total Adjusted EBITDA related to unconsolidated
affiliates                                      $        655

$ 716 $ (61 )



Distributions received from unconsolidated
affiliates:
Citrus                                          $        171                  $      156     $        15
FEP                                                       68                          47              21
MEP                                                       48                         114             (66 )
HPC (2)                                                    -                          35             (35 )
Other                                                    110                          80              30
Total distributions received from
unconsolidated affiliates                       $        397

$ 432 $ (35 )

(1) 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.

(2) For the year ended December 31, 2017, equity in earnings of unconsolidated

affiliates includes the impact of non-cash impairments recorded by HPC,

which reduced the Partnership's equity in earnings by $185 million.

(3) These amounts represent our proportionate share of the Adjusted EBITDA of

our unconsolidated affiliates and are based on our equity in earnings or

losses of our unconsolidated affiliates adjusted for our proportionate share


     of the unconsolidated affiliates' interest, depreciation, depletion,
     amortization, non-cash items and taxes.



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Segment Operating Results
Intrastate Transportation and Storage
                                                   Years Ended December 31,
                                                     2018             2017

Change


Natural gas transported (BBtu/d)                     10,873             8,427           2,446
Revenues                                        $     3,737       $     3,083     $       654
Cost of products sold                                 2,665             2,327             338
Segment margin                                        1,072               756             316
Unrealized (gains) losses on commodity risk
management activities                                    38                (5 )            43
Operating expenses, excluding non-cash
compensation expense                                   (189 )            (168 )           (21 )
Selling, general and administrative, excluding
non-cash compensation expense                           (27 )             (22 )            (5 )
Adjusted EBITDA related to unconsolidated
affiliates                                               32                64             (32 )
Other                                                     1                 1               -
Segment Adjusted EBITDA                         $       927       $       626     $       301


Volumes. For the year ended December 31, 2018 compared to the prior year,
transported volumes increased primarily due to favorable market pricing spreads,
as well as the impact of reflecting RIGS assets as a consolidated subsidiary
beginning in April 2018.
Segment Margin. The components of our intrastate transportation and storage
segment margin were as follows:
                                                    Years Ended December 31,
                                                      2018              2017           Change
Transportation fees                             $         525       $       448     $        77
Natural gas sales and other (excluding
unrealized gains and losses)                              510               196             314
Retained fuel revenues (excluding unrealized
gains and losses)                                          59                58               1
Storage margin, including fees (excluding
unrealized gains and losses)                               16                49             (33 )
Unrealized gains (losses) on commodity risk
management activities                                     (38 )               5             (43 )
Total segment margin                            $       1,072       $       756     $       316


Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the
prior year, Segment Adjusted EBITDA related to our intrastate transportation and
storage segment increased due to the net impacts of the following:
•   an increase of $314 million in realized natural gas sales and other due to

higher realized gains from pipeline optimization activity;

• a net increase of $14 million due to the consolidation of RIGS beginning in

April 2018, resulting in increases in transportation fees, operating

expenses, and selling, general and administrative expenses of $73 million,

$16 million and $6 million, respectively, and a decrease of $37 million in

Adjusted EBITDA related to unconsolidated affiliates; and

• an increase of $4 million in transportation fees, excluding the impact of

consolidating RIGS as discussed above, primarily due to new contracts and the

impact of the Red Bluff Express pipeline coming online in May 2018; partially

offset by

• a decrease of $33 million in realized storage margin primarily due to an

adjustment to the Bammel storage inventory, lower storage fees and lower


    realized derivative gains.



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Interstate Transportation and Storage


                                                   Years Ended December 31,
                                                     2018             2017

Change


Natural gas transported (BBtu/d)                      9,542             6,058           3,484
Natural gas sold (BBtu/d)                                17                18              (1 )
Revenues                                        $     1,682       $     1,131     $       551
Operating expenses, excluding non-cash
compensation, amortization and accretion
expenses                                               (431 )            (315 )          (116 )
Selling, general and administrative, excluding
non-cash compensation, amortization and
accretion expenses                                      (63 )             (41 )           (22 )
Adjusted EBITDA related to unconsolidated
affiliates                                              492               498              (6 )
Other                                                     -                 1              (1 )
Segment Adjusted EBITDA                         $     1,680       $     1,274     $       406


Volumes. For the year ended December 31, 2018 compared to the prior year,
transported volumes reflected increases of 1,919 BBtu/d as a result of the
initiation of service on the Rover pipeline; increases of 572 BBtu/d and 439
BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to higher
demand resulting from colder weather and increased utilization by the Rover
pipeline; 375 BBtu/d on the Tiger pipeline as a result of production increases
in the Haynesville Shale, and 145 BBtu/d on the Transwestern pipeline resulting
from favorable market opportunities in the West, midcontinent and Waha areas
from the Permian supply basin.
Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the
prior year, Segment Adjusted EBITDA related to our interstate transportation and
storage segment increased due to the net impacts of the following:
•   an increase of $359 million associated with the Rover pipeline with increases

of $485 million in revenues, $105 million in net operating expenses and $21

million in selling, general and administrative expenses and other; and

• an aggregate increase of $66 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 and Panhandle pipelines;

partially offset by

• an increase of $11 million in operating expenses, excluding the incremental

expenses related to the Rover pipeline discussed above, primarily due to

increases in maintenance project costs due to scope and level of activity;

and

• a decrease of $6 million in Adjusted EBITDA related to unconsolidated

affiliates primarily due to lower margins on MEP due to lower rates on

renewals of expiring long term contracts.




Midstream
                                                   Years Ended December 31,
                                                     2018             2017           Change
Gathered volumes (BBtu/d):                           12,126             9,814           2,312
NGLs produced (MBbls/d):                                540               438             102
Equity NGLs (MBbls/d):                                   29                31              (2 )
Revenues                                        $     7,522       $     6,943     $       579
Cost of products sold                                 5,145             4,761             384
Segment margin                                        2,377             2,182             195
Unrealized gains on commodity risk management
activities                                                -               (15 )            15
Operating expenses, excluding non-cash
compensation expense                                   (705 )            (638 )           (67 )
Selling, general and administrative, excluding
non-cash compensation expense                           (81 )             (78 )            (3 )
Adjusted EBITDA related to unconsolidated
affiliates                                               33                28               5
Other                                                     3                 2               1
Segment Adjusted EBITDA                         $     1,627       $     1,481     $       146



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Volumes. Gathered volumes and NGL production increased during the year ended
December 31, 2018 compared to the prior year primarily due to increases in the
North Texas, Permian and Northeast regions, partially offset by smaller declines
in other regions.
Segment Margin. The table below presents the components of our midstream segment
margin. For the years ended December 31, 2018 and 2017, the amounts previously
reported for fee-based and non-fee-based margin have been adjusted to reflect
reclassification of certain contractual minimum fees from fee-based margin to
non-fee-based margin in order to conform to the current period classification.
                                                        Years Ended December 31,
                                                          2018                  2017          Change
Gathering and processing fee-based revenues     $       1,788               $    1,690     $        98
Non-fee based contracts and processing
(excluding unrealized gains and losses)                   589                      477             112
Unrealized gains on commodity risk management
activities                                                  -                       15             (15 )
Total segment margin                            $       2,377               $    2,182     $       195


Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the
prior year, Segment Adjusted EBITDA related to our midstream segment increased
due to the net impacts of the following:
•   an increase of $98 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;

• an increase of $79 million in non fee-based margin due to increased

throughput volume in the North Texas and Permian regions;

• an increase of $33 million in non fee-based margin due to higher crude oil

and NGL prices; and

• an increase of $5 million in Adjusted EBITDA related to unconsolidated

affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint

ventures; partially offset by

• an increase of $67 million in operating expenses primarily due to increases

of $20 million in outside services, $19 million in materials, $8 million in

maintenance project costs, $7 million in ad valorem taxes, $6 million in

employee costs and $6 million in office expenses; and

• an increase of $3 million in selling, general and administrative expenses due

to higher professional fees.

NGL and Refined Products Transportation and Services


                                                    Years Ended December

31,


                                                     2018              2017

Change


NGL transportation volumes (MBbls/d)                   1,027               754            273
Refined products transportation volumes
(MBbls/d)                                                621               599             22
NGL and refined products terminal volumes
(MBbls/d)                                                812               791             21
NGL fractionation volumes (MBbls/d)                      527               361            166
Revenues                                        $     11,123       $     8,648     $    2,475
Cost of products sold                                  8,462             6,508          1,954
Segment margin                                         2,661             2,140            521
Unrealized gains on commodity risk management
activities                                               (86 )             (26 )          (60 )
Operating expenses, excluding non-cash
compensation expense                                    (604 )            (478 )         (126 )
Selling, general and administrative expenses,
excluding non-cash compensation expense                  (74 )             (64 )          (10 )
Adjusted EBITDA related to unconsolidated
affiliates                                                82                68             14
Other                                                      -                 1             (1 )
Segment Adjusted EBITDA                         $      1,979       $     1,641     $      338



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Volumes. For the year ended December 31, 2018 compared to the prior year, 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 year and higher throughput from Mariner South resulting
from increased export volumes.
Refined products transportation volumes decreased for the year ended
December 31, 2018 compared to prior year, primarily due to timing of turnarounds
at third-party refineries in the Midwest and Northeast regions.
NGL and Refined products terminal volumes increased for the year ended
December 31, 2018 compared to prior year, primarily due to more volumes loaded
at our Nederland terminal as propane export demand increased and higher
throughput volumes at our refined products terminals in the Northeast.
Average volumes fractionated at our Mont Belvieu, Texas fractionation facility
increased for the year ended December 31, 2018 compared to the prior year
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 Margin. The components of our NGL and refined products transportation
and services segment margin were as follows:
                                                        Years Ended

December 31,


                                                          2018                  2017          Change
Fractionators and refinery services margin      $         511               $      415     $        96
Transportation margin                                   1,233                      990             243
Storage margin                                            211                      214              (3 )
Terminal Services margin                                  494                      424              70
Marketing margin                                          126                       71              55
Unrealized gains on commodity risk management
activities                                                 86                       26              60
Total segment margin                            $       2,661               $    2,140     $       521


Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the
prior year, Segment Adjusted EBITDA related to our NGL and refined products
transportation and services segment increased due to the net impacts of the
following:
•   an increase in transportation margin of $243 million primarily due to a $216

million increase resulting from increased producer volumes from the Permian

region on our Texas NGL pipelines, a $31 million increase due to higher

throughput volumes on Mariner West driven by end-user facility constraints in

the prior period, a $15 million increase resulting from a reclassification

between our transportation and fractionation margins, a $9 million increase

due to higher throughput volumes from the Barnett region, a $5 million

increase due to higher throughput volumes on Mariner South due to system

downtime in the prior period and a $4 million increase in prior period

customer credits. These increases were partially offset by a $16 million

decrease resulting from lower throughput volumes on Mariner East 1 due to

system downtime in 2018, a $14 million decrease due to lower throughput

volumes from the Southeast Texas region and a $7 million decrease resulting

from the timing of deficiency fee revenue recognition;

• an increase in fractionation and refinery services margin of $96 million

primarily due to a $106 million increase resulting from the commissioning of

our fifth fractionator in July 2018 and a $7 million increase from blending

gains as a result of improved market pricing. These increases were partially

offset by a $16 million decrease resulting from a reclassification between

our transportation and fractionation margins and a $2 million decrease from

higher affiliate storage fees paid;

• an increase in terminal services margin of $70 million due to a $36 million

increase resulting from a change in the classification of certain customer

reimbursements previously recorded in operating expenses, a $23 million

increase at our Nederland terminal due to increased export demand and a $12

million increase due to higher throughput at our Marcus Hook Industrial

Complex. These increases were partially offset by lower terminal throughput

fees in part due to the sale of one of our terminals in April 2017;

• an increase in marketing margin of $55 million due to a $48 million increase

from our butane blending operations and a $22 million increase in sales of

NGLs and other products at our Marcus Hook Industrial Complex due to more

favorable market prices. 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 $14 million to adjusted EBITDA related to unconsolidated

affiliates due to improved contributions from our unconsolidated refined


    products joint venture interests; partially offset by



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• an increase of $126 million in operating expenses primarily due to a $30

million increase in costs to operate our fractionators and a $20 million

increase in operating costs on our NGL pipelines as a result of higher

throughput and the commissioning of our fifth fractionator in July 2018, a

$36 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, increases of $24 million and $7 million to operating

costs at our Marcus Hook and Nederland terminals, respectively, as a result

of significantly higher volumes through both terminals in 2018, an $8 million

increase to environmental reserves and a $1 million increase to overhead

allocations and maintenance repairs performed on our refinery services

assets; and

• an increase of $10 million in selling, general and administrative expenses

primarily due to a $6 million increase in overhead costs allocated to the

segment, a $2 million increase in legal fees, a $1 million increase in

management fees previously recorded in operating expenses and a $1 million

increase in employee costs.

Crude Oil Transportation and Services


                                                    Years Ended December

31,


                                                     2018              2017

Change


Crude Transportation Volumes (MBbls/d)                 4,172             3,538            634
Crude Terminals Volumes (MBbls/d)                      2,096             1,928            168
Revenue                                         $     17,332       $    11,703     $    5,629
Cost of products sold                                 14,439             9,826          4,613
Segment margin                                         2,893             1,877          1,016
Unrealized losses on commodity risk management
activities                                                55                 1             54
Operating expenses, excluding non-cash
compensation expense                                    (547 )            (430 )         (117 )
Selling, general and administrative expenses,
excluding non-cash compensation expense                  (86 )             (82 )           (4 )
Adjusted EBITDA related to unconsolidated
affiliates                                                15                13              2
Segment Adjusted EBITDA                         $      2,330       $     1,379     $      951


Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the
prior 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 $1.07 billion in segment margin (excluding unrealized losses

on commodity risk management activities) primarily due to the following: a

$586 million increase resulting from placing the Bakken pipeline in service

in the second quarter of 2017, a $266 million increase resulting from higher

throughput on our Texas crude pipeline system primarily due to increased

production from Permian producers; and gains of $355 million due to more

favorable basis spreads; partially offset by an unfavorable inventory

valuation adjustment of $54 million for the 2018 year as compared to a

favorable inventory valuation adjustment of $82 million for the 2017 year;

and

• an increase of $2 million in Adjusted EBITDA related to unconsolidated

affiliates due to increased jet fuel sales from our joint ventures; partially

offset by

• an increase of $117 million in operating expenses primarily due to a $67

million increase to throughput related costs on existing assets; a $36

million increase resulting from placing the Bakken pipeline in service in the

second quarter of 2017; a $26 million increase resulting from the addition of

certain joint venture transportation assets in the second quarter of 2017;

and a $5 million increase from ad valorem taxes; partially offset by an $17

million decrease in insurance and environmental related expenses; and

• an increase of $4 million in selling, general and administrative expenses


    primarily due to increases associated with placing our Bakken Pipeline in
    service in the second quarter of 2017.



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Investment in Sunoco LP
                                                    Years Ended December 31,
                                                     2018              2017           Change
Revenues                                        $     16,994       $    11,723     $    5,271
Cost of products sold                                 15,872            10,615          5,257
Segment margin                                         1,122             1,108             14
Unrealized (gains) losses on commodity risk
management activities                                      6                (3 )            9
Operating expenses, excluding non-cash
compensation expense                                    (435 )            (456 )           21
Selling, general and administrative, excluding
non-cash compensation expense                           (129 )            (116 )          (13 )
Inventory valuation adjustments                           85               (24 )          109
Adjusted EBITDA from discontinued operations             (25 )             223           (248 )
Other, net                                                14                 -             14
Segment Adjusted EBITDA                         $        638       $       732     $      (94 )


The Investment in Sunoco LP segment reflects the consolidated results of Sunoco
LP.
Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the
prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP
segment decreased due to the net impacts of the following:
•   a decrease of $248 million in Adjusted EBITDA from discontinued operations

primarily due to Sunoco LP's retail divestment in January 2018; partially

offset by

• an increase of $109 million in inventory fair value adjustments due to

changes in fuel prices between periods;

• an increase of $14 million in margin primarily due to an increase in rental

income as a result of the increase in commission agent sites in the current

year, offset by decreases in the gross profit on motor fuel sales; and

• a net decrease of $8 million in operating and selling, general and

administrative expenses primarily due to decreased rent expense.




Investment in USAC
                                                      Years Ended December 31,
                                                      2018                 2017           Change
Revenues                                        $         508         $          -     $       508
Cost of products sold                                      67                    -              67
Segment margin                                            441                    -             441
Operating expenses, excluding non-cash
compensation expense                                     (110 )                  -            (110 )
Selling, general and administrative, excluding
non-cash compensation expense                             (50 )                  -             (50 )
Other, net                                                  8                    -               8
Segment Adjusted EBITDA                         $         289         $          -     $       289


The investment in USAC segment reflects the consolidated results of USAC from
April 2, 2018, the date ET obtained control of USAC, through December 31, 2018.
Changes between periods are due to the consolidation of USAC beginning April 2,
2018.

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All Other
                                                   Years Ended December 31,
                                                     2018             2017           Change
Revenue                                         $     2,228       $     2,901     $     (673 )
Cost of products sold                                 2,006             2,509           (503 )
Segment margin                                          222               392           (170 )
Unrealized gains on commodity risk management
activities                                               (2 )             (11 )            9
Operating expenses, excluding non-cash
compensation expense                                    (56 )            (117 )           61
Selling, general and administrative expenses,
excluding non-cash compensation expense                (124 )            (135 )           11
Adjusted EBITDA related to unconsolidated
affiliates                                                1                45            (44 )
Other and eliminations                                   (1 )              13            (14 )
Segment Adjusted EBITDA                         $        40       $       187     $     (147 )


Amounts reflected in our all other segment during the periods presented above
primarily include:
• our natural gas marketing operations;

• our wholly-owned natural gas compression operations;

• a non-controlling interest in PES. Prior to PES's reorganization in August

2018, ETO's 33% interest in PES was reflected as an unconsolidated affiliate;

subsequent the August 2018 reorganization, ETO holds an approximately 8%

interest in PES and no longer reflects PES as an affiliate; and

• our investment in coal handling facilities.




Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the
prior year, Segment Adjusted EBITDA decreased due to the net impacts of the
following:
•   a decrease of $98 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 $38 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;

• a decrease of $4 million due to merger and acquisition expenses related to

the Energy Transfer Merger in 2018; and

• a decrease of $15 million due to a one-time fee received from a joint venture

affiliate in 2017; partially offset by

• an increase of $7 million due to lower transport fees resulting from the

expiration of a capacity commitment on Trunkline pipeline;

• an increase of $6 million due to a decrease in losses from mark-to-market of

physical system gas; and

• an increase of $7 million due to increased margin from ETO's compression

equipment business.




LIQUIDITY AND CAPITAL RESOURCES
Overview
Parent Company Only
Subsequent to the Merger with ETO, 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
Sunoco LP and USAC.
The Parent Company's primary cash requirements are for general and
administrative expenses, debt service requirements and distributions to its
partners. The Parent Company currently expects to fund its short-term needs for
such items with cash flows from its direct and indirect investments in ETO. The
Parent Company distributes its available cash remaining after satisfaction of
the aforementioned cash requirements to its Unitholders on a quarterly basis.

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The Parent Company expects ETO and its respective subsidiaries and investments
in Sunoco LP and USAC to utilize their resources, along with cash from their
operations, to fund their announced growth capital expenditures and working
capital needs; however, the Parent Company may issue debt or equity securities
from time to time, as it deems prudent to provide liquidity for new capital
projects of its subsidiaries or for other partnership purposes.
ETO
ETO's ability to satisfy its obligations and pay distributions to the Parent
Company will depend on its future performance, which will be subject to
prevailing economic, financial, business and weather conditions, and other
factors, many of which are beyond the control of ETO's management.
ETO currently expects capital expenditures in 2020 to be within the following
ranges (excluding capital expenditures related to our investments in Sunoco LP
and USAC):
                                               Growth                      Maintenance
                                         Low            High            Low            High
Intrastate transportation and
storage                              $       20     $       30     $        40     $       45
Interstate transportation and
storage (1)                                 100            125             140            145
Midstream                                   625            650             125            130
NGL and refined products
transportation and services (1)           2,550          2,650             100            110
Crude oil transportation and
services (1)                                500            525             165            175
All other (including eliminations)          125            150              75             80
Total capital expenditures           $    3,920     $    4,130     $       645     $      685


(1)  Includes capital expenditures related to ETO's proportionate ownership of

the Bakken, Rover, and Bayou Bridge pipeline projects and our proportionate

ownership of the Orbit Gulf Coast NGL export project.




The assets used in our natural gas and liquids operations, including pipelines,
gathering systems and related facilities, are generally long-lived assets and do
not require significant maintenance capital expenditures. Accordingly, we do not
have any significant financial commitments for maintenance capital expenditures
in our businesses. From time to time we experience increases in pipe costs due
to a number of reasons, including but not limited to, delays from steel mills,
limited selection of mills capable of producing large diameter pipe timely,
higher steel prices and other factors beyond our control. However, we include
these factors in our anticipated growth capital expenditures for each year.
ETO generally funds maintenance capital expenditures and distributions with cash
flows from operating activities. ETO generally expects to funds growth capital
expenditures with proceeds of borrowings under ETO credit facilities, along with
cash from operations.
As of December 31, 2019, in addition to $253 million of cash on hand, ETO had
available capacity under the ETO Credit Facilities of $1.71 billion. Based on
ETO's current estimates, ETO expects to utilize capacity under the ETO Credit
Facilities, along with cash from operations, to fund ETO's announced growth
capital expenditures and working capital needs through the end of 2020; however,
ETO may issue debt or equity securities prior to that time as ETO deems prudent
to provide liquidity for new capital projects, to maintain investment grade
credit metrics or other partnership purposes.
Sunoco LP
Sunoco LP's primary sources of liquidity consist of cash generated from
operating activities, borrowings under its $1.50 billion credit facility and the
issuance of additional long-term debt or partnership units as appropriate given
market conditions. At December 31, 2019, Sunoco LP had available borrowing
capacity of $1.33 billion under its revolving credit facility and $21 million of
cash and cash equivalents on hand.
In 2020, Sunoco LP expects to invest approximately $130 million in growth
capital expenditures and approximately $45 million on maintenance capital
expenditures. Sunoco LP may revise the timing of these expenditures as necessary
to adapt to economic conditions.

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USAC


The compression services business is capital intensive, requiring significant
investment to maintain, expand and upgrade existing operations. USAC's capital
requirements have consisted primarily of, and it anticipates that its capital
requirements will continue to consist primarily of, the following:
•   maintenance capital expenditures, which are capital expenditures made to

maintain the operating capacity of its assets and extend their useful lives,


    to replace partially or fully depreciated assets, or other capital
    expenditures that are incurred in maintaining its existing business and
    related operating income; and

• expansion capital expenditures, which are capital expenditures made to expand

the operating capacity or operating income capacity of assets, including by

acquisition of compression units or through modification of existing

compression units to increase their capacity, or to replace certain partially

or fully depreciated assets that were not currently generating operating

income.




USAC classifies capital expenditures as maintenance or expansion on an
individual asset basis. Over the long-term, USAC expects that its maintenance
capital expenditure requirements will continue to increase as the overall size
and age of its fleet increase. USAC currently plans to spend approximately
$32 million in maintenance capital expenditures during 2020, including parts
consumed from inventory.
Without giving effect to any equipment USAC may acquire pursuant to any future
acquisitions, it currently has budgeted between $110 million and $120 million in
expansion capital expenditures during 2020. As of December 31, 2019, USAC has
binding commitments to purchase $49 million of additional compression units, all
of which USAC expects to be delivered in 2020.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of
which we cannot control. These include regulatory changes, the price of our
products and services, the demand for such products and services, margin
requirements resulting from significant changes in commodity prices, operational
risks, the successful integration of our acquisitions, and other factors.
Operating Activities
Changes in cash flows from operating activities between periods primarily result
from changes in earnings (as discussed in "Results of Operations" above),
excluding the impacts of non-cash items and changes in operating assets and
liabilities. Non-cash items include recurring non-cash expenses, such as
depreciation, depletion and amortization expense and non-cash compensation
expense. The increase in depreciation, depletion and amortization expense during
the periods presented primarily resulted from construction and acquisitions of
assets, while changes in non-cash compensation expense resulted from changes in
the number of units granted and changes in the grant date fair value estimated
for such grants. Cash flows from operating activities also differ from earnings
as a result of non-cash charges that may not be recurring such as impairment
charges and allowance for equity funds used during construction. The allowance
for equity funds used during construction increases in periods when ETO has a
significant amount of interstate pipeline construction in progress. Changes in
operating assets and liabilities between periods result from factors such as the
changes in the value of derivative assets and liabilities, timing of accounts
receivable collection, payments on accounts payable, the timing of purchases and
sales of inventories, and the timing of advances and deposits received from
customers.
Following is a summary of operating activities by period:
Year Ended December 31, 2019
Cash provided by operating activities in 2019 was $8.00 billion and income from
continuing operations was $4.90 billion. The difference between net income and
cash provided by operating activities in 2019 primarily consisted of non-cash
items totaling $3.37 billion offset by net changes in operating assets and
liabilities of $518 million. The non-cash activity in 2019 consisted primarily
of depreciation, depletion and amortization of $3.15 billion, impairment losses
of $74 million, non-cash compensation expense of $113 million, equity in
earnings of unconsolidated affiliates of $302 million, inventory valuation
adjustments of $79 million, losses on extinguishment of debt of $18 million, and
deferred income tax expense of $217 million. The Partnership also received
distributions of $290 million from unconsolidated affiliates.
Year Ended December 31, 2018
Cash provided by operating activities in 2018 was $7.51 billion and income from
continuing operations was $3.63 billion. The difference between net income and
cash provided by operating activities in 2018 primarily consisted of non-cash
items totaling $3.30 billion offset by net changes in operating assets and
liabilities of $289 million. The non-cash activity in 2018 consisted primarily
of depreciation, depletion and amortization of $2.86 billion, impairment losses
of $431 million, non-cash compensation expense of $105 million, equity in
earnings of unconsolidated affiliates of $344 million, inventory valuation
adjustments of

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$85 million, losses on extinguishment of debt of $112 million, and deferred
income tax benefit of $7 million. The Partnership also received distributions of
$328 million from unconsolidated affiliates.
Year Ended December 31, 2017
Cash provided by operating activities in 2017 was $4.43 billion and income from
continuing operations was $2.54 billion. The difference between net income and
cash provided by operating activities in 2017 primarily consisted of non-cash
items totaling $1.82 billion offset by net changes in operating assets and
liabilities of $192 million. The non-cash activity in 2017 consisted primarily
of depreciation, depletion and amortization of $2.55 billion, impairment losses
of $1.04 billion, impairment in unconsolidated affiliates of $313 million,
non-cash compensation expense of $99 million, equity in earnings of
unconsolidated affiliates of $144 million, inventory valuation adjustments of
$24 million, losses on extinguishment of debt of $89 million, and deferred
income tax benefit of $1.87 billion. The Partnership also received distributions
of $297 million from unconsolidated affiliates.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for
acquisitions, capital expenditures, cash distributions from our joint ventures,
and cash proceeds from sales or contributions of assets or businesses. Changes
in capital expenditures between periods primarily result from increases or
decreases in our growth capital expenditures to fund our construction and
expansion projects.
Following is a summary of investing activities by period:
Year Ended December 31, 2019
Cash used in investing activities in 2019 was $6.93 billion. Total capital
expenditures (excluding the allowance for equity funds used during construction
and net of contributions in aid of construction costs) were $5.88 billion.
Additional detail related to our capital expenditures is provided in the table
below. During 2019, we received $93 million of cash proceeds from the sale of a
noncontrolling interest in a subsidiary, paid $787 million in net cash for the
SemGroup acquisition, and paid $7 million in cash for all other acquisitions. We
received $54 million of cash proceeds from the sale of assets. The Partnership
also received distributions of $98 million from unconsolidated affiliates.
Year Ended December 31, 2018
Cash used in investing activities in 2018 was $7.08 billion. Total capital
expenditures (excluding the allowance for equity funds used during construction
and net of contributions in aid of construction costs) were $7.30 billion.
Additional detail related to our capital expenditures is provided in the table
below. We recorded a net increase in cash of $461 million related to the USAC
acquisition and paid $429 million in cash for all other acquisitions. We
received $87 million of cash proceeds from the sale of assets. The Partnership
also received distributions of $69 million from unconsolidated affiliates.
Year Ended December 31, 2017
Cash used in investing activities in 2017 was $5.61 billion. Total capital
expenditures (excluding the allowance for equity funds used during construction
and net of contributions in aid of construction costs) were $8.41 billion.
Additional detail related to our capital expenditures is provided in the table
below. We paid $280 million in cash related to the acquisition of PennTex's
remaining noncontrolling interest and $303 million in cash for all other
acquisitions. We received $2.00 billion in cash related to the Bakken equity
sale to MarEn Bakken Company LLC, $1.48 billion in cash related to the Rover
equity sale to Blackstone Capital Partners. We received $48 million of cash
proceeds from the sale of assets. The Partnership also received distributions of
$135 million from unconsolidated affiliates.

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The following is a summary of the Partnership's capital expenditures (including
only our proportionate share of the Bakken, Rover, and Bayou Bridge pipeline
projects, our proportionate share of the Orbit Gulf Coast NGL export project,
and net of contributions in aid of construction costs) by period:
                                                         Capital

Expenditures Recorded During Period


                                                           Growth           Maintenance        Total
Year Ended December 31, 2019:
Intrastate transportation and storage                $             87     $          37     $      124
Interstate transportation and storage                             239               136            375
Midstream                                                         670               157            827
NGL and refined products transportation and services            2,854               122          2,976
Crude oil transportation and services                             317                86            403
Investment in Sunoco LP                                           108                40            148
Investment in USAC                                                170                30            200
All other (including eliminations)                                165                50            215
Total capital expenditures                           $          4,610     $

658 $ 5,268



Year Ended December 31, 2018:
Intrastate transportation and storage                $            311     $          33     $      344
Interstate transportation and storage                             695               117            812
Midstream                                                       1,026               135          1,161
NGL and refined products transportation and services            2,303                78          2,381
Crude oil transportation and services                             414                60            474
Investment in Sunoco LP (1)                                        72                31            103
Investment in USAC                                                182                23            205
All other (including eliminations)                                117                33            150
Total capital expenditures                           $          5,120     $

510 $ 5,630



Year Ended December 31, 2017:
Intrastate transportation and storage                $            155     $          20     $      175
Interstate transportation and storage                             645                83            728
Midstream                                                       1,185               123          1,308
NGL and refined products transportation and services            2,899                72          2,971
Crude oil transportation and services                             392                61            453
Investment in Sunoco LP (1)                                       129                48            177
All other (including eliminations)                                196                72            268
Total capital expenditures                           $          5,601     $         479     $    6,080


(1)  Amounts related to Sunoco LP's capital expenditures include capital
     expenditures related to discontinued operations.


Financing Activities
Changes in cash flows from financing activities between periods primarily result
from changes in the levels of borrowings and equity issuances, which are
primarily used to fund our acquisitions and growth capital expenditures.
Distributions to partners increased between the periods as a result of increases
in the number of common units outstanding or increases in the distribution rate.

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Following is a summary of financing activities by period:
Year Ended December 31, 2019
Cash used in financing activities was $1.20 billion in 2019. In 2019, our
subsidiaries received $780 million in proceeds from the issuance of preferred
units. In 2019, we had a consolidated increase in our debt level of
$2.48 billion, primarily due to the issuance of subsidiary senior notes. During
2019, we paid distributions of $3.05 billion to our partners and we paid
distributions of $1.60 billion to noncontrolling interests. In addition, we
received capital contributions of $348 million in cash from noncontrolling
interests. During 2019, we incurred debt issuance costs of $117 million.
Year Ended December 31, 2018
Cash used in financing activities was $3.08 billion in 2018. Our subsidiaries
received $1.40 billion in proceeds from the issuance of common units, including
$58 million from the issuance of ETO Common Units and $1.34 billion from the
issuance of other subsidiary common units. In 2018, we had a consolidated
increase in our debt level of $53 million, primarily due to the issuance of
Parent Company and subsidiary senior notes. During 2018, we paid distributions
of $1.68 billion to our partners and we paid distributions of $3.12 billion to
noncontrolling interests. In addition, we received capital contributions of
$649 million in cash from noncontrolling interests. During 2018, we incurred
debt issuance costs of $171 million.
Year Ended December 31, 2017
Cash provided by financing activities was $953 million in 2017. In 2017, we
received $568 million in cash from the issuance of common units and our
subsidiaries received $3.24 billion in proceeds from the issuance of common
units, including $2.28 billion from the issuance of ETO Common Units and
$952 million from the issuance of other subsidiary common units. In 2017, we had
a consolidated increase in our debt level of $340 million, primarily due to the
issuance of Parent Company and subsidiary senior notes. During 2017, we paid
distributions of $1.01 billion to our partners and we paid distributions of
$2.96 billion to noncontrolling interests. In addition, we received capital
contributions of $1.21 billion in cash from noncontrolling interests. During
2017, we incurred debt issuance costs of $131 million.
Discontinued Operations
Following is a summary of activities related to discontinued operations by
period:
Year Ended December 31, 2018
Cash provided by discontinued operations was $2.73 billion for the year ended
December 31, 2018 resulting from cash used in operating activities of
$484 million, cash provided by investing activities of $3.21 billion, and
changes in cash included in current assets held for sale of $11 million.
Year Ended December 31, 2017
Cash provided by discontinued operations was $93 million for the year ended
December 31, 2017 resulting from cash provided by operating activities of
$136 million, cash used in investing activities of $38 million and changes in
cash included in current assets held for sale of $5 million.

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Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
                                                                 December 31,
                                                             2019             2018
Parent Company Indebtedness:
ET Senior Notes due October 2020                        $         52     $

1,187


ET Senior Notes due March 2023                                     5

1,000


ET Senior Notes due January 2024                                  23            1,150
ET Senior Notes due June 2027                                     44            1,000
ET Senior Secured Term Loan                                        -            1,220
Subsidiary Indebtedness:
ETO Senior Notes                                              36,118           28,755
Transwestern Senior Notes                                        575              575
Panhandle Senior Notes                                           235              385
Bakken Senior Notes                                            2,500                -

Sunoco LP Senior Notes, Term Loan and lease-related obligations

                                                    2,935

2,307


USAC Senior Notes                                              1,475

725


Credit Facilities and Commercial Paper:
ETO $2.00 billion Term Loan facility due October 2022          2,000


ETO $5.00 billion Revolving Credit Facility due
December 2023                                                  4,214

3,694

Sunoco LP $1.50 billion Revolving Credit Facility due July 2023

700

USAC $1.60 billion Revolving Credit Facility due April 2023

1,050


Bakken $2.50 billion Credit Facility due August 2019               -

2,500


HFOTCO Tax Exempt Notes due 2050                                 225


SemCAMS Revolver due February 2024                                92


SemCAMS Term Loan A due February 2024                            269


Other long-term debt                                               2


Unamortized premiums, net of discounts and fair value
adjustments                                                        4               21
Deferred debt issuance costs                                    (279 )           (248 )
Total debt                                                    51,054           46,028
Less: current maturities of long-term debt                        26

2,655


Long-term debt, less current maturities                 $     51,028     $

43,373




The terms of our consolidated indebtedness and that of our subsidiaries are
described in more detail below and in Note 6 to our consolidated financial
statements, included in "Item 8. Financial Statements and Supplementary Data."
Recent Transactions
ETO January 2020 Senior Notes Offering and Redemption
On January 22, 2020, ETO completed a registered offering (the "January 2020
Senior Notes Offering") of $1.00 billion aggregate principal amount of ETO's
2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of ETO's
3.750% Senior Notes due 2030, and $2.00 billion aggregate principal amount of
ETO's 5.000% Senior Notes due 2050, (collectively, the "Notes"). The Notes are
fully and unconditionally guaranteed by the Partnership's wholly-owned
subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured
basis.
Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its
$400 million aggregate principal amount of 5.75% Senior Notes due September 1,
2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due
October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior
Notes due October 15, 2020, its $250 million aggregate principal

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amount of 5.50% Senior Notes due February 15, 2020, ET's $52 million aggregate
principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern's
$175 million aggregate principal amount of 5.36% Senior Notes due December 9,
2020.
ETO Term Loan
On October 17, 2019, ETO entered into a term loan credit agreement (the "ETO
Term Loan") providing for a $2.00 billion three-year term loan credit facility.
Borrowings under the term loan agreement mature on October 17, 2022 and are
available for working capital purposes and for general partnership purposes. The
term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco
Logistics Partners Operations L.P.
ET-ETO Senior Notes Exchange
In February 2019, ETO commenced offers to exchange all of ET's outstanding
senior notes for senior notes issued by ETO (the "ET-ETO senior notes
exchange").  Approximately 97% of ET's outstanding senior notes were tendered
and accepted, and substantially all the exchanges settled on March 25, 2019. In
connection with the exchange, ETO issued approximately $4.21 billion aggregate
principal amount of the following senior notes:
• $1.14 billion aggregate principal amount of 7.50% senior notes due 2020;

• $995 million aggregate principal amount of 4.25% senior notes due 2023;

• $1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and

• $956 million aggregate principal amount of 5.50% senior notes due 2027.

ETO 2019 Senior Notes Offering and Redemption In January 2019, ETO issued the following senior notes: • $750 million aggregate principal amount of 4.50% senior notes due 2024;

• $1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and

• $1.75 billion aggregate principal amount of 6.25% senior notes due 2049.

The $3.96 billion net proceeds from the offering were used to make an intercompany loan to ET (which ET used to repay its term loan in full), for general partnership purposes and to redeem at maturity all of the following: • ETO's $400 million aggregate principal amount of 9.70% senior notes due March

15, 2019;

• ETO's $450 million aggregate principal amount of 9.00% senior notes due April

15, 2019; and

• Panhandle's $150 million aggregate principal amount of 8.125% senior notes

due June 1, 2019.




Panhandle Senior Notes Redemption
In June 2019, Panhandle's $150 million aggregate principal amount of 8.125%
senior notes matured and were repaid with borrowings under an affiliate loan
agreement with ETO.
Bakken Senior Notes Offering
In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary
of Dakota Access, issued the following senior notes related to the Bakken
pipeline:
• $650 million aggregate principal amount of 3.625% senior notes due 2022;

• $1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and

• $850 million aggregate principal amount of 4.625% senior notes due 2029.




The $2.48 billion in net proceeds from the offering were used to repay in full
all amounts outstanding on the Bakken credit facility and the facility was
terminated.
Sunoco LP Senior Notes Offering
In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00%
senior notes due 2027 in a private placement to eligible purchasers. The net
proceeds from this offering were used to repay a portion of Sunoco LP's existing
borrowings under its credit facility. In July 2019, Sunoco LP completed an
exchange of these notes for registered notes with substantially identical terms.

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USAC Senior Notes Offering
In March 2019, USAC issued $750 million aggregate principal amount of 6.875%
senior notes due 2027 in a private placement, and in December 2019, USAC
exchanged those notes for substantially identical senior notes registered under
the Securities Act. The net proceeds from this offering were used to repay a
portion of USAC's existing borrowings under its credit facility and for general
partnership purposes.
Credit Facilities and Commercial Paper
Parent Company Credit Facility
In connection with the closing of the Energy Transfer Merger, on October 19,
2018, the Partnership repaid in full all outstanding borrowings under the
facility and the facility was terminated.
ETO Credit Facilities
Borrowings under the ETO Credit Facilities are unsecured and initially
guaranteed by Sunoco Logistics Partners Operations L.P.  Borrowings under the
ETO Credit Facilities will bear interest at a eurodollar rate or a base rate, at
our option, plus an applicable margin.  In addition, we will be required to pay
a quarterly commitment fee to each lender equal to the product of the applicable
rate and such lender's applicable percentage of the unused portion of the
aggregate commitments under the ETO Credit Facilities.
We typically repay amounts outstanding under the ETO Credit Facilities with
proceeds from unit offerings or long-term notes offerings. The timing of
borrowings depends on the Partnership's activities and the cash available to
fund those activities. The repayments of amounts outstanding under the ETO
Credit Facilities depend on multiple factors, including market conditions and
expectations of future working capital needs, and ultimately are a financing
decision made by management. Therefore, the balance outstanding under the ETO
Credit Facilities may vary significantly between periods. We do not believe that
such fluctuations indicate a significant change in our liquidity position,
because we expect to continue to be able to repay amounts outstanding under the
ETO Credit Facilities with proceeds from unit offerings or long-term note
offerings.
ETO Term Loan
On October 17, 2019, ETO entered into a term loan credit agreement (the "ETO
Term Loan") providing for a $2.00 billion three-year term loan credit facility.
Borrowings under the term loan agreement mature on October 17, 2022 and are
available for working capital purposes and for general partnership purposes. The
term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco
Logistics Partners Operations L.P.
As of December 31, 2019, the ETO Term Loan had $2.00 billion outstanding and was
fully drawn. The weighted average interest rate on the total amount outstanding
as of December 31, 2019 was 2.78%.
ETO Five-Year Credit Facility
ETO's revolving credit facility (the "ETO Five-Year Credit Facility") allows for
unsecured borrowings up to $5.00 billion and matures on December 1, 2023. The
ETO Five-Year Credit Facility contains an accordion feature, under which the
total aggregate commitment may be increased up to $6.00 billion under certain
conditions.
As of December 31, 2019, the ETO Five-Year Credit Facility had $4.21 billion
outstanding, of which $1.64 billion was commercial paper. The amount available
for future borrowings was $709 million after taking into account letters of
credit of $77 million. The weighted average interest rate on the total amount
outstanding as of December 31, 2019 was 2.88%.
ETO 364-Day Facility
ETO's 364-day revolving credit facility (the "ETO 364-Day Facility") allows for
unsecured borrowings up to $1.00 billion and matures on November 27, 2020. As of
December 31, 2019, the ETO 364-Day Facility had no outstanding borrowings.
Sunoco LP Credit Facility
As of December 31, 2019, the Sunoco LP Credit Facility had $162 million
outstanding borrowings and $8 million in standby letters of credit. The amount
available for future borrowings was at December 31, 2019 was $1.33 billion. The
weighted average interest rate on the total amount outstanding as of
December 31, 2019 was 3.75%.

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USAC Credit Facility
As of December 31, 2019, USAC had $403 million of outstanding borrowings and no
outstanding letters of credit under the credit agreement. As of December 31,
2019, USAC had $1.20 billion of availability under its credit facility. The
weighted average interest rate on the total amount outstanding as of
December 31, 2019 was 4.31%.
SemCAMS Credit Facilities
SemCAMS is party to a credit agreement providing for a C$350 million (US$270
million at the December 31, 2019 exchange rate) senior secured term loan
facility, a C$$525 million (US$404 million at the December 31, 2019 exchange
rate) senior secured revolving credit facility, and a C$300 million (US$231
million at the December 31, 2019 exchange rate) senior secured construction loan
facility (the "KAPS Facility"). The term loan facility and the revolving credit
facility mature on February 25, 2024. The KAPS Facility matures on June 13,
2024. SemCAMS may incur additional term loans and revolving commitments in an
aggregate amount not to exceed C$250 million (US$193 million at the December 31,
2019 exchange rate), subject to receiving commitments for such additional term
loans or revolving commitments from either new lenders or increased commitments
from existing lenders.
Covenants Related to Our Credit Agreements
Covenants Related to the Parent Company
The Term Loan Facility and ET Revolving Credit Facility previously contained
customary representations, warranties, covenants, and events of default,
including a change of control event of default and limitations on incurrence of
liens, new lines of business, merger, transactions with affiliates and
restrictive agreements. Both facilities have been paid off and terminated.
Covenants Related to ETO
The agreements relating to the ETO senior notes contain restrictive covenants
customary for an issuer with an investment-grade rating from the rating
agencies, which covenants include limitations on liens and a restriction on
sale-leaseback transactions.
The ETO Credit Facilities contain covenants that limit (subject to certain
exceptions) the Partnership's and certain of the Partnership's subsidiaries'
ability to, among other things:
• incur indebtedness;


• grant liens;


• enter into mergers;


• dispose of assets;


• make certain investments;

• make Distributions (as defined in the ETO Credit Facilities) during certain

Defaults (as defined in the ETO Credit Facilities) and during any Event of

Default (as defined in the ETO Credit Facilities);

• engage in business substantially different in nature than the business

currently conducted by the Partnership and its subsidiaries;

• engage in transactions with affiliates; and

• enter into restrictive agreements.




The ETO Credit Facilities applicable margin and rate used in connection with the
interest rates and commitment fees, respectively, are based on the credit
ratings assigned to our senior, unsecured, non-credit enhanced long-term debt.
The applicable margin for eurodollar rate loans under the ETO Five-Year Facility
ranges from 1.125% to 2.000% and the applicable margin for base rate loans
ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the
ETO Five-Year Facility ranges from 0.125% to 0.300%.  The applicable margin for
eurodollar rate loans under the ETO 364-Day Facility ranges from 1.250% to
1.750% and the applicable margin for base rate loans ranges from 0.250% to
0.750%. The applicable rate for commitment fees under the ETO 364-Day Facility
ranges from 0.125% to 0.225%.
The ETO Credit Facilities contain various covenants including limitations on the
creation of indebtedness and liens, and related to the operation and conduct of
our business. The ETO Credit Facilities also limit us, on a rolling four quarter
basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA
ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can
generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our
Leverage Ratio was 4.04 to 1 at December 31, 2019, as calculated in accordance
with the credit agreements.

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The agreements relating to the Transwestern senior notes contain certain
restrictions that, among other things, limit the incurrence of additional debt,
the sale of assets and the payment of dividends and specify a maximum debt to
capitalization ratio.
Failure to comply with the various restrictive and affirmative covenants of our
revolving credit facilities could require us to pay debt balances prior to
scheduled maturity and could negatively impact the Partnership's or our
subsidiaries' ability to incur additional debt and/or our ability to pay
distributions to Unitholders.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the
maturity date of any obligation due to a failure to maintain any specific credit
rating, nor would a reduction in any credit rating, by itself, cause an event of
default under any of Panhandle's lending agreements.
Panhandle's restrictive covenants include restrictions on liens securing debt
and guarantees and restrictions on mergers and on the sales of assets. A breach
of any of these covenants could result in acceleration of Panhandle's debt.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility contains various customary representations,
warranties, covenants and events of default, including a change of control event
of default, as defined therein. Sunoco LP's Credit Facility requires Sunoco LP
to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net
Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a
period not to exceed three fiscal quarters in the event Sunoco LP engages in
certain specified acquisitions of not less than $50 million (as permitted under
Sunoco LP's Credit Facility agreement). The Sunoco LP Credit Facility also
requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the
Sunoco LP's Credit Facility agreement) of not less than 2.25 to 1.
Covenants Related to USAC
The USAC Credit Facility contains covenants that limit (subject to certain
exceptions) USAC's ability to, among other things:
• grant liens;

• make certain loans or investments;

• incur additional indebtedness or guarantee other indebtedness;




• merge or consolidate;


• sell our assets; or

• make certain acquisitions.

The credit facility is also subject to the following financial covenants, including covenants requiring us to maintain: • a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of

the last day of each fiscal quarter; and

• a maximum funded debt to EBITDA ratio, determined as of the last day of each

fiscal quarter, for the annualized trailing three months of (i) 5.5 to 1

through the end of the fiscal quarter ending December 31, 2019 and (ii) 5.0

to 1.0 thereafter, in each case subject to a provision for increases to such

thresholds by 0.50 in connection with certain future acquisitions for the six

consecutive month period following the period in which any such acquisition

occurs.




Covenants Related to the HFOTCO Tax Exempt Notes
The indentures covering HFOTCO's tax exempt notes due 2050 ("IKE Bonds") include
customary representations and warranties and affirmative and negative covenants.
Such covenants include limitations on the creation of new liens, indebtedness,
making of certain restricted payments and payments on indebtedness, making
certain dispositions, making material changes in business activities, making
fundamental changes including liquidations, mergers or consolidations, making
certain investments, entering into certain transactions with affiliates, making
amendments to certain credit or organizational agreements, modifying the fiscal
year, creating or dealing with hazardous materials in certain ways, entering
into certain hedging arrangements, entering into certain restrictive agreements,
funding or engaging in sanctioned activities, taking actions or causing the
trustee to take actions that materially adversely affect the rights, interests,
remedies or security of the bondholders, taking actions to remove the trustee,
making certain amendments to the bond documents, and taking actions or omitting
to take actions that adversely impact the tax exempt status of the IKE Bonds.

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Compliance with our Covenants
We and our subsidiaries were in compliance with all requirements, tests,
limitations, and covenants related to our debt agreements as of December 31,
2019.
Contractual Obligations
The following table summarizes our long-term debt and other contractual
obligations as of December 31, 2019:
                                                       Payments Due by Period
                                           Less Than 1                                      More Than 5
Contractual Obligations       Total            Year          1-3 Years       3-5 Years         Years
Long-term debt             $   51,329     $      3,086     $     7,204     $    13,673     $     27,366
Interest on long-term
debt(1)                        41,196            2,545           4,958           4,306           29,387
Payments on derivatives           401              150             251               -                -
Purchase commitments(2)         2,133            2,053              57               7               16
Transportation, natural
gas storage and
fractionation contracts            16                5               6               5                -
Operating lease
obligations                     1,548               98             166             140            1,144
Service concession
arrangement(3)                    379               15              30              32              302
Other(4)                          190               25              48              40               77
Total(5)                   $   97,192     $      7,977     $    12,720     $    18,203     $     58,292

(1) Interest payments on long-term debt are based on the principal amount of

debt obligations as of December 31, 2019. With respect to variable rate

debt, the interest payments were estimated using the interest rate as of

December 31, 2019. To the extent interest rates change, our contractual

obligations for interest payments will change. See "Item 7A. Quantitative

and Qualitative Disclosures About Market Risk" for further discussion.

(2) We define a purchase commitment as an agreement to purchase goods or

services that is enforceable and legally binding (unconditional) on us that

specifies all significant terms, including: fixed or minimum quantities to

be purchased; fixed, minimum or variable price provisions; and the

approximate timing of the transactions. We have long and short-term product

purchase obligations for refined product and energy commodities with

third-party suppliers. These purchase obligations are entered into at either

variable or fixed prices. The purchase prices that we are obligated to pay

under variable price contracts approximate market prices at the time we take

delivery of the volumes. Our estimated future variable price contract

payment obligations are based on the December 31, 2019 market price of the

applicable commodity applied to future volume commitments. Actual future

payment obligations may vary depending on market prices at the time of

delivery. The purchase prices that we are obligated to pay under fixed price

contracts are established at the inception of the contract. Our estimated

future fixed price contract payment obligations are based on the contracted

fixed price under each commodity contract. Obligations shown in the table


     represent estimated payment obligations under these contracts for the
     periods indicated.

(3) Includes minimum guaranteed payments under service concession arrangements

with New Jersey Turnpike Authority and New York Thruway Authority.

(4) Expected contributions to fund our pension and postretirement benefit plans

were included in "Other" above. Environmental liabilities, AROs,

unrecognized tax benefits, contingency accruals and deferred revenue, which

were included in "Other non-current liabilities" in our consolidated balance

sheets were excluded from the table above as the amounts do not represent

contractual obligations or, in some cases, the amount and/or timing of the

cash payments is uncertain.

(5) Excludes net non-current deferred tax liabilities of $3.21 billion due to

uncertainty of the timing of future cash flows for such liabilities.




Cash Distributions
Cash Distributions Paid by the Parent Company
Under the Parent Company Partnership Agreement, the Parent Company will
distribute all of its Available Cash, as defined, within 50 days following the
end of each fiscal quarter. Available cash generally means, with respect to any
quarter, all cash on hand at the end of such quarter less the amount of cash
reserves that are necessary or appropriate in the reasonable discretion of the
General Partner that is necessary or appropriate to provide for future cash
requirements.

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Distributions declared and paid are as follows:


 Quarter Ended            Record Date        Payment Date        Rate

December 31, 2016 (1) February 7, 2017 February 21, 2017 $ 0.2850 March 31, 2017 May 10, 2017 May 19, 2017 0.2850 June 30, 2017

           August 7, 2017     August 21, 2017       0.2850

September 30, 2017 November 7, 2017 November 20, 2017 0.2950 December 31, 2017 February 8, 2018 February 20, 2018 0.3050 March 31, 2018 May 7, 2018 May 21, 2018 0.3050 June 30, 2018

           August 6, 2018     August 20, 2018       0.3050

September 30, 2018 November 8, 2018 November 19, 2018 0.3050 December 31, 2018 February 8, 2019 February 19, 2019 0.3050 March 31, 2019 May 7, 2019 May 20, 2019 0.3050 June 30, 2019

           August 6, 2019     August 19, 2019       0.3050

September 30, 2019 November 5, 2019 November 19, 2019 0.3050 December 31, 2019 February 7, 2020 February 19, 2020 0.3050

(1) Certain common unitholders elected to participate in a plan pursuant to

which those unitholders elected to forego their cash distributions on all or

a portion of their common units for a period of up to nine quarters

commencing with the distribution for the quarter ended March 31, 2016 and,

in lieu of receiving cash distributions on these common units for each such

quarter, each said unitholder received ET Series A Convertible Preferred

Units (on a one-for-one basis for each common unit as to which the

participating unitholder elected be subject to this plan) that entitled them

to receive a cash distribution of up to $0.11 per unit. See Note 8 to the

Partnership's consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data."

Our distributions declared and paid with respect to ET Series A Convertible Preferred Unit were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2016 February 7, 2017 February 21, 2017 $ 0.1100 March 31, 2017 May 10, 2017 May 19, 2017 0.1100 June 30, 2017 August 7, 2017 August 21, 2017 0.1100 September 30, 2017 November 7, 2017 November 20, 2017 0.1100 December 31, 2017 February 8, 2018 February 20, 2018 0.1100 March 31, 2018 May 7, 2018 May 21, 2018 0.1100

The total amounts of distributions declared and paid during the periods presented (all from Available Cash from the Parent Company's operating surplus and are shown in the period to which they relate) are as follows:


                                          Years Ended December 31,
                                        2019         2018 (1)       2017
Limited Partners                   $   3,221        $    2,215    $ 1,022
General Partner interest                   4                 3          3

Total Parent Company distributions $ 3,225 $ 2,218 $ 1,025

(1) Include distributions declared by Energy Transfer LP for periods subsequent


      to the Energy Transfer Merger.



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The total amounts of distributions declared and paid during the periods
presented prior to the closing of the Energy Transfer Merger as discussed in
Note 1 (all from Available Cash from ETO's operating surplus and are shown in
the period to which they relate) are as follows:
                                            Years Ended December 31,
                                              2018             2017
Common Units held by public              $     1,286       $     2,435
Common Units held by ET                           31                61
General Partner interest and IDRs                900             1,654
IDR relinquishments (1)                          (84 )            (656 )
Series A Preferred Units                          59                15
Series B Preferred Units                          36                 9
Series C Preferred Units (2)                      23                 -
Series D Preferred Units (2)                      15                 -

Total distributions declared to partners $ 2,266 $ 3,518




(1)  Net of Class I unit distributions

(2) Distributions reflect prorated distributions for the year ended December 31,

2018.




Cash Distributions Paid by Subsidiaries
Certain of our subsidiaries are required by their respective partnership
agreements to distribute all cash on hand at the end of each quarter, less
appropriate reserves determined by the board of directors of their respective
general partners.
ETO Preferred Unit Distributions
Distributions on the ETO's Series A, Series B, Series C, Series D and Series E
preferred units declared and/or paid by ETO were as follows:
   Period Ended        Record Date        Payment Date        Series A (1)        Series B (1)       Series C       Series D       Series E
December 31, 2017    February 1, 2018   February 15, 2018   $      15.4510   *  $      16.3780   *  $       -      $       -      $       -
June 30, 2018        August 1, 2018     August 15, 2018            31.2500             33.1250         0.5634   *          -              -
September 30, 2018   November 1, 2018   November 15, 2018                -                   -         0.4609         0.5931   *          -
December 31, 2018    February 1, 2019   February 15, 2019          31.2500             33.1250         0.4609         0.4766              -
March 31, 2019       May 1, 2019        May 15, 2019                     -                   -         0.4609         0.4766              -
June 30, 2019        August 1, 2019     August 15, 2019            31.2500             33.1250         0.4609         0.4766         0.5806   *
September 30, 2019   November 1, 2019   November 15, 2019                -                   -         0.4609         0.4766         0.4750
December 31, 2019    February 3, 2020   February 18, 2020          31.2500             33.1250         0.4609         0.4766         0.4750

* Represent prorated initial distributions. Prorated initial distributions on

the recently issued ETO Series F Preferred Units and ETO Series G Preferred

Units will be payable in May 2020.

(1) ETO Series A Preferred Units and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.

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Sunoco LP Cash Distributions
The following table illustrates the percentage allocations of available cash
from operating surplus between Sunoco LP's common unitholders and the holder of
its IDRs based on the specified target distribution levels, after the payment of
distributions to Class C unitholders. The amounts set forth under "marginal
percentage interest in distributions" are the percentage interests of the IDR
holder and the common unitholders in any available cash from operating surplus
which Sunoco LP distributes up to and including the corresponding amount in the
column "total quarterly distribution per unit target amount." The percentage
interests shown for common unitholders and IDR holder for the minimum quarterly
distribution are also applicable to quarterly distribution amounts that are less
than the minimum quarterly distribution.
                                                                   Marginal Percentage
                                                                Interest in Distributions
                                 Total Quarterly Distribution     Common       Holder of
                                        Target Amount           Unitholders       IDRs
Minimum Quarterly Distribution              $0.4375                100%            -%
First Target Distribution            $0.4375 to $0.503125          100%            -%
Second Target Distribution          $0.503125 to $0.546875          85%           15%
Third Target Distribution           $0.546875 to $0.656250          75%           25%
Thereafter                             Above $0.656250              50%           50%

Distributions on Sunoco LP's units declared and/or paid by Sunoco LP were as follows:

Quarter Ended Record Date Payment Date Rate December 31, 2016 February 13, 2017 February 21, 2017 $ 0.8255 March 31, 2017 May 9, 2017 May 16, 2017 0.8255 June 30, 2017 August 7, 2017 August 15, 2017 0.8255 September 30, 2017 November 7, 2017 November 14, 2017 0.8255 December 31, 2017 February 6, 2018 February 14, 2018 0.8255 March 31, 2018 May 7, 2018 May 15, 2018 0.8255 June 30, 2018 August 7, 2018 August 15, 2018 0.8255 September 30, 2018 November 6, 2018 November 14, 2018 0.8255 December 31, 2018 February 6, 2019 February 14, 2019 0.8255 March 31, 2019 May 7, 2019 May 15, 2019 0.8255 June 30, 2019 August 6, 2019 August 14, 2019 0.8255 September 30, 2019 November 5, 2019 November 19, 2019 0.8255 December 31, 2019 February 7, 2020 February 19, 2020 0.8255

The total amount of distributions to the Partnership from Sunoco LP for the periods presented below is as follows:


                                          Years Ended December 31,
                                           2019            2018     2017
Distributions from Sunoco LP
Limited Partner interests          $      94              $  94    $ 150
General Partner interest and IDRs         70                 70       85
Series A Preferred                         -                  2       23
Total distributions from Sunoco LP $     164              $ 166    $ 258


USAC Cash Distributions
Subsequent to the Energy Transfer Merger and USAC Transactions described in Note
1 and Note 3, respectively, ETO owned approximately 39.7 million USAC common
units and 6.4 million USAC Class B units. Subsequent to the conversion of the
USAC

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Class B Units to USAC common units on July 30, 2019, ETO owns approximately 46.1
million USAC common units. As of December 31, 2019, USAC had approximately
96.6 million common units outstanding. USAC currently has a non-economic general
partner interest and no outstanding IDRs.
Distributions on USAC's units declared and/or paid by USAC subsequent to the
USAC transaction on April 2, 2018 were as follows:

Quarter Ended Record Date Payment Date Rate March 31, 2018 May 1, 2018 May 11, 2018 $ 0.5250 June 30, 2018 July 30, 2018 August 10, 2018 0.5250 September 30, 2018 October 29, 2018 November 09, 2018 0.5250 December 31, 2018 January 28, 2019 February 8, 2019 0.5250 March 31, 2019 April 29, 2019 May 10, 2019 0.5250 June 30, 2019 July 29, 2019 August 9, 2019 0.5250 September 30, 2019 October 28, 2019 November 8, 2019 0.5250 December 31, 2019 January 27, 2020 February 7, 2020 0.5250

The total amount of distributions to the Partnership from USAC for the periods presented below is as follows:


                                       Years Ended December 31,
                                        2019              2018     2017
Distributions from USAC
Limited Partner interests     $      90                  $  73    $   -
Total distributions from USAC $      90                  $  73    $   -


Estimates and Critical Accounting Policies
The selection and application of accounting policies is an important process
that has developed as our business activities have evolved and as the accounting
rules have developed. Accounting rules generally do not involve a selection
among alternatives, but involve an implementation and interpretation of existing
rules, and the use of judgment applied to the specific set of circumstances
existing in our business. We make every effort to properly comply with all
applicable rules, and we believe the proper implementation and consistent
application of the accounting rules are critical. Our critical accounting
policies are discussed below. For further details on our accounting policies see
Note 2 to our consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity with
GAAP requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and the accrual for and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period. The
natural gas industry conducts its business by processing actual transactions at
the end of the month following the month of delivery. Consequently, the most
current month's financial results for the midstream, NGL and intrastate
transportation and storage segments are estimated using volume estimates and
market prices. Any differences between estimated results and actual results are
recognized in the following month's financial statements. Management believes
that the operating results estimated for the year ended December 31, 2019
represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not
limited to, the timing of certain forecasted transactions that are hedged, the
fair value of derivative instruments, useful lives for depreciation, depletion
and amortization, purchase accounting allocations and subsequent realizability
of intangible assets, fair value measurements used in the goodwill impairment
test, market value of inventory, assets and liabilities resulting from the
regulated ratemaking process, contingency reserves and environmental reserves.
Actual results could differ from those estimates.
Revenue Recognition. Revenues for sales of natural gas and NGLs are recognized
at the later of the time of delivery of the product to the customer or the time
of sale. Revenues from service labor, transportation, treating, compression and
gas processing, are recognized upon completion of the service. Transportation
capacity payments are recognized when earned in the period the capacity is made
available.
Our intrastate transportation and storage and interstate transportation and
storage segments' results are determined primarily by the amount of capacity our
customers reserve as well as the actual volume of natural gas that flows through
the transportation

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pipelines. Under transportation contracts, our customers are charged (i) a
demand fee, which is a fixed fee for the reservation of an agreed amount of
capacity on the transportation pipeline for a specified period of time and which
obligates the customer to pay even if the customer does not transport natural
gas on the respective pipeline, (ii) a transportation fee, which is based on the
actual throughput of natural gas by the customer, (iii) fuel retention based on
a percentage of gas transported on the pipeline, or (iv) a combination of the
three, generally payable monthly. Excess fuel retained after consumption is
typically valued at market prices.
Our intrastate transportation and storage segment also generates revenues and
margin from the sale of natural gas to electric utilities, independent power
plants, local distribution companies, industrial end-users and other marketing
companies on the HPL System. Generally, we purchase natural gas from the market,
including purchases from our marketing operations, and from producers at the
wellhead.
In addition, our intrastate transportation and storage segment generates
revenues and margin from fees charged for storing customers' working natural gas
in our storage facilities. We also engage in natural gas storage transactions in
which we seek to find and profit from pricing differences that occur over time
utilizing the Bammel storage reservoir. We purchase physical natural gas and
then sell financial contracts at a price sufficient to cover our carrying costs
and provide for a gross profit margin. We expect margins from natural gas
storage transactions to be higher during the periods from November to March of
each year and lower during the period from April through October of each year
due to the increased demand for natural gas during colder weather. However, we
cannot assure that management's expectations will be fully realized in the
future and in what time period, due to various factors including weather,
availability of natural gas in regions in which we operate, competitive factors
in the energy industry, and other issues.
Lake Charles LNG's revenues from storage and re-gasification of natural gas are
based on capacity reservation charges and, to a lesser extent, commodity usage
charges. Reservation revenues are based on contracted rates and capacity
reserved by the customers and recognized monthly. Revenues from commodity usage
charges are also recognized monthly and represent the recovery of electric power
charges at Lake Charles LNG's terminal.
Results from the midstream segment are determined primarily by the volumes of
natural gas gathered, compressed, treated, processed, purchased and sold through
our pipeline and gathering systems and the level of natural gas and NGL prices.
We generate midstream revenues and segment margins principally under fee-based
or other arrangements in which we receive a fee for natural gas gathering,
compressing, treating or processing services. The revenue earned from these
arrangements is directly related to the volume of natural gas that flows through
our systems and is not directly dependent on commodity prices. Our midstream
segment also generates revenues from the sale of residue gas and NGLs at the
tailgate of our processing facilities primarily to affiliates and some
third-party customers.
We also utilize other types of arrangements in our midstream segment, including
(i) discount-to-index price arrangements, which involve purchases of natural gas
at either (1) a percentage discount to a specified index price, (2) a specified
index price less a fixed amount or (3) a percentage discount to a specified
index price less an additional fixed amount, (ii) percentage-of-proceeds
arrangements under which we gather and process natural gas on behalf of
producers, sell the resulting residue gas and NGL volumes at market prices and
remit to producers an agreed upon percentage of the proceeds based on an index
price, and (iii) keep-whole arrangements where we gather natural gas from the
producer, process the natural gas and sell the resulting NGLs to third parties
at market prices. In many cases, we provide services under contracts that
contain a combination of more than one of the arrangements described above. The
terms of our contracts vary based on gas quality conditions, the competitive
environment at the time the contracts are signed and customer requirements. Our
contract mix may change as a result of changes in producer preferences,
expansion in regions where some types of contracts are more common and other
market factors.
We conduct marketing activities in which we market the natural gas that flows
through our assets, referred to as on-system gas. We also attract other
customers by marketing volumes of natural gas that do not move through our
assets, referred to as off-system gas. For both on-system and off-system gas, we
purchase natural gas from natural gas producers and other supply points and sell
that natural gas to utilities, industrial consumers, other marketers and
pipeline companies, thereby generating gross margins based upon the difference
between the purchase and resale prices.
We have a risk management policy that provides for oversight over our marketing
activities. These activities are monitored independently by our risk management
function and must take place within predefined limits and authorizations. As a
result of our use of derivative financial instruments that may not qualify for
hedge accounting, the degree of earnings volatility that can occur may be
significant, favorably or unfavorably, from period to period. We attempt to
manage this volatility through the use of daily position and profit and loss
reports provided to senior management and predefined limits and authorizations
set forth in our risk management policy.
We inject and hold natural gas in our Bammel storage facility to take advantage
of contango markets, when the price of natural gas is higher in the future than
the current spot price. We use financial derivatives to hedge the natural gas
held in connection with these arbitrage opportunities. At the inception of the
hedge, we lock in a margin by purchasing gas in the spot market or off peak

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season and entering a financial contract to lock in the sale price. If we
designate the related financial contract as a fair value hedge for accounting
purposes, we value the hedged natural gas inventory at current spot market
prices along with the financial derivative we use to hedge it. Changes in the
spread between the forward natural gas prices designated as fair value hedges
and the physical inventory spot prices result in unrealized gains or losses
until the underlying physical gas is withdrawn and the related designated
derivatives are settled. Once the gas is withdrawn and the designated
derivatives are settled, the previously unrealized gains or losses associated
with these positions are realized. Unrealized margins represent the unrealized
gains or losses from our derivative instruments using mark-to-market accounting,
with changes in the fair value of our derivatives being recorded directly in
earnings. These margins fluctuate based upon changes in the spreads between the
physical spot prices and forward natural gas prices. If the spread narrows
between the physical and financial prices, we will record unrealized gains or
lower unrealized losses. If the spread widens, we will record unrealized losses
or lower unrealized gains. Typically, as we enter the winter months, the spread
converges so that we recognize in earnings the original locked in spread, either
through mark-to-market or the physical withdrawal of natural gas.
NGL storage and pipeline transportation revenues are recognized when services
are performed or products are delivered, respectively. Fractionation and
processing revenues are recognized when product is either loaded into a truck or
injected into a third-party pipeline, which is when title and risk of loss pass
to the customer.
In our natural gas compression business, revenue is recognized for compressor
packages and technical service jobs using the completed contract method which
recognizes revenue upon completion of the job. Costs incurred on a job are
deducted at the time revenue is recognized.
Terminalling and storage revenues are recognized at the time the services are
provided. Pipeline revenues are recognized upon delivery of the barrels to the
location designated by the shipper. Crude oil acquisition and marketing
revenues, as well as refined product marketing revenues, are recognized when
title to the product is transferred to the customer. Revenues are not recognized
for crude oil exchange transactions, which are entered into primarily to acquire
crude oil of a desired quality or to reduce transportation costs by taking
delivery closer to end markets. Any net differential for exchange transactions
is recorded as an adjustment of inventory costs in the purchases component of
cost of products sold and operating expenses in the statements of operations.
Investment in Sunoco LP
Sunoco LP's revenues from motor fuel are recognized either at the time fuel is
delivered to the customer or at the time of sale. Shipment and delivery of motor
fuel generally occurs on the same day. Sunoco LP charges wholesale customers for
third-party transportation costs, which are recorded net in cost of sales.
Through PropCo, Sunoco LP's wholly-owned corporate subsidiary, Sunoco LP may
sell motor fuel to customers on a commission agent basis, in which Sunoco LP
retains title to inventory, controls access to and sale of fuel inventory, and
recognizes revenue at the time the fuel is sold to the ultimate customer. In
Sunoco LP's fuel distribution and marketing operations, Sunoco LP derives other
income from rental income, propane and lubricating oils, and other ancillary
product and service offerings. In Sunoco LP's other operations, Sunoco LP
derives other income from merchandise, lottery ticket sales, money orders,
prepaid phone cards and wireless services, ATM transactions, car washes, movie
rentals, and other ancillary product and service offerings. Sunoco LP records
revenue from other retail transactions on a net commission basis when a product
is sold and/or services are rendered.
Investment in USAC
USAC's revenue from contracted compression, station, gas treating and
maintenance services is recognized ratably under its fixed-fee contracts over
the term of the contract as services are provided to its customers. Initial
contract terms typically range from six months to five years. However, USAC
usually continues to provide compression services at a specific location beyond
the initial contract term, either through contract renewal or on a
month-to-month or longer basis. USAC primarily enters into fixed-fee contracts
whereby its customers are required to pay its monthly fee even during periods of
limited or disrupted throughput. Services are generally billed monthly, one
month in advance of the commencement of the service month, except for certain
customers who are billed at the beginning of the service month, and payment is
generally due 30 days after receipt of the invoice. Amounts invoiced in advance
are recorded as deferred revenue until earned, at which time they are recognized
as revenue. The amount of consideration USAC receives and revenue it recognizes
is based upon the fixed fee rate stated in each service contract.
USAC's retail parts and services revenue is earned primarily on freight and
crane charges that are directly reimbursable by its customers and maintenance
work on units at its customers' locations that are outside the scope of USAC's
core maintenance activities. Revenue from retail parts and services is
recognized at the point in time the part is transferred or service is provided
and control is transferred to the customer. At such time, the customer has the
ability to direct the use of the benefits of such part or service after USAC has
performed its services. USAC bills upon completion of the service or transfer of
the parts, and payment is generally due 30 days after receipt of the invoice.
The amount of consideration USAC receives and revenue it recognizes is based
upon the invoice amount.

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Lease Accounting.  At the inception of each lease arrangement, we determine if
the arrangement is a lease or contains an embedded lease and review the facts
and circumstances of the arrangement to classify lease assets as operating or
finance leases under Topic 842. The Partnership has elected not to record any
leases with terms of 12 months or less on the balance sheet.
Balances related to operating leases are included in operating lease ROU assets,
accrued and other current liabilities, operating lease current liabilities and
non-current operating lease liabilities in our consolidated balance sheets.
Finance leases represent a small portion of the active lease agreements and are
included in finance lease ROU assets, current maturities of long-term debt and
long-term debt, less current maturities in our consolidated balance sheets. The
ROU assets represent the Partnership's right to use an underlying asset for the
lease term and lease liabilities represent the obligation of the Partnership to
make minimum lease payments arising from the lease for the duration of the lease
term.
Most leases include one or more options to renew, with renewal terms that can
extend the lease term from one to 20 years or greater. The exercise of lease
renewal options is typically at the sole discretion of the Partnership and lease
extensions are evaluated on a lease-by-lease basis. Leases containing early
termination clauses typically require the agreement of both parties to the
lease. At the inception of a lease, all renewal options reasonably certain to be
exercised are considered when determining the lease term. The depreciable life
of lease assets and leasehold improvements are limited by the expected lease
term.
To determine the present value of future minimum lease payments, we use the
implicit rate when readily determinable. Presently, because many of our leases
do not provide an implicit rate, the Partnership applies its incremental
borrowing rate based on the information available at the lease commencement date
to determine the present value of minimum lease payments. The operating and
finance lease ROU assets include any lease payments made and exclude lease
incentives.
Minimum rent payments are expensed on a straight-line basis over the term of the
lease. In addition, some leases require additional contingent or variable lease
payments, which are based on the factors specific to the individual agreement.
Variable lease payments the Partnership is typically responsible for include
payment of real estate taxes, maintenance expenses and insurance.
For short-term leases (leases that have term of twelve months or less upon
commencement), lease payments are recognized on a straight-line basis and no ROU
assets are recorded.
Accounting for Derivative Instruments and Hedging Activities. We utilize various
exchange-traded and OTC commodity financial instrument contracts to limit our
exposure to margin fluctuations in natural gas, NGL, crude oil and refined
products. These contracts consist primarily of futures and swaps.
If we designate a derivative financial instrument as a cash flow hedge and it
qualifies for hedge accounting, the change in the fair value is deferred in AOCI
until the underlying hedged transaction occurs. Any ineffective portion of a
cash flow hedge's change in fair value is recognized each period in earnings.
Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI
until the underlying physical transaction occurs, unless it is probable that the
forecasted transaction will not occur by the end of the originally specified
time period or within an additional two-month period of time thereafter. For
financial derivative instruments that do not qualify for hedge accounting, the
change in fair value is recorded in cost of products sold in the consolidated
statements of operations.
If we designate a hedging relationship as a fair value hedge, we record the
changes in fair value of the hedged asset or liability in cost of products sold
in our consolidated statement of operations. This amount is offset by the
changes in fair value of the related hedging instrument. Any ineffective portion
or amount excluded from the assessment of hedge ineffectiveness is also included
in the cost of products sold in the consolidated statement of operations.
We utilize published settlement prices for exchange-traded contracts, quotes
provided by brokers, and estimates of market prices based on daily contract
activity to estimate the fair value of these contracts. Changes in the methods
used to determine the fair value of these contracts could have a material effect
on our results of operations. We do not anticipate future changes in the methods
used to determine the fair value of these derivative contracts. See "Item 7A.
Quantitative and Qualitative Disclosures about Market Risk" for further
discussion regarding our derivative activities.
Fair Value of Financial Instruments. We have commodity derivatives, interest
rate derivatives and embedded derivatives in our preferred units that are
accounted for as assets and liabilities at fair value in our consolidated
balance sheets. We determine the fair value of our assets and liabilities
subject to fair value measurement by using the highest possible "level" of
inputs. Level 1 inputs are observable quotes in an active market for identical
assets and liabilities. We consider the valuation of marketable securities and
commodity derivatives transacted through a clearing broker with a published
price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are
inputs observable for similar assets and liabilities. We consider OTC commodity
derivatives entered into directly with third parties as a Level 2 valuation
since the values of these derivatives are quoted on an exchange for similar
transactions. Additionally, we consider our options transacted through our
clearing broker as having Level 2 inputs due to the level of activity of these
contracts on the exchange in which they trade. We consider the valuation of our

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interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is
based on quotes from an active exchange of Eurodollar futures for the same
period as the future interest swap settlements. Level 3 inputs are unobservable.
Derivatives related to the embedded derivatives in our preferred units are
valued using a binomial lattice model. The market inputs utilized in the model
include credit spread, probabilities of the occurrence of certain events, common
unit price, dividend yield, and expected value, and are considered level 3. See
further information on our fair value assets and liabilities in Note 2 of our
consolidated financial statements.
Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in
Unconsolidated Affiliates. Long-lived assets are required to be tested for
recoverability whenever events or changes in circumstances indicate that the
carrying amount of the asset may not be recoverable. Goodwill and intangibles
with indefinite lives must be tested for impairment annually or more frequently
if events or changes in circumstances indicate that the related asset might be
impaired. An impairment of an investment in an unconsolidated affiliate is
recognized when circumstances indicate that a decline in the investment value is
other than temporary. An impairment loss should be recognized only if the
carrying amount of the asset/goodwill is not recoverable and exceeds its fair
value.
In order to test for recoverability when performing a quantitative impairment
test, we must make estimates of projected cash flows related to the asset, which
include, but are not limited to, assumptions about the use or disposition of the
asset, estimated remaining life of the asset, and future expenditures necessary
to maintain the asset's existing service potential. In order to determine fair
value, we make certain estimates and assumptions, including, among other things,
changes in general economic conditions in regions in which our markets are
located, the availability and prices of natural gas, our ability to negotiate
favorable sales agreements, the risks that natural gas exploration and
production activities will not occur or be successful, our dependence on certain
significant customers and producers of natural gas, and competition from other
companies, including major energy producers. While we believe we have made
reasonable assumptions to calculate the fair value, if future results are not
consistent with our estimates, we could be exposed to future impairment losses
that could be material to our results of operations.
The Partnership determined the fair value of its reporting units using a
weighted combination of the discounted cash flow method and the guideline
company method. Determining the fair value of a reporting unit requires judgment
and the use of significant estimates and assumptions. Such estimates and
assumptions include revenue growth rates, operating margins, weighted average
costs of capital and future market conditions, among others. The Partnership
believes the estimates and assumptions used in our impairment assessments are
reasonable and based on available market information, but variations in any of
the assumptions could result in materially different calculations of fair value
and determinations of whether or not an impairment is indicated. Under the
discounted cash flow method, the Partnership determined fair value based on
estimated future cash flows of each reporting unit including estimates for
capital expenditures, discounted to present value using the risk-adjusted
industry rate, which reflect the overall level of inherent risk of the reporting
unit. Cash flow projections are derived from one year budgeted amounts and five
year operating forecasts plus an estimate of later period cash flows, all of
which are evaluated by management. Subsequent period cash flows are developed
for each reporting unit using growth rates that management believes are
reasonably likely to occur. Under the guideline company method, the Partnership
determined the estimated fair value of each of our reporting units by applying
valuation multiples of comparable publicly-traded companies to each reporting
unit's projected EBITDA and then averaging that estimate with similar historical
calculations using a three year average. In addition, the Partnership estimated
a reasonable control premium representing the incremental value that accrues to
the majority owner from the opportunity to dictate the strategic and operational
actions of the business.
One key assumption for the measurement of an impairment is management's estimate
of future cash flows and EBITDA. These estimates are based on the annual budget
for the upcoming year and forecasted amounts for multiple subsequent years. The
annual budget process is typically completed near the annual goodwill impairment
testing date, and management uses the most recent information for the annual
impairment tests. The forecast is also subjected to a comprehensive update
annually in conjunction with the annual budget process and is revised
periodically to reflect new information and/or revised expectations. The
estimates of future cash flows and EBITDA are subjective in nature and are
subject to impacts from the business risks described in "Item 1A. Risk Factors."
Therefore, the actual results could differ significantly from the amounts used
for goodwill impairment testing, and significant changes in fair value estimates
could occur in a given period. Such changes in fair value estimates could result
in additional impairments in future periods; therefore, the actual results could
differ significantly from the amounts used for goodwill impairment testing, and
significant changes in fair value estimates could occur in a given period,
resulting in additional impairments.
Management does not believe that any of the goodwill balances in its reporting
units is currently at significant risk of impairment; however, of the $5.2
billion of goodwill on the Partnership's consolidated balance sheet as of
December 31, 2019, approximately $380 million is recorded in reporting units for
which the estimated fair value exceeded the carrying value by less than 20% in
the most recent quantitative test.

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During the year ended December 31, 2019, the Partnership recorded the following
impairments:
•   A $12 million impairment was recorded related to the goodwill associated with

the Partnership's Southwest Gas operations within the interstate segment

primarily due to decreases in projected future revenues and cash flows.

Additionally, the Partnership recorded a $9 million impairment related to the

goodwill associated with the Partnership's North Central operations within

the midstream segment primarily due to changes in assumptions related to

projected future revenues and cash flows.

• Sunoco LP recognized a $47 million write-down on assets held for sale related

to its ethanol plant in Fulton, New York.

• USAC also recognized a $6 million fixed asset impairment related to certain

idle compressor assets.




During the year ended December 31, 2018, the Partnership recorded the following
impairments:
•   a $378 million impairment was recorded related to the goodwill associated

with the Partnership's Northeast operations within the midstream segment

primarily due to changes in assumptions related to projected future revenues

and cash flows from the dates the goodwill was originally recorded. These

changes in assumptions reflect delays in the construction of third-party

takeaway capacity in the Northeast. Additionally, the Partnership recorded

asset impairments of $4 million related to our midstream operations and asset

impairments $9 million related to our crude operations idle leased assets.

• Sunoco LP also recognized a $30 million impairment charge on its contractual

rights primarily due to decreases in projected future revenues and cash flows

from the date the intangible assets were originally recorded.

• USAC also recognized a $9 million fixed asset impairment related to certain

idle compressor assets.




During the year ended December 31, 2017, the Partnership recorded the following
impairments:
•   a $223 million impairment was recorded related to the goodwill associated

with CDM. In January 2018, the Partnership announced the contribution of CDM

to USAC. Based on the Partnership's anticipated proceeds in the contribution

transaction, the implied fair value of the CDM reporting unit was less than

the Partnership's carrying value. As the Partnership believes that the

contribution consideration also represented an appropriate estimate of fair

value as of the 2017 annual impairment test date, the Partnership recorded an

impairment for the difference between the carrying value and the fair value

of the reporting unit.

• a $262 million impairment was recorded related to the goodwill associated

with the Partnership's interstate transportation and storage reporting units,

and a $229 million impairment was recorded related to the goodwill associated

with the general partner of Panhandle in the all other segment. These

impairments were due to a reduction in management's forecasted future cash

flows from the related reporting units, which reduction reflected the impacts

discussed in "Results of Operations" above, along with the impacts of

re-contracting assumptions related to future periods.

• a $79 million impairment was recorded related to the goodwill associated the

Partnership's refined products transportation and services reporting unit.

Subsequent to the Sunoco Logistics Merger, the Partnership restructured the

internal reporting of legacy Sunoco Logistics' business to be consistent with

the internal reporting of legacy ETO. Subsequent to this reallocation the

carrying value of certain refined products reporting units was less than the

estimated fair value due to a reduction in management's forecasted future

cash flows from the related reporting units, and the goodwill associated with

those reporting units was fully impaired. No goodwill remained in the

respective reporting units subsequent to the impairment.

• a $127 million impairment of property, plant and equipment related to Sea

Robin primarily due to a reduction in expected future cash flows due to an

increase during 2017 in insurance costs related to offshore assets.

• a $141 million impairment of the Partnership's equity method investment in

FEP. The Partnership concluded that the carrying value of its investment in

FEP was other than temporarily impaired based on an anticipated decrease in


    production in the Fayetteville basin and a customer re-contracting with a
    competitor during 2017.

• a $172 million impairment of the Partnership's equity method investment in

HPC primarily due to a decrease in projected future revenues and cash flows

driven be the bankruptcy of one of HPC's major customers in 2017 and an

expectation that contracts expiring in the next few years will be renewed at

lower tariff rates and lower volumes.

• For 2017, Sunoco LP also recognized impairments of $404 million, of which

$119 million was allocated to continuing operations, as discussed further

below.




Except for the 2017 impairment of the goodwill associated with CDM, as discussed
above, the goodwill impairments recorded by the Partnership during the years
ended December 31, 2019, 2018 and 2017 represented all of the goodwill within
the respective reporting units.
During 2017, Sunoco LP announced the sale of a majority of the assets in its
retail and Stripes reporting units. These reporting units include the retail
operations in the continental United States but excludes the retail convenience
store operations in Hawaii

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that comprise the Aloha reporting unit. Upon the classification of assets and
related liabilities as held for sale, Sunoco LP's management applied the
measurement guidance in ASC 360, Property, Plant and Equipment, to calculate the
fair value less cost to sell of the disposal group. In accordance with ASC
360-10-35-39, Sunoco LP's management first tested the goodwill included within
the disposal group for impairment prior to measuring the disposal group's fair
value less the cost to sell. In the determination of the classification of
assets held for sale and the related liabilities, Sunoco LP's management
allocated a portion of the goodwill balance previously included in the Sunoco LP
retail and Stripes reporting units to assets held for sale based on the relative
fair values of the business to be disposed of and the portion of the respective
reporting unit that will be retained in accordance with ASC 350-20-40-3.
Sunoco LP recognized goodwill impairments of $387 million in 2017, of which
$102 million was allocated to continuing operations, primarily due to changes in
assumptions related to projected future revenues and cash flows from the dates
the goodwill was originally recorded.
Additionally, Sunoco LP performed impairment tests on its indefinite-lived
intangible assets during the fourth quarter of 2017 and recognized a total of
$17 million in impairment charges on their contractual rights and liquor
licenses primarily due to decreases in projected future revenues and cash flows
from the date the intangible assets were originally recorded.
Property, Plant and Equipment. Expenditures for maintenance and repairs that do
not add capacity or extend the useful life are expensed as incurred.
Expenditures to refurbish assets that either extend the useful lives of the
asset or prevent environmental contamination are capitalized and depreciated
over the remaining useful life of the asset. Additionally, we capitalize certain
costs directly related to the construction of assets including internal labor
costs, interest and engineering costs. Upon disposition or retirement of
pipeline components or natural gas plant components, any gain or loss is
recorded to accumulated depreciation. When entire pipeline systems, gas plants
or other property and equipment are retired or sold, any gain or loss is
included in the consolidated statement of operations. Depreciation of property,
plant and equipment is provided using the straight-line method based on their
estimated useful lives ranging from 1 to 99 years. Changes in the estimated
useful lives of the assets could have a material effect on our results of
operation. We do not anticipate future changes in the estimated useful lives of
our property, plant and equipment.
Asset Retirement Obligations. We have determined that we are obligated by
contractual or regulatory requirements to remove facilities or perform other
remediation upon retirement of certain assets. The fair value of any ARO is
determined based on estimates and assumptions related to retirement costs, which
the Partnership bases on historical retirement costs, future inflation rates and
credit-adjusted risk-free interest rates. These fair value assessments are
considered to be Level 3 measurements, as they are based on both observable and
unobservable inputs. Changes in the liability are recorded for the passage of
time (accretion) or for revisions to cash flows originally estimated to settle
the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset
exists and such obligation can be reasonably estimated. We will record an ARO in
the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts discussed below, management was not able to
reasonably measure the fair value of AROs as of December 31, 2019 and 2018, in
most cases because the settlement dates were indeterminable. Although a number
of other onshore assets in Panhandle's system are subject to agreements or
regulations that give rise to an ARO upon Panhandle's discontinued use of these
assets, AROs were not recorded because these assets have an indeterminate
removal or abandonment date given the expected continued use of the assets with
proper maintenance or replacement. ETC Sunoco has legal AROs for several other
assets at its previously owned refineries, pipelines and terminals, for which it
is not possible to estimate when the obligations will be settled. Consequently,
the retirement obligations for these assets cannot be measured at this time. At
the end of the useful life of these underlying assets, ETC Sunoco is legally or
contractually required to abandon in place or remove the asset. We believe we
may have additional AROs related to ETC Sunoco's pipeline assets and storage
tanks, for which it is not possible to estimate whether or when the AROs will be
settled. Consequently, these AROs cannot be measured at this time. Sunoco LP has
AROs related to the estimated future cost to remove underground storage tanks.
Individual component assets have been and will continue to be replaced, but the
pipeline and the natural gas gathering and processing systems will continue in
operation as long as supply and demand for natural gas exists. Based on the
widespread use of natural gas in industrial and power generation activities,
management expects supply and demand to exist for the foreseeable future.  We
have in place a rigorous repair and maintenance program that keeps the pipelines
and the natural gas gathering and processing systems in good working order.
Therefore, although some of the individual assets may be replaced, the pipelines
and the natural gas gathering and processing systems themselves will remain
intact indefinitely.
Other non-current assets on the Partnership's consolidated balance sheet
included $31 million and $26 million of legally restricted funds for the purpose
of settling AROs as of December 31, 2019 and 2018, respectively.

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Legal Matters. We are subject to litigation and regulatory proceedings as a
result of our business operations and transactions. We utilize both internal and
external counsel in evaluating our potential exposure to adverse outcomes from
claims, orders, judgments or settlements. To the extent that actual outcomes
differ from our estimates, or additional facts and circumstances cause us to
revise our estimates, our earnings will be affected. We expense legal costs as
incurred, and all recorded legal liabilities are revised as required as better
information becomes available to us. The factors we consider when recording an
accrual for contingencies include, among others: (i) the opinions and views of
our legal counsel; (ii) our previous experience; and (iii) the decision of our
management as to how we intend to respond to the complaints.
For more information on our litigation and contingencies, see Note 11 to our
consolidated financial statements included in "Item 8. Financial Statements and
Supplementary Data" in this report.
Environmental Remediation Activities. The Partnership's accrual for
environmental remediation activities reflects anticipated work at identified
sites where an assessment has indicated that cleanup costs are probable and
reasonably estimable. The accrual for known claims is undiscounted and is based
on currently available information, estimated timing of remedial actions and
related inflation assumptions, existing technology and presently enacted laws
and regulations. It is often extremely difficult to develop reasonable estimates
of future site remediation costs due to changing regulations, changing
technologies and their associated costs, and changes in the economic
environment. Engineering studies, historical experience and other factors are
used to identify and evaluate remediation alternatives and their related costs
in determining the estimated accruals for environmental remediation activities.
Losses attributable to unasserted claims are generally reflected in the accruals
on an undiscounted basis, to the extent they are probable of occurrence and
reasonably estimable. ETO has established a wholly-owned captive insurance
company to bear certain risks associated with environmental obligations related
to certain sites that are no longer operating. The premiums paid to the captive
insurance company include estimates for environmental claims that have been
incurred but not reported, based on an actuarially determined fully developed
claims expense estimate. In such cases, ETO accrues losses attributable to
unasserted claims based on the discounted estimates that are used to develop the
premiums paid to the captive insurance company.
In general, each remediation site/issue is evaluated individually based upon
information available for the site/issue and no pooling or statistical analysis
is used to evaluate an aggregate risk for a group of similar items (e.g.,
service station sites) in determining the amount of probable loss accrual to be
recorded. ETO's estimates of environmental remediation costs also frequently
involve evaluation of a range of estimates. In many cases, it is difficult to
determine that one point in the range of loss estimates is more likely than any
other. In these situations, existing accounting guidance requires that the
minimum of the range be accrued. Accordingly, the low end of the range often
represents the amount of loss which has been recorded. The Partnership's
consolidated balance sheet reflected $320 million in environmental accruals as
of December 31, 2019.
Total future costs for environmental remediation activities will depend upon,
among other things, the identification of any additional sites, the
determination of the extent of the contamination at each site, the timing and
nature of required remedial actions, the nature of operations at each site, the
technology available and needed to meet the various existing legal requirements,
the nature and terms of cost-sharing arrangements with other potentially
responsible parties, the availability of insurance coverage, the nature and
extent of future environmental laws and regulations, inflation rates, terms of
consent agreements or remediation permits with regulatory agencies and the
determination of the Partnership's liability at the sites, if any, in light of
the number, participation level and financial viability of the other parties.
The recognition of additional losses, if and when they were to occur, would
likely extend over many years. Management believes that the Partnership's
exposure to adverse developments with respect to any individual site is not
expected to be material. However, if changes in environmental laws or
regulations occur or the assumptions used to estimate losses at multiple sites
are adjusted, such changes could impact multiple facilities, formerly owned
facilities and third-party sites at the same time. As a result, from time to
time, significant charges against income for environmental remediation may
occur; however, management does not believe that any such charges would have a
material adverse impact on the Partnership's consolidated financial position.
Deferred Income Taxes. ET recognizes benefits in earnings and related deferred
tax assets for net operating loss carryforwards ("NOLs") and tax credit
carryforwards. If necessary, a charge to earnings and a related valuation
allowance are recorded to reduce deferred tax assets to an amount that is more
likely than not to be realized by the Partnership in the future. Deferred income
tax assets attributable to state and federal NOLs and federal tax alternative
minimum tax credit carryforwards totaling $936 million have been included in
ET's consolidated balance sheet as of December 31, 2019. The state NOL
carryforward benefits of $149 million ($118 million net of federal benefit)
begin to expire in 2020 with a substantial portion expiring between 2033 and
2039. ET's corporate subsidiaries have federal NOLs of $3.42 billion ($718
million in benefits) of which $1.3 billion will expire between 2031 and 2037.
Any federal NOL generated in 2018 and future years can be carried forward
indefinitely. Federal alternative minimum tax credit carryforwards of
$15 million remained at December 31, 2019. We have determined that a valuation
allowance totaling $62 million ($49 million net of federal income tax effects)
is required for state NOLs as of December 31, 2019 primarily due to significant
restrictions on their use in the Commonwealth of Pennsylvania. A separate
valuation allowance of $46 million

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is attributable to foreign tax credits. In making the assessment of the future
realization of the deferred tax assets, we rely on future reversals of existing
taxable temporary differences, tax planning strategies and forecasted taxable
income based on historical and projected future operating results. The potential
need for valuation allowances is regularly reviewed by management. If it is more
likely than not that the recorded asset will not be realized, additional
valuation allowances which increase income tax expense may be recognized in the
period such determination is made. Likewise, if it is more likely than not that
additional deferred tax assets will be realized, an adjustment to the deferred
tax asset will increase income in the period such determination is made.
Forward-Looking Statements
This annual report contains various forward-looking statements and information
that are based on our beliefs and those of our General Partner, as well as
assumptions made by and information currently available to us. These
forward-looking statements are identified as any statement that does not relate
strictly to historical or current facts. When used in this annual report, words
such as "anticipate," "project," "expect," "plan," "goal," "forecast,"
"estimate," "intend," "could," "believe," "may," "will" and similar expressions
and statements regarding our plans and objectives for future operations, are
intended to identify forward-looking statements. Although we and our General
Partner believe that the expectations on which such forward-looking statements
are based are reasonable, neither we nor our General Partner can give assurances
that such expectations will prove to be correct. Forward-looking statements are
subject to a variety of risks, uncertainties and assumptions. If one or more of
these risks or uncertainties materialize, or if underlying assumptions prove
incorrect, our actual results may vary materially from those anticipated,
estimated, projected or expected. Among the key risk factors that may have a
direct bearing on our results of operations and financial condition are:
•   the ability of our subsidiaries to make cash distributions to us, which is

dependent on their results of operations, cash flows and financial condition;

• the actual amount of cash distributions by our subsidiaries to us;

• the volumes transported on our subsidiaries' pipelines and gathering systems;

• the level of throughput in our subsidiaries' processing and treating

facilities;

• the fees our subsidiaries charge and the margins they realize for their

gathering, treating, processing, storage and transportation services;

• the prices and market demand for, and the relationship between, natural gas


    and NGLs;


• energy prices generally;

• the prices of natural gas and NGLs compared to the price of alternative and

competing fuels;

• the general level of petroleum product demand and the availability and price

of NGL supplies;

• the level of domestic oil, natural gas and NGL production;

• the availability of imported oil, natural gas and NGLs;

• actions taken by foreign oil and gas producing nations;

• the political and economic stability of petroleum producing nations;

• the effect of weather conditions on demand for oil, natural gas and NGLs;

• availability of local, intrastate and interstate transportation systems;

• the continued ability to find and contract for new sources of natural gas

supply;

• availability and marketing of competitive fuels;

• the impact of energy conservation efforts;

• energy efficiencies and technological trends;

• governmental regulation and taxation;

• changes to, and the application of, regulation of tariff rates and

operational requirements related to our subsidiaries' interstate and

intrastate pipelines;

• hazards or operating risks incidental to the gathering, treating, processing

and transporting of natural gas and NGLs;




• competition from other midstream companies and interstate pipeline companies;


• loss of key personnel;



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• loss of key natural gas producers or the providers of fractionation services;

• reductions in the capacity or allocations of third-party pipelines that

connect with our subsidiaries pipelines and facilities;

• the effectiveness of risk-management policies and procedures and the ability

of our subsidiaries liquids marketing counterparties to satisfy their

financial commitments;

• the nonpayment or nonperformance by our subsidiaries' customers;

• regulatory, environmental, political and legal uncertainties that may affect

the timing and cost of our subsidiaries' internal growth projects, such as

our subsidiaries' construction of additional pipeline systems;

• risks associated with the construction of new pipelines and treating and

processing facilities or additions to our subsidiaries' existing pipelines

and facilities, including difficulties in obtaining permits and rights-of-way

or other regulatory approvals and the performance by third-party contractors;

• the availability and cost of capital and our subsidiaries' ability to access

certain capital sources;

• a deterioration of the credit and capital markets;

• risks associated with the assets and operations of entities in which our

subsidiaries own less than a controlling interests, including risks related

to management actions at such entities that our subsidiaries may not be able

to control or exert influence;

• the ability to successfully identify and consummate strategic acquisitions at

purchase prices that are accretive to our financial results and to

successfully integrate acquired businesses;

• changes in laws and regulations to which we are subject, including tax,

environmental, transportation and employment regulations or new

interpretations by regulatory agencies concerning such laws and regulations;

and

• the costs and effects of legal and administrative proceedings.




You should not put undue reliance on any forward-looking statements. When
considering forward-looking statements, please review the risks described under
"Item 1A. Risk Factors" in this annual report. Any forward-looking statement
made by us in this Annual Report on Form 10-K is based only on information
currently available to us and speaks only as of the date on which it is made. We
undertake no obligation to publicly update any forward-looking statement,
whether written or oral, that may be made from time to time, whether as a result
of new information, future developments or otherwise.
Inflation
Interest rates on existing and future credit facilities and future debt
offerings could be significantly higher than current levels, causing our
financing costs to increase accordingly. Although increased financing costs
could limit our ability to raise funds in the capital markets, we expect to
remain competitive with respect to acquisitions and capital projects since our
competitors would face similar circumstances.
Inflation in the United States has been relatively low in recent years and has
not had a material effect on our results of operations. It may in the future,
however, increase the cost to acquire or replace property, plant and equipment
and may increase the costs of labor and supplies. Our operating revenues and
costs are influenced to a greater extent by commodity price changes. To the
extent permitted by competition, regulation and our existing agreements, we have
and will continue to pass along a portion of increased costs to our customers in
the form of higher fees.

Latest news about Energy Transfer LP

Energy Transfer Raises Quarterly Distribution to $0.3175 a Unit, Payable May 20 to Holders of Record May 13	Apr. 24	MT
AI boom to fuel natural gas demand in coming years, report says	Apr. 23	RE
As shale oil gains slow, deepwater port struggles for customers	Apr. 22	RE
Mizuho Securities Adjusts Price Target on Energy Transfer to $19 From $18, Maintains Buy Rating	Apr. 18	MT
Sunoco Completes European Terminal Acquisition, Station Sale to 7-Eleven -- OPIS	Apr. 17	DJ
Energy Transfer Stay on New Pipeline by DT Midstream Overturned by Appeals Court	Apr. 10	MT
Social Buzz: Wallstreetbets Stocks Mixed Premarket Tuesday; MicroStrategy to Decline, Taiwan Semiconductor Manufacturing to Open Higher	Apr. 09	MT
CERAWEEK-Williams delays Louisiana natgas pipeline amid competitor dispute	Mar. 20	RE
Analysis-Peak rates boost U.S. demand for riskier form of corporate debt	Mar. 15	RE
EQT to buy Equitrans Midstream in bid to boost natural gas margins	Mar. 11	RE
Japan boosts reliance on allies Australia, US for long-term LNG supplies	Mar. 10	RE
Energy Transfer LP Appoints Clifford A. Harris as Director	Feb. 28	CI
Sector Update: Energy Stocks Decline in Friday Afternoon Trading	Feb. 23	MT
Sunoco, Energy Transfer Sign Marketing Partnership With Sauber Motorsport	Feb. 23	MT
Sunoco and Energy Transfer Sign First Joint Multi-Year Partnership with Stake F1 Team Kick Sauber	Feb. 23	CI
Citigroup Adjusts Price Target on Energy Transfer to $18 From $17, Maintains Buy Rating	Feb. 21	MT
Sector Update: Energy Stocks Decline Late Afternoon	Feb. 20	MT
Japan's Kyushu Electric Holds Investment in Energy Transfer's Lake Charles Project	Feb. 20	MT
Exclusive-Occidental explores $18 billion-plus sale of Western Midstream, sources say	Feb. 20	RE
Exclusive-Japan's Kyushu Electric to wait for US LNG policy clarity on Lake Charles	Feb. 20	RE
UBS Adjusts Energy Transfer Price Target to $22 From $23, Maintains Buy Rating	Feb. 15	MT
Energy Transfer earnings rise in Q4 on natural gas liquids demand growth	Feb. 14	RE
Energy Transfer Q4 Earnings, Revenue Increase	Feb. 14	MT
Transcript : Energy Transfer LP, Q4 2023 Earnings Call, Feb 14, 2024	Feb. 14
Energy Transfer LP Reports Earnings Results for the Fourth Quarter and Full Year Ended December 31, 2023	Feb. 14	CI

Chart Energy Transfer LP

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Company Profile

Energy Transfer LP owns and operates a diversified portfolios of energy assets in the United States. The Company is engaged in natural gas operations such as natural gas midstream and intrastate transportation and storage, and interstate natural gas transportation and storage. It is also engaged in crude oil, natural gas liquids (NGL) and refined products transportation, terminalling and acquisition and marketing activities as well as NGL storage and fractionation services. The Companyâs segments include intrastate transportation and storage; interstate transportation and storage; midstream; NGL and refined products transportation and services; crude oil transportation and services; investment in Sunoco LP; investment in USA Compression Partners, LP (USAC), and all other. It has approximately 125,000 miles of pipeline and associated energy infrastructure. The Company owns and operates approximately 12,200 miles of intrastate natural gas transportation pipelines.

Sector

Oil & Gas Transportation Services

Calendar

2024-05-08 - Q1 2024 Earnings Release

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Income Statement Evolution

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Ratings for Energy Transfer LP

Trading Rating

Investor Rating

ESG Refinitiv

D+

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Analysts' Consensus

Sell

Buy

Mean consensus

BUY

Number of Analysts

Last Close Price

15.94 USD

Average target price

18.48 USD

Spread / Average Target

+15.91%

Consensus

EPS Revisions

Estimates Revisions

Quarterly earnings - Rate of surprise

Company calendar

Sector Natural Gas Pipeline

	1st Jan change	Capi.
ENERGY TRANSFER LP	+15.51%	53.45B
SNAM S.P.A.	-8.21%	15.55B
DT MIDSTREAM, INC.	+17.86%	6.23B
EQUITRANS MIDSTREAM CORPORATION	+34.77%	5.83B
OQ GAS NETWORKS SAOC	-5.23%	1.64B
NEXTDECADE CORPORATION	+31.24%	1.61B
SHAANXI PROVINCIAL NATURAL GAS CO.,LTD	-2.05%	1.09B
S.N.T.G.N. TRANSGAZ S.A.	+0.64%	766M
TRANSPORTADORA DE GAS DEL NORTE S.A.	-.--%	328M
NATURELGAZ SANAYI VE TICARET	-11.95%	138M

Natural Gas Pipeline