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OFFON

ENERGY TRANSFER LP

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

05/07/2021 | 11:50am EDT
(Tabular dollar and unit amounts, except per unit data, are in millions)
The following is a discussion of our historical consolidated financial condition
and results of operations, and should be read in conjunction with (i) our
historical consolidated financial statements and accompanying notes thereto
included elsewhere in this Quarterly Report on Form 10-Q; and (ii) the
consolidated financial statements and management's discussion and analysis of
financial condition and results of operations included in the Partnership's
Annual Report on Form 10-K for the year ended December 31, 2020 filed with the
SEC on February 19, 2021. 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 "Part I - Item 1A. Risk Factors" of our Annual
Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on
February 19, 2021. Additional information on forward-looking statements is
discussed below in "Forward-Looking Statements."
Unless the context requires otherwise, references to "we," "us," "our," the
"Partnership" and "ET" mean Energy Transfer LP and its consolidated
subsidiaries.
RECENT DEVELOPMENTS
Winter Storm Impacts
Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts
to the Partnership's consolidated net income and Adjusted EBITDA and also
affected the results of operations in certain segments, as discussed in "Results
of Operations" below. The recognition of the impacts of Winter Storm Uri during
the three months ended March 31, 2021 required management to make certain
estimates and assumptions, including estimates of expected credit losses and
assumptions related to the resolution of disputes with counterparties with
respect to certain purchases and sales of natural gas. The ultimate realization
of credit losses and the resolution of disputed purchases and sales of natural
gas could materially impact the Partnership's financial condition and results of
operations in future periods.
Enable Acquisition
On February 16, 2021, the Partnership entered into a definitive merger agreement
to acquire Enable. Under the terms of the merger agreement, Enable's common
unitholders will receive 0.8595 of an ET common unit in exchange for each Enable
common unit. In addition, each outstanding Enable preferred unit will be
exchanged for 0.0265 of a Series G Preferred Unit, and ET will make a
$10 million cash payment for Enable's general partner. Pursuant to support
agreements entered into in connection with the merger agreement, the two largest
Enable unitholders have delivered their written consents to approve the merger.
These unitholders collectively own 79% of Enable's outstanding common units, and
those consents are therefore sufficient to approve the merger. The transaction
is subject to the satisfaction of customary closing conditions, including
Hart-Scott-Rodino Act ("HSR") clearance.
We anticipate that the Federal Trade Commission ("FTC") will issue requests for
additional information and documentary material, commonly known as "second
requests," which would extend the HSR waiting period until the 30th calendar day
after the date that both parties substantially comply with the second requests.
We continue to believe that the FTC will grant unconditional clearance of the
transaction, and we remain fully committed to closing the Enable merger under
the terms of the merger agreement. We expect to close the transaction in the
second half of 2021.
Rollup Mergers
On April 1, 2021, ET, ETO and certain of ETO's subsidiaries consummated several
internal reorganization transactions (the "Rollup Mergers"). In connection with
the Rollup Mergers, Sunoco Logistics Operations and its general partner merged
with and into ETO, with ETO surviving, and immediately thereafter, ETO merged
with and into ET, with ET surviving. The impacts of the Rollup Mergers also
included the following:
•All of ETO's long-term debt was assumed by ET, as more fully described in Note
7 to the consolidated financial statements in "Item 1. Financial Statements."
•Each issued and outstanding ETO preferred unit was converted into the right to
receive one newly created ET preferred unit. A description of the ET Preferred
Units is included in Note 9 to the consolidated financial statements in "Item 1.
Financial Statements."
•Each of ETO's issued and outstanding Class K, Class L, Class M and Class N
units, all of which were held by ETP Holdco Corporation, a wholly-owned
subsidiary of ETO, were converted into an aggregate 675,625,000 newly created
Class B Units representing limited partner interests in ET.
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Quarterly Cash Distribution
In April 2021, ET announced its quarterly distribution of $0.1525 per unit
($0.61 annualized) on ET common units for the quarter ended March 31, 2021.
Regulatory Update
Interstate Natural Gas Transportation Regulation
Rate Regulation
Effective January 2018, the 2017 Tax Cuts 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
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. On July 31, 2020, the United States Court of
Appeals for the District of Columbia Circuit issued an opinion upholding the
FERC's decision denying a separate master limited partnership recovery of an
income tax allowance and its decision not to require the master limited
partnership to refund accumulated deferred income tax balances. In light of the
rehearing order's clarification regarding an individual entity's ability to
argue in support of recovery of an income tax allowance and the court's
subsequent opinion upholding denial of an income tax allowance to a master
limited partnership, the impact of the FERC's policy on the treatment of income
taxes on the rates we can charge for FERC-regulated transportation services is
unknown at this time.
Even without application of the FERC's recent rate making-related policy
statements and rulemakings, 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, including ROE and tax-related
components, although changes in these components may tend to decrease our
cost-of-service rate, other components in the cost-of-service rate calculation
may increase and result in a newly calculated cost-of-service rate that is less
than, 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,
Midcontinent Express and Fayetteville Express, 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. 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 Revised Policy Statement, changes to
ROE methodology, or other FERC policies, 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 our cost-of-service components and the outcomes of any
challenges to our rates by the FERC or our shippers.
On July 18, 2018, the FERC issued a final rule establishing procedures to
evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the
Tax Act and the FERC's Revised Policy Statement. By order issued January 16,
2019, the FERC initiated a review of Panhandle's existing rates pursuant to
Section 5 of the NGA 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 and an NGA Section 4 rate case
on August 30, 2019. The Section 4 and Section 5 proceedings were consolidated by
order of the Chief Judge on October 1, 2019. A hearing in the combined
proceedings commenced on August 25, 2020 and adjourned on September 15, 2020.
The initial decision by the administrative law judge was issued on March 26,
2021. On April 26, 2021, Panhandle filed its brief on exceptions to the initial
decision.
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
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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.
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 for Finished Goods, or
PPI-FG. Many existing pipelines utilize the FERC liquids index to change
transportation rates annually. 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. In a December 2020 order,
FERC determined that during the five-year period commencing July 1, 2021 and
ending June 30, 2026, common carriers charging indexed rates will be permitted
to adjust their indexed ceilings annually by PPI-FG plus 0.78 percent. Requests
for rehearing of the December 2020 order were filed on January 19, 2021, and
remain pending before FERC. Accordingly, the FERC's final determination of the
index rate coupled with the anticipated and subsequent appeals of the December
2020 order could adversely impact the final determination of the FERC approved
index.
FERC has also implemented changes related to its treatment of federal income
taxes. The change in treatment impacts two rate components. Those components are
the allowance for income taxes and the amount for accumulated deferred income
taxes. These changes will primarily impact any cost-of-service related filing
and our revenues associated with any cost-based service could be adversely
affected by future FERC or judicial rulings. However, we believe that these
impacts, if any, will be minimal.
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. Inventory adjustments that are excluded from the calculation of
Adjusted EBITDA represent only the changes in lower of cost or market reserves
on inventory that is carried at LIFO. These amounts are unrealized valuation
adjustments applied to Sunoco LP's fuel volumes remaining in inventory at the
end of the period.
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
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.
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Consolidated Results
                                                                           Three Months
                                                                              Ended
                                                                            March 31,
                                                                                  2021             2020             Change
Segment Adjusted EBITDA:
Intrastate transportation and storage                                          $ 2,813          $    240          $ 2,573
Interstate transportation and storage                                              453               404               49
Midstream                                                                          288               383              (95)
NGL and refined products transportation and services                               647               663              (16)
Crude oil transportation and services                                              510               591              (81)
Investment in Sunoco LP                                                            157               209              (52)
Investment in USAC                                                                 100               106               (6)
All other                                                                           72                39               33
Adjusted EBITDA (consolidated)                                                   5,040             2,635            2,405
Depreciation, depletion and amortization                                          (954)             (867)             (87)
Interest expense, net of interest capitalized                                     (589)             (602)              13
Impairment losses                                                                   (3)           (1,325)           1,322
Gains (losses) on interest rate derivatives                                        194              (329)             523
Non-cash compensation expense                                                      (28)              (22)              (6)
Unrealized gains on commodity risk management activities                            46                51               (5)
Inventory valuation adjustments (Sunoco LP)                                        100              (227)             327
Losses on extinguishments of debt                                                   (7)              (62)              55
Adjusted EBITDA related to unconsolidated affiliates                              (123)             (154)              31
Equity in earnings (losses) of unconsolidated affiliates                            55                (7)              62

Other, net                                                                         (15)              (27)              12
Income (loss) before income tax expense                                          3,716              (936)           4,652
Income tax expense                                                                 (75)              (28)             (47)

Net income (loss)                                                              $ 3,641          $   (964)         $ 4,605


Adjusted EBITDA (consolidated). For the three months ended March 31, 2021
compared to the same period last year, Adjusted EBITDA increased 91%, primarily
due to the impacts of Winter Storm Uri in February 2021. The most significant
impacts from the storm were recognized in our intrastate transportation and
storage segment, where realized storage margin increased by $1.52 billion
compared to the prior period as a result of withdrawals during the storm,
realized natural gas sales increased $983 million primarily due to sales during
the storm, and retained fuel revenues increased $84 million primarily due to
unprecedented natural gas prices during the storm. Additional information on
changes impacting Adjusted EBITDA, including other impacts from Winter Storm Uri
and other non-storm-related factors, is available below in "Segment Operating
Results."
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization increased for the three months ended March 31, 2021 compared to the
same period last year primarily due to the incremental depreciation related to
assets recently placed in service.
Interest expense, net. Interest expense, net of interest capitalized decreased
for the three months ended March 31, 2021 compared to the same periods last year
primarily due to the following:
•a decrease of $10 million for the Partnership primarily due to lower average
debt balance and borrowing costs on recently refinanced and floating rate debt,
partially offset by lower interest capitalized; and
•a decrease of $3 million for Sunoco LP primarily attributable to a slight
decrease in average total long-term debt and decrease in the weighted average
interest rate on long-term debt for the respective periods.
Impairment Losses. During the three months ended March 31, 2021, USAC recognized
an impairment of $3 million related to its compression equipment as a result of
its evaluations of the future deployment of its idle fleet under current market
conditions. During the three months ended March 31, 2020, the Partnership
performed an interim impairment test on certain reporting units within its
midstream, interstate, crude, NGL and all other operations. As a result of the
interim impairment test, the Partnership recognized goodwill impairments
totaling of $706 million due to decreases in projected future cash flows as a
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result of overall market demand decline. In addition, USAC recognized a goodwill
impairment of $619 million based on changes in market condition.
Gains (Losses) on Interest Rate Derivatives. Gains and losses on interest rate
derivatives during the three months ended March 31, 2021 resulted from changes
in forward interest rates, which caused our forward-starting swaps to change in
value.
Unrealized Gains (Losses) on Commodity Risk Management Activities. See
additional information on the unrealized gains (losses) on commodity risk
management activities included in "Segment Operating Results" below.
Losses on Extinguishments of Debt. During the three months ended March 31, 2021,
amounts were related to Sunoco LP's January 2021 repurchase of the remainder of
its 2023 senior notes. During the three months ended March 31, 2020, amounts
were related to ETO's senior notes redemption in January 2020.
Inventory Valuation Adjustments. Inventory valuation adjustments represent
changes in lower of cost or market using the last-in, first-out method on Sunoco
LP's inventory. These amounts are unrealized valuation adjustments applied to
fuel volumes remaining in inventory at the end of the period. For the three
months ended March 31, 2021, an increase in fuel prices reduced lower of cost or
market reserve requirements for the period by $100 million. For the three months
ended March 31, 2020, a decline in fuel prices increased lower of cost or market
reserve requirements for the period by $227 million.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of
Unconsolidated Affiliates. See additional information in "Supplemental
Information on Unconsolidated Affiliates" and "Segment Operating Results" below.
Other, net. Other, net primarily includes the amortization of regulatory assets
and other income and expense amounts.
Income Tax Expense. For the three months ended March 31, 2021 compared to the
same period in the prior year, income tax expense increased due to higher
earnings from the Partnership's consolidated corporate subsidiaries in the
current period.
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Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated
affiliates:
                                                                          Three Months
                                                                              Ended
                                                                            March 31,
                                                                                  2021            2020(1)           Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus                                                                         $    37          $     35          $      2
FEP                                                                                  -               (70)               70
MEP                                                                                 (3)                -                (3)
White Cliffs                                                                         -                 8                (8)
Other                                                                               21                20                 1

Total equity in earnings (losses) of unconsolidated affiliates

$ 55 $ (7) $ 62


Adjusted EBITDA related to unconsolidated affiliates(2):
Citrus                                                                         $    79          $     79          $      -
FEP                                                                                  -                19               (19)
MEP                                                                                  5                 8                (3)
White Cliffs                                                                         5                14                (9)
Other                                                                               34                34                 -
Total Adjusted EBITDA related to unconsolidated affiliates                  

$ 123 $ 154 $ (31)


Distributions received from unconsolidated affiliates:
Citrus                                                                         $    56          $     49          $      7
FEP                                                                                  4                18               (14)
MEP                                                                                  4                11                (7)
White Cliffs                                                                        15                13                 2
Other                                                                               21                19                 2
Total distributions received from unconsolidated affiliates                 

$ 100 $ 110 $ (10)



(1)For the three months ended March 31, 2020, equity in earnings (losses) of
unconsolidated affiliates includes the impact of non-cash impairments recorded
by FEP, which reduced the Partnership's equity in earnings by $85 million.
(2)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.
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•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 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.
Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts
to the Partnership's Adjusted EBITDA and also affected the results of operations
in certain segments, as discussed in segment analysis below. The recognition of
the impacts of Winter Storm Uri during the three months ended March 31, 2021
required management to make certain estimates and assumptions, including
estimates of expected credit losses and assumptions related to the resolution of
disputes with counterparties with respect to certain purchases and sales of
natural gas. The ultimate realization of credit losses and the resolution of
disputed purchases and sales of natural gas could materially impact the
Partnership's financial condition and results of operations in future periods.
Intrastate Transportation and Storage
                                                                          Three Months
                                                                             Ended
                                                                           March 31,
                                                                                 2021             2020             Change
Natural gas transported (BBtu/d)                                               11,851            13,135           (1,284)
Withdrawals from storage natural gas inventory (BBtu)                          19,045             6,975           12,070
Revenues                                                                      $ 4,900          $    593          $ 4,307
Cost of products sold                                                           1,994               303            1,691
Segment margin                                                                  2,906               290            2,616
Unrealized gains on commodity risk management activities                          (12)               (6)              (6)
Operating expenses, excluding non-cash compensation expense                       (80)              (41)             (39)

Selling, general and administrative expenses, excluding non-cash compensation expense

                                                      (8)               (9)               1
Adjusted EBITDA related to unconsolidated affiliates                                6                 6                -
Other                                                                               1                 -                1
Segment Adjusted EBITDA                                                       $ 2,813          $    240          $ 2,573


Volumes. For the three months ended March 31, 2021 compared to the same period
last year, transported volumes decreased primarily due to the bankruptcy filing
of a transportation customer, a contract step-down, and impacts of Winter Storm
Uri.
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Table of Contents Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:

                                                                           Three Months
                                                                              Ended
                                                                            March 31,
                                                                                  2021             2020            Change
Transportation fees                                                        

$ 180 $ 161 $ 19 Natural gas sales and other (excluding unrealized gains and losses)

                                                                          1,071               88              983

Retained fuel revenues (excluding unrealized gains and losses)

                                                                             93                9               84

Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)

                                                1,550               26            1,524

Unrealized gains on commodity risk management activities and fair value inventory adjustments

        12                6                6
Total segment margin                                                           $ 2,906          $   290          $ 2,616


Segment Adjusted EBITDA. For the three months ended March 31, 2021 compared to
the same period last year, Segment Adjusted EBITDA related to our intrastate
transportation segment increased due to the net effects of the following:
•an increase of $1.52 billion in realized storage margin due to higher physical
storage margin from withdrawals during Winter Storm Uri;
•an increase of $983 million in realized natural gas sales and other primarily
due to natural gas sales at prevailing market prices during Winter Storm Uri;
•an increase of $84 million in retained fuel revenues primarily due to natural
gas prices during Winter Storm Uri; and
•an increase of $19 million in transportation fees due to demand volume ramp-ups
from the Permian and fees related to Winter Storm Uri, partially offset by the
expiration of certain contracts on our Regency Intrastate Gas System; partially
offset by
•an increase of $39 million in operating expenses primarily due to a $29 million
increase in the cost of fuel consumption during Winter Storm Uri and a $9
million increase in electricity costs.
Interstate Transportation and Storage
                                                                        Three Months Ended
                                                                            March 31,
                                                                                  2021              2020             Change
Natural gas transported (BBtu/d)                                                  9,654            10,630              (976)
Natural gas sold (BBtu/d)                                                            21                15                 6
Revenues                                                                    

$ 525 $ 464 $ 61

Operating expenses, excluding non-cash compensation, amortization and accretion expenses

                                                (134)             (143)                9

Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses

                          (21)              (21)                -
Adjusted EBITDA related to unconsolidated affiliates                                 85               106               (21)

Other                                                                                (2)               (2)                -
Segment Adjusted EBITDA                                                        $    453          $    404          $     49


Volumes. For the three months ended March 31, 2021 compared to the same period
last year, transported volumes decreased primarily due to foundation shipper
contract expirations and a shipper bankruptcy on our ETC Tiger system,
maintenance of third-party facilities, and lower crude production resulting in
lower associated gas production.
Segment Adjusted EBITDA. For the three months ended March 31, 2021 compared to
the same period last year, Segment Adjusted EBITDA related to our interstate
transportation and storage segment increased due to the net impacts of the
following:
•an increase of $61 million in revenues primarily due to an $88 million increase
in operational gas sales and a $6 million increase in reservation revenues from
higher contracted volumes and increased short-term firm contracts. These
increases were partially offset by a $31 million decrease due to contract
expirations and a shipper bankruptcy during 2020 on our ETC Tiger system; and
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•a decrease of $9 million in operating expenses primarily due to a $5 million
decrease in employee costs, a $2 million decrease in maintenance expenses and a
$2 million decrease in ad valorem tax expense; partially offset by
•a decrease of $21 million in Adjusted EBITDA related to unconsolidated
affiliates primarily due to a $19 million decrease from our Fayetteville Express
Pipeline joint venture as a result of the expiration of foundation shipper
contracts and a $3 million decrease from our Midcontinent Express Pipeline joint
venture as a result of less capacity sold and lower rates received following the
expiration of foundation shipper contracts, partially offset by a $1 million
increase from our Citrus joint venture resulting from higher revenues.
Midstream
                                                                          Three Months
                                                                             Ended
                                                                           March 31,
                                                                                 2021             2020            Change
Gathered volumes (BBtu/d)                                                      12,024           13,346           (1,322)
NGLs produced (MBbls/d)                                                           534              610              (76)
Equity NGLs (MBbls/d)                                                              30               36               (6)
Revenues                                                                      $ 2,672          $ 1,170          $ 1,502
Cost of products sold                                                           2,202              575            1,627
Segment margin                                                                    470              595             (125)

Operating expenses, excluding non-cash compensation expense                      (164)            (193)              29

Selling, general and administrative expenses, excluding non-cash compensation expense

                                                     (25)             (26)               1
Adjusted EBITDA related to unconsolidated affiliates                                7                7                -

Segment Adjusted EBITDA                                                       $   288          $   383          $   (95)


Volumes. Gathered volumes and NGL production decreased during the three months
ended March 31, 2021 compared to the same period last year primarily due to
basin declines and Winter Storm Uri in the South Texas, Mid-Continent/Panhandle,
Permian and North Texas regions partially offset by volume growth in the
Ark-La-Tex region.
Segment Margin. The components of our midstream segment gross margin were as
follows:
                                                                Three Months Ended
                                                                    March 31,
                                                                                2021       2020       Change
Gathering and processing fee-based revenues                                    $ 498      $ 530      $  (32)
Non-fee-based contracts and processing                                           (28)        65         (93)

Total segment margin                                                           $ 470      $ 595      $ (125)


Segment Adjusted EBITDA. For the three months ended March 31, 2021 compared to
the same period last year, Segment Adjusted EBITDA related to our midstream
segment decreased due to the net impacts of the following:
•a decrease of $145 million in non-fee-based margin due to the impacts of Winter
Storm Uri; and
•a decrease of $32 million in fee-based margin due to lower volumes primarily in
the South Texas Region as a result of basin declines and Winter Storm Uri;
partially offset by
•an increase of $52 million in non-fee-based margin due to favorable natural gas
prices of $26 million and NGL prices of $26 million;
•a decrease of $29 million in operating expenses due to cost-saving initiatives,
including a decrease of $19 million in outside services, $7 million in materials
and $3 million in ad valorem taxes; and
•a decrease of $1 million in selling, general and administrative expenses due to
a decrease in overhead costs resulting from corporate cost reductions.
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NGL and Refined Products Transportation and Services
                                                                           Three Months
                                                                              Ended
                                                                            March 31,
                                                                                  2021             2020            Change
NGL transportation volumes (MBbls/d)                                             1,502            1,398              104
Refined products transportation volumes (MBbls/d)                                  462              542              (80)
NGL and refined products terminal volumes (MBbls/d)                              1,042              847              195
NGL fractionation volumes (MBbls/d)                                                726              804              (78)
Revenues                                                                       $ 3,990          $ 2,715          $ 1,275
Cost of products sold                                                            3,141            1,836            1,305
Segment margin                                                                     849              879              (30)
Unrealized gains on commodity risk management activities                           (23)             (55)              32
Operating expenses, excluding non-cash compensation expense                       (172)            (159)             (13)

Selling, general and administrative expenses, excluding non-cash compensation expense

                                                      (28)             (25)              (3)
Adjusted EBITDA related to unconsolidated affiliates                                21               23               (2)

Segment Adjusted EBITDA                                                        $   647          $   663          $   (16)


Volumes. For the three months ended March 31, 2021 compared to the same period
last year, NGL transportation volumes increased primarily due to the initiation
of service on our propane and ethane export pipelines into our Nederland
Terminal.
Refined products transportation volumes decreased for the three months ended
March 31, 2021 compared to the same periods last year due to less domestic
demand for jet fuel and other refined products, as well as COVID-19 related
demand reductions.
NGL and refined products terminal volumes increased for the three months ended
March 31, 2021 compared to the same periods last year primarily due to higher
volumes from our Mariner East system. In addition, loaded vessels at our
Nederland Terminal increased due to the additional supply from the initiation of
service on our propane and ethane export pipelines in the fourth quarter of
2020. These increases were partially offset by lower domestic demand for jet
fuel and other refined products at our refined product terminals due primarily
to COVID-19 related demand reductions.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility
decreased for the three months ended March 31, 2021 compared to the same period
last year primarily due to lower NGL volumes feeding our Mont Belvieu
fractionation facility as a result of production interruptions, primarily in the
Permian region, due to Winter Storm Uri during the first quarter of 2021.
Segment Margin. The components of our NGL and refined products transportation
and services segment margin were as follows:
                                                                          Three Months
                                                                              Ended
                                                                            March 31,
                                                                                  2021             2020            Change
Transportation margin                                                          $   492          $   476          $     16
Fractionators and refinery services margin                                         145              179               (34)
Terminal services margin                                                           141              151               (10)
Storage margin                                                                      67               63                 4
Marketing margin                                                                   (19)             (45)               26
Unrealized gains on commodity risk management activities                            23               55               (32)
Total segment margin                                                           $   849          $   879          $    (30)


Segment Adjusted EBITDA. For the three months ended March 31, 2021 compared to
the same period last year, Segment Adjusted EBITDA related to our NGL and
refined products transportation and services segment decreased due to the net
impacts of the following:
•a decrease of $34 million in fractionators and refinery services margin
primarily due to a $28 million decrease resulting from downtime on our various
fractionators due to the previously mentioned weather-driven and COVID-19
related volume reductions in the first quarter of 2021 and a $17 million
decrease relating to a cavern withdrawal in the first quarter
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of 2021, the impact of which was partially offset in our transportation margin.
These decreases were partially offset by an $8 million increase due to a more
favorable pricing environment impacting our refinery services business;
•an increase of $13 million in operating expenses primarily due to a $14 million
increase in power costs; and
•a decrease of $10 million in terminal services margin primarily due to a $32
million decrease resulting from an expiration of a third-party contract at our
Nederland Terminal in the second quarter of 2020. This decrease was partially
offset by increases of $13 million in loading fees due to higher LPG export
volumes at our Nederland Terminal, $7 million due to the startup of our ethane
export facilities at our Nederland Terminal in the first quarter of 2021, and $1
million due to higher throughput at our Marcus Hook Terminal; partially offset
by
•an increase of $26 million in marketing margin primarily due to a $45 million
increase resulting from higher optimization gains and from the sale of NGL
component products at our Mont Belvieu facility, a $14 million increase from our
optimization and blending operations from our northeast NGL and refined products
marketing operations, and a $7 million increase due to inventory write-downs
taken on various products during 2020 as a result of market price declines.
These increases were partially offset by intrasegment charges of $24 million in
the first quarter of 2021 which were fully offset within our transportation
margin, as well as a $15 million decrease in butane blending margin due to less
favorable prices; and
•an increase of $16 million in transportation margin primarily due to
intrasegment revenues of $24 million in the first quarter of 2021, which are
fully offset by a charge reflected in our marketing margin, a $20 million
increase due to higher export volumes feeding into our Nederland Terminal
resulting from the initiation of service on our propane and ethane export
pipelines in the fourth quarter of 2020, a $19 million increase from higher
throughput on our Mariner East pipeline system and an $11 million gain relating
to a cavern withdrawal in the first quarter of 2021 that is partially offset on
our fractionators margin. These increases were partially offset by a $58 million
decrease resulting from lower throughput across the various regions in Texas due
to Winter Storm Uri related production outages.
Crude Oil Transportation and Services
                                                                           Three Months
                                                                              Ended
                                                                            March 31,
                                                                                  2021             2020            Change
Crude transportation volumes (MBbls/d)                                           3,491            4,424             (933)
Crude terminals volumes (MBbls/d)                                                2,327            2,996             (669)
Revenues                                                                       $ 3,500          $ 4,213          $  (713)
Cost of products sold                                                            2,838            3,458             (620)
Segment margin                                                                     662              755              (93)

Unrealized (gains) losses on commodity risk management activities

                                                                          (5)              10              (15)
Operating expenses, excluding non-cash compensation expense                       (122)            (158)              36

Selling, general and administrative expenses, excluding non-cash compensation expense

                                                      (30)             (28)              (2)
Adjusted EBITDA related to unconsolidated affiliates                                 5               12               (7)

Segment Adjusted EBITDA                                                        $   510          $   591          $   (81)


Volumes. For the three months ended March 31, 2021 compared to the same period
last year, crude transportation volumes were lower on our Texas pipeline system
and Bakken pipeline, driven by COVID-19 related demand reductions impacting both
regions, as well as lower crude oil production along our Texas systems due to
Winter Storm Uri during the first quarter of 2021. These volume reductions also
resulted in lower terminal volumes compared to the prior period.
Segment Adjusted EBITDA. For the three months ended March 31, 2021 compared to
the same period last year, Segment Adjusted EBITDA related to our crude oil
transportation and services segment decreased due to the net impacts of the
following:
•a decrease of $108 million in segment margin (excluding unrealized gains and
losses on commodity risk management activities) primarily due to a $111 million
decrease from our Texas crude pipeline system due to lower volumes transported
and lower average tariff rates realized, a $55 million decrease due to lower
volumes on our Bakken Pipeline resulting from lower Bakken crude oil production,
a $26 million decrease in crude terminal margin primarily driven by lower
Permian and Bakken pipeline volumes, reduced Gulf Coast refinery utilization
from adverse weather, and decreased export demand, a $5 million decrease due to
lower volumes on our Bayou Bridge pipeline, and a $3 million decrease in
Mid-Continent gathering volumes due to lower production. These decreases were
partially offset by a $92 million increase (excluding a
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net change of $15 million in unrealized gains and losses on commodity risk
management activities) from our crude oil acquisition and marketing business
primarily due to losses realized in the first quarter of 2020 on the write down
of crude inventory due to significant market price declines;
•an increase of $2 million in selling, general and administrative expenses
primarily due to higher insurance premiums and allocated overhead costs; and
•a decrease of $7 million in Adjusted EBITDA related to unconsolidated
affiliates due to lower volumes on White Cliffs Pipeline due to lower crude oil
production in the DJ basin, partly offset by higher margin from jet fuel sales
by our joint ventures, partially offset by
•a decrease of $36 million in operating expenses primarily due to lower
volume-driven expenses and corporate cost reduction initiatives.
Investment in Sunoco LP
                                                                          Three Months
                                                                             Ended
                                                                           March 31,
                                                                                 2021             2020            Change
Revenues                                                                      $ 3,471          $ 3,272          $    199
Cost of products sold                                                           3,120            3,164               (44)
Segment margin                                                                    351              108               243

Unrealized (gains) losses on commodity risk management activities

                                                                         (5)               6               (11)
Operating expenses, excluding non-cash compensation expense                       (76)            (109)               33

Selling, general and administrative expenses, excluding non-cash compensation expense

                                                     (20)             (30)               10
Adjusted EBITDA related to unconsolidated affiliates                                2                2                 -
Inventory valuation adjustments                                                  (100)             227              (327)
Other                                                                               5                5                 -
Segment Adjusted EBITDA                                                       $   157          $   209          $    (52)


The Investment in Sunoco LP segment reflects the consolidated results of Sunoco
LP.
Segment Adjusted EBITDA. For the three months ended March 31, 2021 compared to
the same period last year, Segment Adjusted EBITDA related to our investment in
Sunoco LP segment decreased due to the net impacts of the following:
•a decrease in the gross profit on motor fuel sales of $78 million primarily due
to a 20.7% decrease in gross profit per gallon sold and a 7.5% decrease in
gallons sold; and
•a decrease in non-motor fuel sales and lease gross profit of $17 million
primarily due to reduced credit card transactions; partially offset by
•a decrease in operating expenses and selling, general and administrative
expenses of $43 million primarily due to lower expected credit losses, employee
costs, professional fees, credit card processing fees, insurance and
maintenance.
Investment in USAC
                                                                         Three Months
                                                                             Ended
                                                                           March 31,
                                                                                 2021             2020            Change
Revenues                                                                      $   158          $   179          $    (21)
Cost of products sold                                                              21               24                (3)
Segment margin                                                                    137              155               (18)

Operating expenses, excluding non-cash compensation expense

                                                                           (28)             (35)                7

Selling, general and administrative expenses, excluding non-cash compensation expense

       (9)             (14)                5

Segment Adjusted EBITDA                                                       $   100          $   106          $     (6)

The Investment in USAC segment reflects the consolidated results of USAC.

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Segment Adjusted EBITDA. For the three months ended March 31, 2021 compared to
the same period last year, Segment Adjusted EBITDA related to our investment in
USAC segment decreased due to the net impacts of the following:
•a decrease of $18 million in segment margin primarily due to a decrease in
demand for compression services driven by decreased U.S. crude oil and natural
gas activity compared to the prior period, partially offset by
•a decrease of $7 million in operating expenses is primarily driven by the
decrease in average revenue generating horsepower and reduced headcount in the
current period; and
•a decrease of $5 million in selling, general and administrative expenses
primarily due to changes in the allowance for expected credit losses and lower
employee-related expenses.
All Other
                                                                          Three Months
                                                                             Ended
                                                                           March 31,
                                                                                 2021             2020            Change
Revenues                                                                      $ 1,512              513          $    999
Cost of products sold                                                           1,342              415               927
Segment margin                                                                    170               98                72
Unrealized gains on commodity risk management activities                           (1)              (5)                4
Operating expenses, excluding non-cash compensation expense                       (51)             (38)              (13)

Selling, general and administrative expenses, excluding non-cash compensation expense

                                                     (39)             (35)               (4)
Adjusted EBITDA related to unconsolidated affiliates                               (1)               -                (1)
Other and eliminations                                                             (6)              19               (25)
Segment Adjusted EBITDA                                                       $    72          $    39          $     33


Amounts reflected in our all other segment primarily include:
•our natural gas marketing operations;
•our wholly-owned natural gas compression operations;
•our investment in coal handling facilities; and
•our Canadian operations, which include natural gas gathering and processing
assets.
Segment Adjusted EBITDA. For the three months ended March 31, 2021 compared to
the same period last year, Segment Adjusted EBITDA related to our all other
segment increased due to the net impacts of the following:
•an increase of $52 million from power trading activities primarily due to
short-term, favorable market conditions created by Winter Storm Uri in February
2021;
•an increase of $17 million primarily due to revenues earned under the Electric
Reliability Council of Texas ("ERCOT") responsive reserve program during the
Winter Storm Uri, and
•an increase of $5 million primarily due to increased gains from sales of
storage natural gas; partially offset by
•a decrease of $22 million primarily due to insurance proceeds received in the
prior period on settled claims related to our MTBE litigation; and
•a decrease of $10 million due to higher utility expense related to freezing
temperatures.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Our ability to satisfy obligations and pay distributions to unitholders will
depend on our future performance, which will be subject to prevailing economic,
financial, business and weather conditions, and other factors, many of which are
beyond management's control.
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We currently expect capital expenditures in 2021 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                   $    15      $    20      $   30      $  35
Interstate transportation and storage (1)                    50           75         120        125
Midstream                                                   425          450         110        115
NGL and refined products transportation and services        650          750         110        120
Crude oil transportation and services (1)                   325          350          90        100
All other (including eliminations)                           75          100          55         60
Total capital expenditures                              $ 1,540      $ 1,745      $  515      $ 555


(1)Includes capital expenditures related to our 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 have
included these factors in our anticipated growth capital expenditures for each
year.
We generally fund maintenance capital expenditures and distributions with cash
flows from operating activities. We generally expect to fund growth capital
expenditures with proceeds of borrowings under our credit facilities, along with
cash from operations.
Sunoco LP currently expects to invest approximately $150 million in growth
capital expenditures and approximately $45 million on maintenance capital
expenditures for the full year 2021.
USAC currently plans to spend approximately $22 million in maintenance capital
expenditures and currently has budgeted between $30 million and $40 million in
expansion capital expenditures for the full year 2021.
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 for our 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 acquisition 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 we have 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 price risk management assets and liabilities, the timing
of accounts receivable collection, the timing of payments on accounts payable,
the timing of purchase and sales of inventories and the timing of advances and
deposits received from customers.
Three months ended March 31, 2021 compared to three months ended March 31, 2020.
Cash provided by operating activities during 2021 was $5.16 billion compared to
$1.83 billion for 2020, and net income was $3.64 billion for 2021 and net loss
was $964 million for 2020. The difference between net income and net cash
provided by operating activities for the three months ended March 31, 2021
primarily consisted of net changes in operating assets and liabilities (net of
effects of acquisitions) of $533 million and other non-cash items totaling
$942 million.
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The non-cash activity in 2021 and 2020 consisted primarily of depreciation,
depletion and amortization of $954 million and $867 million, respectively,
non-cash compensation expense of $28 million and $22 million, respectively,
inventory valuation adjustments of $100 million and $227 million, respectively,
and deferred income taxes of $66 million and $42 million, respectively. Non-cash
activity also included losses on extinguishments of debt in 2021 and 2020 of $7
million and $62 million, respectively, and impairment losses of $3 million and
$1.33 billion in 2021 and 2020, respectively.
Net income (loss) includes equity in earnings of unconsolidated affiliates of
$55 million in 2021 and equity in losses of unconsolidated affiliates of $7
million in 2020, and cash provided by operating activities includes cash
distributions received from unconsolidated affiliates that are deemed to be paid
from cumulative earnings, which distributions were $45 million in 2021 and
$58 million in 2020.
Cash paid for interest, net of interest capitalized, was $562 million and $535
million for the three months ended March 31, 2021 and 2020, respectively.
Interest capitalized was $27 million and $38 million for the three months ended
March 31, 2021 and 2020, respectively.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for
acquisitions, capital expenditures, cash contributions to our joint ventures,
and cash proceeds from sales or contributions of assets or businesses. In
addition, distributions from equity investees are included in cash flows from
investing activities if the distributions are deemed to be a return of the
Partnership's investment. Changes in capital expenditures between periods
primarily result from increases or decreases in our growth capital expenditures
to fund our construction and expansion projects.
Three months ended March 31, 2021 compared to three months ended March 31, 2020.
Cash used in investing activities during 2021 was $635 million compared to $1.56
billion for 2020. Total capital expenditures (excluding the allowance for equity
funds used during construction and net of contributions in aid of construction
costs) for 2021 were $695 million compared to $1.60 billion for 2020. Additional
detail related to our capital expenditures is provided in the table below.
The following is a summary of capital expenditures (including only our
proportionate share of the Bakken, Rover and Bayou Bridge pipeline projects and
net of contributions in aid of construction costs) on an accrual basis for the
three months ended March 31, 2021:
                                                                 Capital 

Expenditures Recorded During Period

                                                               Growth                Maintenance            Total
Intrastate transportation and storage                   $               9          $          4          $      13
Interstate transportation and storage                                   9                     9                 18
Midstream                                                              69                    14                 83
NGL and refined products transportation and services                  187                    23                210
Crude oil transportation and services                                  71                     8                 79
Investment in Sunoco LP                                                13                     5                 18
Investment in USAC                                                      4                     5                  9
All other (including eliminations)                                     16                     8                 24
Total capital expenditures                              $             378          $         76          $     454


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 increase between the periods based on increases in the number of
common units outstanding or increases in the distribution rate.
Three months ended March 31, 2021 compared to three months ended March 31, 2020.
Cash used in financing activities during 2021 was $4.53 billion compared to
$366 million for 2020. During 2021, we had a net decrease in our debt level of
$3.73 billion compared to a net decrease of $764 million for 2020. In 2020, we
paid debt issuance costs of $51 million. During 2020, our subsidiaries received
$1.58 billion in net proceeds from offerings of preferred units.
In 2021 and 2020, we paid distributions of $406 million and $770 million,
respectively, to our partners. In 2021 and 2020, we paid distributions of
$406 million and $444 million, respectively, to noncontrolling interests. In
2021 and 2020, we paid distributions of $12 million to our redeemable
noncontrolling interests. In addition, we received capital contributions of $20
million in cash from noncontrolling interests in 2021 compared to $95 million in
cash from noncontrolling interests in 2020.
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Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
                                                                      March 31,           December 31,
                                                                        2021                  2020
ET Indebtedness:

Senior Notes (1)                                                    $   36,455          $      37,855
Term Loan (2)                                                            2,000                  2,000
Five-Year Credit Facility (2)                                              800                  3,103
Subsidiary Indebtedness:
Transwestern Senior Notes                                                  400                    400
Panhandle Senior Notes                                                     235                    235
Bakken Senior Notes                                                      2,500                  2,500
Sunoco LP Senior Notes and lease-related obligations                     2,711                  3,139
USAC Senior Notes                                                        1,475                  1,475
HFOTCO Tax Exempt Notes                                                    225                    225
Revolving credit facilities:
Sunoco LP Credit Facility                                                  381                      -
USAC Credit Facility                                                       503                    474
Energy Transfer Canada Revolver due February 2024                           65                     57
Energy Transfer Canada Revolver Term Loan A due February 2024              261                    261
Other long-term debt                                                         3                      3
Net unamortized premiums, discounts, and fair value adjustments            (10)                   (10)
Deferred debt issuance costs                                              (269)                  (279)
Total debt                                                              47,735                 51,438
Less: current maturities of long-term debt                                  23                     21
Long-term debt, less current maturities                             $   

47,712 $ 51,417



(1)The balances presented above include senior notes that were formerly
obligations of ETO prior to the Rollup Mergers discussed below and in "Recent
Developments" above. As of March 31, 2021 and December 31, 2020, the outstanding
principal amount of ETO senior notes was $36.4 billion and $37.8 billion,
respectively. Beginning April 1, 2021, these senior notes are obligations of ET.
A description of the ETO senior notes that were assumed by ET is included in the
Partnership's Annual Report on Form 10-K for the year ended December 31, 2020.
(2)The Term Loan and Five-Year Credit Facility were previously obligations of
ETO. Subsequent to the completion of the Rollup Mergers on April 1, 2021, these
facilities are obligations of ET.
Recent Transactions
In connection with the Rollup Mergers on April 1, 2021, ET entered into various
supplemental indentures and assumed all the obligations of ETO under the
respective indentures and credit agreements.
During the first quarter of 2021, ETO redeemed its $600 million of 4.40% senior
notes due April 1, 2021 and its $800 million of 4.65% senior notes due June 1,
2021, using proceeds from the Five-Year Credit Facility.
Credit Facilities and Commercial Paper
Term Loan
As a result of the Rollup Mergers, on April 1, 2021, ET assumed all of ETO's
obligations in respect of its term loan credit agreement (the "Term Loan") and
Sunoco Logistics Operations was released as a guarantor in respect of the Term
Loan. The Partnership's Term Loan provides for a $2.00 billion three-year term
loan credit facility. Borrowings under the Term Loan mature on October 17, 2022
and are available for working capital purposes and for general partnership
purposes. As of March 31, 2021, the Term Loan had $2.00 billion outstanding and
was fully drawn. The weighted average interest rate on the total amount
outstanding as of March 31, 2021 was 1.11%.
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Five-Year Credit Facility
As a result of the Rollup Mergers, on April 1, 2021, ET assumed all of ETO's
obligations in respect of its revolving credit facility (the "Five-Year Credit
Facility") and Sunoco Logistics Operations was released as a guarantor in
respect of the Five-Year Credit Facility.The Partnership's Five-Year Credit
Facility allows for unsecured borrowings up to $5.00 billion and matures on
December 1, 2023. The 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 March 31, 2021, the Five-Year Credit Facility had $800 million of
outstanding borrowings, all of which consisted of commercial paper. The amount
available for future borrowings was $4.08 billion, after accounting for
outstanding letters of credit in the amount of $121 million. The weighted
average interest rate on the total amount outstanding as of March 31, 2021 was
0.45%.
364-Day Facility
As a result of the Rollup Mergers, on April 1, 2021, ET assumed all of ETO's
obligations in respect of its 364-day revolving credit facility (the "364-Day
Facility") and Sunoco Logistics Operations was released as a guarantor in
respect of the 364-Day Facility.The Partnership's 364-Day Facility allows for
unsecured borrowings up to $1.00 billion and matures on November 26, 2021. As of
March 31, 2021, the 364-Day Facility had no outstanding borrowings.
Sunoco LP Credit Facility
As of March 31, 2021, the Sunoco LP Credit Facility had $381 million of
outstanding borrowings and $8 million in standby letters of credit and matures
in July 2023. The amount available for future borrowings at March 31, 2021 was
$1.1 billion. The weighted average interest rate on the total amount outstanding
as of March 31, 2021 was 1.86%.
USAC Credit Facility
As of March 31, 2021, USAC had $503 million of outstanding borrowings and no
outstanding letters of credit under the credit agreement. As of March 31, 2021,
USAC had $1.10 billion of availability under its credit facility. The weighted
average interest rate on the total amount outstanding as of March 31, 2021 as
3.20%.
Energy Transfer Canada Credit Facilities
Energy Transfer Canada is party to a credit agreement providing for a C$350
million (US$278 million at the March 31, 2021 exchange rate) senior secured term
loan facility, a C$525 million (US$417 million at the March 31, 2021 exchange
rate) senior secured revolving credit facility, and a C$300 million (US$239
million at the March 31, 2021 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. Energy Transfer Canada may incur additional term loans and revolving
commitments in an aggregate amount not to exceed C$250 million (US$199
million at the March 31, 2021 exchange rate), subject to receiving commitments
for such additional term loans or revolving commitments from either new lenders
or increased commitments from existing lenders.
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 March 31, 2021.
CASH DISTRIBUTIONS
Cash Distributions Paid by ET
Under its partnership agreement, ET will distribute all of its Available Cash,
as defined in the partnership agreement, 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 our
general partner that is necessary or appropriate to provide for future cash
requirements.
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Cash Distributions on ET Common Units
Distributions declared and/or paid with respect to ET common units subsequent to
December 31, 2020 were as follows:
   Quarter Ended          Record Date            Payment Date           Rate
December 31, 2020      February 8, 2021      February 19, 2021       $ 0.1525
March 31, 2021         May 11, 2021          May 19, 2021              0.1525


Cash Distributions on ET Preferred Units
As discussed in "Recent Developments" above, in connection with the Rollup
Mergers, ETO's outstanding preferred units were converted into ET Preferred
Units.
Distributions declared on the ET Preferred Units were as follows:
     Period Ended                Record Date               Payment Date             Series A (1)           Series B (1)          Series C          Series D          Series E          Series F (1)          Series G (1)
December 31, 2020 (2)         February 1, 2021         February 16, 2021          $       31.25          $      33.125          $ 0.4609          $ 0.4766          $ 0.4750          $          -          $          -
March 31, 2021                May 3, 2021              May 17, 2021                           -                      -            0.4609            0.4766            0.4750                 33.75                 35.63


(1)Series A, Series B, Series F and Series G distributions are paid on a
semi-annual basis.
(2)Distributions for the period ended December 31, 2020 reflect distributions
paid on the ETO preferred units prior to the conversion to ET preferred units,
as discussed above.
A summary of the distribution and redemption rights associated with the ET
Preferred Units is included in Note 9 in "Item 1. Financial Statements."
Cash Distributions Paid by Subsidiaries
The Partnership's consolidated financial statements include Sunoco LP and USAC,
both of which are publicly traded master limited partnerships, as well as other
less-than-wholly-owned, consolidated joint ventures. The following sections
describe cash distributions made by our publicly traded subsidiaries, Sunoco LP
and USAC, both of which are required by their respective partnership agreements
to distribute all cash on hand (less appropriate reserves determined by the
boards of directors of their respective general partners) subsequent to the end
of each quarter.
Cash Distributions Paid by Sunoco LP
Distributions on Sunoco LP's units declared and/or paid by Sunoco LP subsequent
to December 31, 2020 were as follows:
   Quarter Ended          Record Date            Payment Date           Rate
December 31, 2020      February 8, 2021      February 19, 2021       $ 0.8255
March 31, 2021         May 11, 2021          May 19, 2021              0.8255

Cash Distributions Paid by USAC Distributions on USAC's units declared and/or paid by USAC subsequent to December 31, 2020 were as follows:

   Quarter Ended          Record Date           Payment Date          Rate
December 31, 2020      January 25, 2021      February 5, 2021      $ 0.5250
March 31, 2021         April 26, 2021        May 7, 2021             0.5250


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. We describe our significant
accounting policies in Note 2 to our consolidated financial statements in the
Partnership's Annual Report on Form 10-K filed with the SEC on February 19,
2021.
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RECENT ACCOUNTING PRONOUNCEMENTS
Currently, there are no accounting pronouncements that have been issued, but not
yet adopted, that are expected to have a material impact on the Partnership's
financial position or results of operations.
FORWARD-LOOKING STATEMENTS
This quarterly 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 quarterly 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 volumes transported on our pipelines and gathering systems;
•the level of throughput in our processing and treating facilities;
•the fees we 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;
•impacts of world health events, including the COVID-19 pandemic;
•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 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;
•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 pipelines and facilities;
•the effectiveness of risk-management policies and procedures and the ability of
our liquids marketing counterparties to satisfy their financial commitments;
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•the nonpayment or nonperformance by our customers;
•regulatory, environmental, political and legal uncertainties that may affect
the timing and cost of our internal growth projects, such as our construction of
additional pipeline systems;
•risks associated with the construction of new pipelines and treating and
processing facilities or additions to our 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 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 we own
less than a controlling interests, including risks related to management actions
at such entities that we 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;
•the costs and effects of legal and administrative proceedings; and
•the risks associated with a potential failure to successfully combine our
business with that of Enable.
You should not put undue reliance on any forward-looking statements. When
considering forward-looking statements, please review the risks described under
"Part I - Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year
ended December 31, 2020. Any forward-looking statement made by us in this
Quarterly Report on Form 10-Q 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.

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