(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 and "Part II - Item 1A. Risk Factors" of our Quarterly Report
on Form 10-Q for the quarter ended June 30, 2021 filed with the SEC on August 5,
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
Series H Preferred Units Issuance
On June 15, 2021, the Partnership issued 900,000 of its 6.500% Series H
Preferred Units at a price of $1,000 per unit. The net proceeds were used to
repay amounts outstanding under the Partnership's term loan and for general
partnership purposes.
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". The recognition of the impacts of Winter Storm Uri during the
nine months ended September 30, 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. In May 2021, the Enable
common unitholders voted to approve the merger. The transaction is subject to
the satisfaction of customary closing conditions, including Hart-Scott-Rodino
Act ("HSR") clearance.
The Federal Trade Commission ("FTC") has issued requests for additional
information and documentary material (the "Second Request"). The effect of the
Second Request is to extend the waiting period imposed by the HSR Act until 30
days after the Partnership and Enable have certified substantial compliance with
the Second Request, unless that period is extended voluntarily or terminated
sooner by the FTC. We continue to believe that the FTC will grant 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 fourth quarter 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 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."
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•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.
Sunoco LP's Acquisitions
In September and October 2021, Sunoco LP acquired a total of nine refined
product terminals in two separate transactions for approximately $256 million.
Quarterly Cash Distribution
In October 2021, ET announced its quarterly distribution of $0.1525 per unit
($0.61 annualized) on ET common units for the quarter ended September 30, 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
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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. On May 17, 2021, Panhandle filed its reply brief on exception
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 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 filed by us on May
26, 2021. 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                                      Nine Months Ended
                                           September 30,                                           September 30,
                                       2021              2020             Change               2021                2020             Change
Segment Adjusted EBITDA:
Intrastate transportation and
storage                            $     172          $    203          $   (31)         $    3,209             $    630          $ 2,579
Interstate transportation and
storage                                  334               425              (91)              1,118                1,232             (114)
Midstream                                556               530               26               1,321                1,280               41
NGL and refined products
transportation and services              706               762              (56)              2,089                2,099              (10)
Crude oil transportation and
services                                 496               631             (135)              1,490                1,741             (251)
Investment in Sunoco LP                  198               189                9                 556                  580              (24)
Investment in USAC                        99               104               (5)                299                  315              (16)
All other                                 18                22               (4)                153                   62               91
Adjusted EBITDA (consolidated)         2,579             2,866             (287)             10,235                7,939            2,296
Depreciation, depletion and
amortization                            (943)             (912)             (31)             (2,837)              (2,715)            (122)
Interest expense, net of interest
capitalized                             (558)             (569)              11              (1,713)              (1,750)              37
Impairment losses                          -            (1,474)           1,474                 (11)              (2,803)           2,792
Gains (losses) on interest rate
derivatives                                1                55              (54)                 72                 (277)             349
Non-cash compensation expense            (26)              (30)               4                 (81)                 (93)              12
Unrealized gains (losses) on
commodity risk management
activities                               (19)              (30)              11                  74                  (27)             101
Inventory valuation adjustments
(Sunoco LP)                                9                11               (2)                168                 (126)             294
Losses on extinguishments of debt          -                 -                -                  (8)                 (62)              54
Adjusted EBITDA related to
unconsolidated affiliates               (141)             (169)              28                (400)                (480)              80
Equity in earnings (losses) of
unconsolidated affiliates                 71               (32)             103                 191                   46              145
Impairment of investment in an
unconsolidated affiliate                   -              (129)             129                   -                 (129)             129
Other, net                                11                53              (42)                  -                  (48)              48
Income (loss) before income tax
expense                                  984              (360)           1,344               5,690                 (525)           6,215
Income tax expense                       (77)              (41)             (36)               (234)                (168)             (66)

Net income (loss)                  $     907          $   (401)         $ 1,308          $    5,456             $   (693)         $ 6,149


Adjusted EBITDA (consolidated). For the three months ended September 30, 2021
compared to the same period last year, Adjusted EBITDA decreased 10% due to the
net impacts of multiple factors across each of our reportable segments. The
primary drivers of the Adjusted EBITDA decrease were in our interstate
transportation and storage, NGL and refined products transportation and
services, and crude oil transportation and services segments. In our interstate
transportation and storage segment, the decrease in Adjusted EBITDA was
primarily driven by shipper contract expirations and a shipper bankruptcy. In
our NGL and refined products transportation and services segment, the decrease
in Adjusted EBITDA was primarily driven by increased utilities and employee
related costs, while several variances within our segment margin were largely
offsetting. In our crude oil transportation and services segment, the decrease
in Adjusted EBITDA reflected a decrease in margin from our crude oil acquisition
and marketing business, as well as increases in operating expense and selling,
general and administrative expenses.
For the nine months ended September 30, 2021 compared to the same period last
year, Adjusted EBITDA increased 29%, 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. In addition, realized natural gas sales
increased $936 million and retained fuel revenues increased $114 million in our
intrastate transportation and storage segment, and these increases were also
primarily due to the impacts of the storm.
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Additional information on changes impacting Adjusted EBITDA for the three and
nine months ended September 30, 2021 compared to the same periods last year,
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 and nine months ended September 30, 2021
compared to the same period last year primarily due to incremental depreciation
related to assets recently placed in service.
Interest Expense, net. Interest expense, net of interest capitalized decreased
for the three and nine months ended September 30, 2021 compared to the same
periods last year primarily due to the following:
•the Partnership's interest expense decreased $8 million and $30 million for the
three and nine months ended September 30, 2021, respectively, primarily due to
lower total debt outstanding and lower borrowing costs on recently refinanced
and floating rate debt, partially offset by lower interest capitalized; and
•Sunoco LP's interest expense decreased $3 million and $7 million for the three
and nine months ended September 30, 2021, respectively, 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. For the nine months ended September 30, 2021, impairment
losses included a total of $5 million recognized by USAC related to its
compression equipment, as well as a $6 million impairment of intangible assets
related to customer contracts within the Partnership's crude operations.
For the three months ended September 30, 2020, the Partnership recognized
goodwill impairments totaling $1.46 billion and fixed asset impairments totaling
$19 million primarily due to decreases in projected future cash flow as a result
of the overall market demand decline. In addition, USAC recognized an equipment
impairment of $2 million based on changes in market conditions. For the nine
months ended September 30, 2020, impairment losses also included goodwill
impairments recognized by the Partnership during the first quarter of 2020
totaling $706 million due to decreases in projected future cash flows as a
result of overall market demand decline and a goodwill impairment recognized by
USAC of $619 million, as well as an equipment impairment of $4 million based on
changes in market conditions during the second quarter of 2020.
Gains (Losses) on Interest Rate Derivatives. Gains and losses on interest rate
derivatives during the three and nine months ended September 30, 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. 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 3.
Quantitative and Qualitative Disclosures About Market Risk" and in Note 12 to
our consolidated financial statements included in "Item 1. Financial
Statements."
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 September 30, 2021 and September 30, 2020, increases in fuel prices
reduced lower of cost or market reserve requirements by $9 million and
$11 million, respectively. For the nine months ended September 30, 2021, an
increase in fuel prices reduced lower of cost or market reserve requirements for
the period by $168 million. For the nine months ended September 30, 2020, a
decline in fuel prices increased lower of cost or market reserve requirements
for the period by $126 million, resulting in an adverse impact to net income.
Losses on Extinguishments of Debt. During the nine months ended September 30,
2021, the losses on extinguishments of debt also included Sunoco LP's January
2021 repurchase of the remainder of its 2023 senior notes as well as the
Partnership's partial repayment of its Term Loan in April 2021. During the nine
months ended September 30, 2020, amounts were related to ETO's senior notes
redemption in January 2020.
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.
Impairment of Investment in an Unconsolidated Affiliate. During the three and
nine months ended September 30, 2020, the Partnership recorded an impairment to
its investment in White Cliffs of $129 million due to a decrease in projected
future revenues and cash flows as a result of the overall market demand decline
that occurred subsequent to the SemGroup, LLC acquisition and related purchase
price allocation in December 2019.
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Other, net. Other, net primarily includes the amortization of regulatory assets
and other income and expense amounts.
Income Tax Expense. For the three and nine months ended September 30, 2021
compared to the same periods last year, income tax expense increased due to
higher earnings from the Partnership's consolidated corporate subsidiaries.
Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated
affiliates:
                                        Three Months Ended                                     Nine Months Ended
                                          September 30,                                          September 30,
                                      2021               2020            Change              2021              2020            Change
Equity in earnings (losses) of
unconsolidated affiliates:
Citrus                            $       44          $    50          $     (6)         $     123          $   127          $     (4)
FEP (1)                                    -             (106)              106                  -             (158)              158
MEP                                       (5)              (1)               (4)               (12)              (3)               (9)
White Cliffs                              (1)               2                (3)                 -               19               (19)
Other                                     33               23                10                 80               61                19

Total equity in profit or loss of non-consolidated affiliates $ 71 $ (32) $ 103 $ 191 $ 46 $ 145

Adjusted EBITDA related to
unconsolidated affiliates(2):
Citrus                            $       87          $    96          $     (9)         $     251          $   264          $    (13)
FEP                                        -               19               (19)                 -               57               (57)
MEP                                        4                8                (4)                14               23                (9)
White Cliffs                               4               11                (7)                14               38               (24)
Other                                     46               35                11                121               98                23

Total adjusted EBITDA related to non-consolidated affiliates $ 141 $ 169 $ (28) $ 400 $ 480 $ (80)

Distributions received from
unconsolidated affiliates:
Citrus                            $      106          $    48          $     58          $     191          $   155          $     36
FEP                                        -               20               (20)                 4               55               (51)
MEP                                        1                4                (3)                 9               22               (13)
White Cliffs                               5                2                 3                 25               25                 -
Other                                     26               24                 2                 73               63                10
Total distributions received from
unconsolidated affiliates         $      138          $    98          $    

40 $ 302 $ 320 $ (18)

(1)For the three and nine months ended September 30, 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 $123 million and $208 million, respectively.
(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.
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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 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. The recognition of the
impacts of Winter Storm Uri during the nine months ended September 30, 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.
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Intrastate Transportation and Storage
                                                  Three Months Ended                                         Nine Months Ended
                                                     September 30,                                             September 30,
                                                2021                  2020             Change              2021               2020            Change
Natural gas transported (BBtu/d)              12,335                 12,185               150              12,465           12,745             (280)
Withdrawals from storage natural gas
inventory (BBtu)                               2,350                 10,315            (7,965)             32,038           15,380           16,658
Revenues                                 $     1,217               $    654          $    563          $    7,066          $ 1,763          $ 5,303
Cost of products sold                            978                    434               544               3,636              985            2,651
Segment margin                                   239                    220                19               3,430              778            2,652
Unrealized (gains) losses on commodity
risk management activities                        (1)                    23               (24)                (18)             (16)              (2)
Operating expenses, excluding non-cash
compensation expense                             (64)                   (42)              (22)               (199)            (131)             

(68)

Selling, general and administrative
expenses, excluding non-cash
compensation expense                              (8)                    (7)               (1)                (25)             (22)              (3)
Adjusted EBITDA related to
unconsolidated affiliates                          6                      7                (1)                 19               19                -
Other                                              -                      2                (2)                  2                2                -
Segment Adjusted EBITDA                  $       172               $    203          $    (31)         $    3,209          $   630          $ 2,579


Volumes. For the three months ended September 30, 2021 compared to the same
period last year, transported volumes increased primarily due to production
increases in the Permian.
For the nine months ended September 30, 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.
Segment Margin. The components of our intrastate transportation and storage
segment margin were as follows:
                                       Three Months Ended                                        Nine Months Ended
                                         September 30,                                             September 30,
                                     2021               2020            Change                 2021                 2020            Change
Transportation fees              $      162          $   151          $     11          $       542              $   460          $    82
Natural gas sales and other
(excluding unrealized gains and
losses)                                  39               75               (36)               1,167                  231              936
Retained fuel revenues
(excluding unrealized gains and
losses)                                  29               12                17                  145                   31              114
Storage margin (excluding
unrealized gains and losses and
fair value inventory
adjustments)                              8                5                 3                1,558                   40            1,518
Unrealized gains on commodity
risk management activities and
fair value inventory adjustments          1              (23)               24                   18                   16                2
Total segment margin             $      239          $   220          $     19          $     3,430              $   778          $ 2,652


Segment Adjusted EBITDA. For the three months ended September 30, 2021 compared
to the same period last year, Segment Adjusted EBITDA related to our intrastate
transportation segment decreased due to the net effects of the following:
•a decrease of $36 million in realized natural gas sales and other primarily due
to lower optimization volumes with shifts to long-term third-party contracts
from the Permian to the Gulf Coast and lower spreads; and
•an increase of $22 million in operating expenses primarily due to increases of
$9 million in cost of fuel consumption due to higher gas prices, $6 million in
maintenance project costs, $3 million in employee related expenses, and $3
million in ad valorem taxes; partially offset by
•an increase of $11 million in transportation fees due to increased firm
transportation volumes from the Permian;
•an increase of $17 million in retained fuel revenues primarily due to higher
natural gas prices; and
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•an increase of $3 million in realized storage margin due to higher storage
optimization.
Segment Adjusted EBITDA. For the nine months ended September 30, 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 $936 million in realized natural gas sales and other primarily
due to natural gas sales during Winter Storm Uri;
•an increase of $114 million in retained fuel revenues primarily due to higher
natural gas prices during Winter Storm Uri; and
•an increase of $82 million in transportation fees due to revenues from Winter
Storm Uri and demand volume ramp-ups from the Permian, partially offset by the
expiration of certain contracts on our Regency Intrastate Gas System; partially
offset by
•an increase of $68 million in operating expenses primarily due to increases of
$45 million in cost of fuel consumption and $4 million in electricity costs,
both of which were primarily due to higher gas prices related to Winter Storm
Uri, as well as increases of $9 million in maintenance project costs, $7 million
in employee related costs, and $3 million in outside services and material
costs.
Interstate Transportation and Storage
                                       Three Months Ended                                      Nine Months Ended
                                          September 30,                                          September 30,
                                     2021               2020             Change              2021               2020            Change
Natural gas transported (BBtu/d)      9,917            10,387              (470)              9,769           10,422             (653)
Natural gas sold (BBtu/d)                16                15                 1                  18               16                2
Revenues                         $      418          $    471          $    (53)         $    1,350          $ 1,380          $   (30)

Operating expenses, excluding
non-cash compensation,
amortization and accretion
expenses                               (152)             (147)               (5)               (429)            (429)               -
Selling, general and
administrative expenses,
excluding non-cash compensation,
amortization and accretion
expenses                                (21)              (20)               (1)                (63)             (57)              (6)
Adjusted EBITDA related to
unconsolidated affiliates                91               122               (31)                265              343              (78)

Other                                    (2)               (1)               (1)                 (5)              (5)               -
Segment Adjusted EBITDA          $      334          $    425          $    (91)         $    1,118          $ 1,232          $  (114)


Volumes. For the three and nine months ended September 30, 2021 compared to the
same periods last year, transported volumes decreased primarily due to
foundation shipper contract expirations and a shipper bankruptcy on our Tiger
system, as well as lower utilization resulting from unfavorable market
conditions on our Trunkline system.
Segment Adjusted EBITDA. For the three months ended September 30, 2021 compared
to the same period last year, Segment Adjusted EBITDA related to our interstate
transportation and storage segment decreased due to the net impacts of the
following:
•a decrease of $53 million in revenues primarily due to a $37 million decline
resulting from shipper contract expirations on our Tiger system and an $18
million decline due to a shipper bankruptcy during 2020 also on our Tiger
system. In addition, transportation revenues decreased by $16 million on our
Panhandle and Trunkline systems due to lower demand. These decreases were
partially offset by an increase of $13 million in transportation revenue from
our Rover system as a result of more favorable market conditions;
•an increase of $5 million in operating expenses primarily due to a $7 million
increase from the revaluation of system gas, a $5 million increase in
maintenance project costs, a $3 million increase in employee costs, and $2
million increase in ad valorem taxes; partially offset by a decrease in credit
losses in the prior period;
•an increase of $1 million in selling, general and administrative expenses
primarily due to higher allocated overhead costs and employee costs; and
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•a decrease of $31 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, a $9 million decrease from our Citrus joint venture due to a
contractual rate adjustment and a $3 million decrease from our Midcontinent
Express Pipeline joint venture due to lower rates on short-term capacity.
Segment Adjusted EBITDA. For the nine months ended September 30, 2021 compared
to the same period last year, Segment Adjusted EBITDA related to our interstate
transportation and storage segment decreased due to the net impacts of the
following:
•a decrease of $30 million in revenues primarily due to a $97 million decline
resulting from shipper contract expirations on our Tiger system and a $37
million decline due to a shipper bankruptcy during 2020 also on our Tiger
system. In addition, revenues decreased by $25 million on our Panhandle and
Trunkline systems due to lower demand. These decreases were partially offset by
increased transportation revenues of $30 million from our Rover system, and a
$96 million increase in operational gas sales;
•an increase of $6 million in selling, general and administrative expenses
primarily resulting from higher allocated overhead and employee costs; and
•a decrease of $78 million in Adjusted EBITDA related to unconsolidated
affiliates primarily due to a $57 million decrease from our Fayetteville Express
Pipeline joint venture as a result of the expiration of foundation shipper
contracts, a $13 million decrease from our Citrus joint venture due to higher
project expenses and allocated costs as well as lower revenue resulting from a
contractual rate adjustment, and an $8 million decrease from our Midcontinent
Express Pipeline joint venture due to capacity sold at lower rates.
Midstream
                                       Three Months Ended                                      Nine Months Ended
                                          September 30,                                          September 30,
                                      2021                2020            Change             2021               2020            Change
Gathered volumes (BBtu/d)           12,991              12,904               87              12,712           13,071             (359)
NGLs produced (MBbls/d)                667                 635               32                 624              616                8
Equity NGLs (MBbls/d)                   37                  32                5                  35               35                -
Revenues                        $    2,919             $ 1,377          $ 1,542          $    7,790          $ 3,565          $ 4,225
Cost of products sold                2,153                 668            1,485               5,864            1,716            4,148
Segment margin                         766                 709               57               1,926            1,849               77

Operating expenses, excluding
non-cash compensation expense         (191)               (169)             (22)               (551)            (528)             (23)
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                (28)                (21)              (7)                (80)             (67)             (13)
Adjusted EBITDA related to
unconsolidated affiliates                8                   9               (1)                 23               23                -
Other                                    1                   2               (1)                  3                3                -
Segment Adjusted EBITDA         $      556             $   530          $    26          $    1,321          $ 1,280          $    41


Volumes. Gathered volumes and NGL production increased during the three months
ended September 30, 2021 compared to the same period last year primarily due to
volume increases in the Permian, Ark-La-Tex, and South Texas regions, partially
offset by volume declines in the Northeast and Mid-Continent/Panhandle regions.
Gathered volumes and NGL production decreased during the nine months ended
September 30, 2021 compared to the same period last year primarily due to volume
decreases in the South Texas, Mid-Continent/Panhandle, Northeast and North Texas
regions partially offset by volume growth in the Permian and Ark-La-Tex regions.
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Segment Margin. The components of our midstream segment gross margin were as
follows:
                                      Three Months Ended                                    Nine Months Ended
                                        September 30,                                         September 30,
                                    2021               2020            Change             2021               2020            Change
Gathering and processing
fee-based revenues              $      535          $   642          $  (107)         $    1,555          $ 1,675          $  (120)
Non-fee-based contracts and
processing                             231               67              164                 371              174              197

Total segment margin            $      766          $   709          $    57          $    1,926          $ 1,849          $    77


Segment Adjusted EBITDA. For the three months ended September 30, 2021 compared
to the same period last year, Segment Adjusted EBITDA related to our midstream
segment increased due to the net impacts of the following:
•an increase of $156 million in non-fee-based margin due to favorable NGL prices
of $96 million and natural gas prices of $60 million; and
•an increase of $8 million in non-fee-based margin due to increased throughput
in the Permian region and the ramp-up of recently completed assets in the
Northeast region; partially offset by
•a decrease of $107 million in fee-based margin due to the recognition of $103
million related to the restructuring and assignment of certain gathering and
processing contracts in the Ark-La-Tex region in the third quarter of 2020;
•an increase of $22 million in operating expenses due to an increase of $15
million in employee costs and $6 million in outside services; and
•an increase of $7 million in selling, general and administrative expenses due
to higher allocated overhead costs.
Segment Adjusted EBITDA. For the nine months ended September 30, 2021 compared
to the same period last year, Segment Adjusted EBITDA related to our midstream
segment increased due to the net impacts of the following:
•an increase of $319 million in non-fee-based margin due to favorable NGL prices
of $197 million and natural gas prices of $122 million; and
•an increase of $21 million in non-fee-based margin due to increased throughput
in the Permian region and the ramp-up of recently completed assets in the
Northeast region; partially offset by
•a decrease of $143 million in non-fee-based margin due to the impacts of Winter
Storm Uri;
•a decrease of $120 million in fee-based margin due to the recognition of $103
million related to the restructuring and assignment of certain gathering and
processing contracts in the Ark-La-Tex region in the third quarter of 2020, as
well as volume declines in the current period;
•an increase of $23 million in operating expenses due to an increase of $35
million in employee costs offset by a decrease of $9 million in outside services
and $2 million in materials; and
•an increase of $13 million in selling, general and administrative expenses due
to higher allocated overhead costs.
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NGL and Refined Products Transportation and Services
                                         Three Months Ended                                      Nine Months Ended
                                            September 30,                                          September 30,
                                        2021                2020            Change             2021               2020            Change
NGL transportation volumes
(MBbls/d)                              1,803               1,493              310               1,685            1,431              254
Refined products transportation
volumes (MBbls/d)                        526                 460               66                 500              460               40
NGL and refined products terminal
volumes (MBbls/d)                      1,237                 850              387               1,156              813              343
NGL fractionation volumes
(MBbls/d)                                884                 877                7                 815              839              (24)
Revenues                          $    5,262             $ 2,623          $ 2,639          $   13,774          $ 7,457          $ 6,317
Cost of products sold                  4,347               1,712            2,635              11,035            4,916            6,119
Segment margin                           915                 911                4               2,739            2,541              198
Unrealized (gains) losses on
commodity risk management
activities                                (2)                 11              (13)                (71)              34             (105)
Operating expenses, excluding
non-cash compensation expense           (207)               (162)             (45)               (573)            (475)             (98)
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                  (27)                (20)              (7)                (82)             (64)             (18)
Adjusted EBITDA related to
unconsolidated affiliates                 26                  22                4                  75               63               12

Other                                      1                   -                1                   1                -                1
Segment Adjusted EBITDA           $      706             $   762          $   (56)         $    2,089          $ 2,099          $   (10)


Volumes. For the three and nine months ended September 30, 2021 compared to the
same periods last year, NGL transportation volumes increased primarily due to
the initiation of service on our propane and ethane export pipelines into our
Nederland Terminal in the fourth quarter of 2020, higher volumes from the Eagle
Ford region and higher volumes on our Mariner East and West pipeline systems.
For the nine months ended September 30, 2021 compared to the same period last
year, the increase in NGL transportation volumes was partially offset by lower
volumes caused by production interruptions, primarily in the Permian region, due
to Winter Storm Uri during the first quarter of 2021.
Refined products transportation volumes increased for the three and nine months
ended September 30, 2021 compared to the same periods last year due to recovery
from COVID-19 related demand reduction in the prior period.
NGL and refined products terminal volumes increased for the three and nine
months ended September 30, 2021 compared to the same periods last year primarily
due to the previously mentioned start of new pipelines and refined product
demand recovery.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility
decreased for the nine months ended September 30, 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.
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Segment Margin. The components of our NGL and refined products transportation
and services segment margin were as follows:
                                         Three Months Ended                                     Nine Months Ended
                                           September 30,                                          September 30,
                                       2021               2020            Change              2021               2020            Change
Transportation margin              $      514          $   494          $     20          $    1,495          $ 1,419          $     76
Fractionators and refinery
services margin                           182              189                (7)                510              541               (31)
Terminal services margin                  166              130                36                 470              410                60
Storage margin                             63               63                 -                 200              181                19
Marketing margin                          (12)              46               (58)                 (7)              24               (31)
Unrealized gains (losses) on
commodity risk management
activities                                  2              (11)               13                  71              (34)              105
Total segment margin               $      915          $   911          $      4          $    2,739          $ 2,541          $    198


Segment Adjusted EBITDA. For the three months ended September 30, 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 $58 million in marketing margin primarily due to a $36 million
decrease in optimization gains and from the sale of NGL component products at
our Mont Belvieu facility and a $19 million decrease in northeast blending and
optimization primarily due to realized losses on financial instruments and
increased costs related to renewable identification numbers ("RINs"), and a $6
million decrease due to optimization gains realized in 2020 as marketing prices
increased. These decreases were partially offset by a $4 million increase in
butane blending margin due to more favorable spreads and incremental gasoline
blending in the third quarter of 2021;
•an increase of $45 million in operating expenses primarily due to a $21 million
increase in utilities cost, a $16 million increase in employee related costs, a
$6 million increase in materials and other associated costs to run the assets
and a $2 million increase in allocated corporate overhead costs;
•an increase of $7 million in selling, general and administrative expenses
primarily due to corporate cost reductions in 2020; and
•a decrease of $7 million in fractionators and refinery services margin
primarily due to a $10 million decrease resulting from a slightly lower average
rate achieved due to the increased utilization of our ethane optimization
strategy. This decrease was partially offset by a $5 million increase in
blending activity at our fractionation facility; partially offset by
•an increase of $36 million in terminal services margin primarily due to a $20
million increase in ethane export fees at our Nederland Terminal, an increase of
$13 million in loading fees due to higher LPG export volumes at our Nederland
Terminal and a $3 million increase at our refined product terminals due to
higher throughput and timing of accounting adjustments;
•an increase of $20 million in transportation margin primarily due to a $30
million increase due to higher export volumes feeding into our Nederland
Terminal, a $6 million increase from higher throughput on our Mariner pipeline
system, and a $6 million increase in refined products transportation due to
recovery from COVID-19 related demand reduction in the prior period and other
refined products demand increases. These increases were partially offset by a
$23 million decrease resulting from a slightly lower average rate achieved due
to the increased utilization of our ethane optimization strategy; and
•an increase of $4 million in Adjusted EBITDA related to unconsolidated
affiliates due to an increase primarily resulting from higher throughput on
Explorer pipeline due to COVID-19 demand recovery.
Segment Adjusted EBITDA. For the nine months ended September 30, 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:
•an increase of $98 million in operating expenses primarily due to a $54 million
increase in utilities costs, $28 million increase in employee costs resulting
primarily from corporate cost reductions in 2020 and an increase of $15 million
in allocated corporate overhead costs;
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•a decrease of $31 million in marketing margin primarily due to a $29 million
decrease in northeast blending and optimization primarily due to realized losses
on financial instruments and increased costs related to RINs and intrasegment
charges of $28 million which were fully offset within our transportation margin.
These decreases were partially offset by a $19 million increase in butane
blending margin due to more favorable spreads and additional blending days
granted by the EPA due to the Colonial Pipeline shutdown, and an $8 million
increase due to inventory and other adjustments in the prior period;
•a decrease of $31 million in fractionators and refinery services margin
primarily due to a $44 million decrease resulting from downtime on our various
fractionators due to Winter Storm Uri in the first quarter of 2021 and a
slightly lower average rate achieved due to increased utilization of our ethane
optimization strategy. This decrease was partially offset by a $10 million
increase from blending activity at our fractionators facility; and
•an increase of $18 million in selling, general and administrative expenses
primarily due to corporate cost reductions in 2020; partially offset by
•an increase of $76 million in transportation margin primarily due to a $76
million increase due to higher export volumes feeding into our Nederland
Terminal, a $39 million increase from higher throughput on our Mariner pipeline
systems, intrasegment revenues of $28 million which are fully offset by a charge
reflected in our marketing margin, and a $15 million increase in refined
products transportation due to recovery from COVID-19 related demand reduction
in the prior period and other refined products demand increases. These increases
were partially offset by an $81 million decrease resulting from lower throughput
across the various regions in Texas due to Winter Storm Uri related production
outages and a slightly lower average rate achieved due to increased utilization
of our ethane optimization strategy;
•an increase of $60 million in terminal services margin primarily due to a $49
million increase in ethane export fees at our Nederland Terminal, a $36 million
increase in loading fees due to higher LPG export volumes at our Nederland
Terminal, an $11 million increase due to higher throughput at our Marcus Hook
Terminal and a $10 million increase due to higher throughput and storage at our
refined product terminals due to recovery from COVID-19 related demand reduction
in the prior period and other refined products demand increases. These increases
were partially offset by a $44 million decrease resulting from an expiration of
a third-party contract at our Nederland Terminal in the second quarter of 2020;
•an increase of $19 million in storage margin primarily due to fees generated
from exported volumes; and
•an increase of $12 million in Adjusted EBITDA related to unconsolidated
affiliates due to a $7 million increase primarily resulting from higher
throughput on Explorer pipeline due to COVID-19 demand recovery and a $5 million
increase from higher volumes on White Cliffs pipeline.
Crude Oil Transportation and Services
                                         Three Months Ended                                      Nine Months Ended
                                            September 30,                                          September 30,
                                        2021                2020            Change             2021               2020            Change
Crude transportation volumes
(MBbls/d)                              4,173               3,551              622               3,901            3,840               61
Crude terminals volumes (MBbls/d)      2,703               2,317              386               2,553            2,688             (135)
Revenues                          $    4,578             $ 2,850          $ 1,728          $   12,498          $ 8,877          $ 3,621
Cost of products sold                  3,918               2,096            1,822              10,520            6,704            3,816
Segment margin                           660                 754              (94)              1,978            2,173             (195)
Unrealized (gains) losses on
commodity risk management
activities                                14                  (1)              15                  12                9                3
Operating expenses, excluding
non-cash compensation expense           (142)               (112)             (30)               (414)            (401)             (13)
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                  (44)                (28)             (16)               (102)             (82)             (20)
Adjusted EBITDA related to
unconsolidated affiliates                  7                   9               (2)                 15               32              (17)

Other                                      1                   9               (8)                  1               10               (9)
Segment Adjusted EBITDA           $      496             $   631          $  (135)         $    1,490          $ 1,741          $  (251)

Volumes. For the three months ended September 30, 2021 compared to the same period last year, crude transportation volumes were higher on our Texas Bakken pipeline and pipeline, driven by a resumption of crude oil production in these areas

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a result of higher crude oil prices as well as a recovery in refinery
utilization. Volumes on our Bayou Bridge pipeline were also higher, driven by
more favorable crude oil differentials for shippers. Volumes also benefited from
a full quarter of operations from our Cushing South pipeline. Crude terminal
volumes were higher due to increased customer throughput activity at our Gulf
Coast terminals.
For the nine months ended September 30, 2021 compared to the same period last
year, crude transportation volumes were higher on our Bakken pipeline and Bayou
Bridge pipelines, reflecting the continued recovery in crude oil production in
North Dakota and more favorable crude oil differentials for shippers on Bayou
Bridge. Volumes on our Texas pipeline system were slightly lower, primarily
reflecting adverse weather negatively impacting volumes in the first quarter of
2021 and less favorable spreads for shippers to some markets in 2021. Crude
terminal volumes were lower primarily due to reduced export demand.
Segment Adjusted EBITDA. For the three months ended September 30, 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 $79 million in segment margin (excluding unrealized gains and
losses on commodity risk management activities) primarily due to a $133 million
decrease from our crude oil acquisition and marketing business due to storage
trading gains realized in the prior period, unfavorable crude inventory
valuation adjustments, and less favorable pricing conditions impacting our
Bakken to Gulf Coast trading operations, a $6 million decrease in throughput at
our crude terminals primarily driven by lower export demand, and a $3 million
decrease from our Texas crude pipeline system due to lower average tariff rates
realized; partially offset by a $65 million increase from improved performance
on our Bayou Bridge and Bakken pipelines;
•an increase of $30 million in operating expenses primarily due to higher
volume-driven expenses and higher employee expenses;
•an increase of $16 million in selling, general and administrative expenses
primarily due to legal expenses and higher overhead allocations to the crude
segment as a result of assets acquired; and
•a decrease of $2 million in Adjusted EBITDA related to unconsolidated
affiliates due to lower volumes on White Cliffs pipeline from lower crude oil
production, partially offset by an increase in jet fuel sales by our joint
ventures.
Segment Adjusted EBITDA. For the nine months ended September 30, 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 $192 million in segment margin (excluding unrealized gains and
losses on commodity risk management activities) primarily due to a $152 million
decrease from our Texas crude pipeline system due to lower utilization and lower
average tariff rates realized, a $58 million decrease from our crude oil
acquisition and marketing business primarily due to storage trading gains
realized in the prior period and less favorable pricing conditions impacting our
Bakken to Gulf Coast trading operations, partially offset by favorable crude
inventory valuation adjustments and a $34 million decrease in throughput at our
crude terminals primarily driven by reduced export demand; partially offset by
an $18 million increase due to higher volumes on our Bayou Bridge pipeline and a
$37 million increase due to higher volumes on our Bakken Pipeline;
•an increase of $13 million in operating expenses primarily due to higher
volume-driven expenses and higher employee expenses;
•an increase of $20 million in selling, general and administrative expenses
primarily due to legal expenses and higher overhead allocations to the crude
segment as a result of assets acquired; and
•a decrease of $17 million in Adjusted EBITDA related to unconsolidated
affiliates due to lower volumes on White Cliffs pipeline from lower crude oil
production, partially offset by an increase in jet fuel sales by our joint
ventures.
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Investment in Sunoco LP
                                       Three Months Ended                                      Nine Months Ended
                                          September 30,                                          September 30,
                                      2021                2020            Change             2021               2020            Change
Revenues                        $    4,779             $ 2,805          $ 1,974          $   12,642          $ 8,157          $ 4,485
Cost of products sold                4,472               2,497            1,975              11,631            7,383            4,248
Segment margin                         307                 308               (1)              1,011              774              237
Unrealized (gains) losses on
commodity risk management
activities                               2                  (6)               8                  (5)               -               (5)
Operating expenses, excluding
non-cash compensation expense          (85)                (84)              (1)               (236)            (265)              29
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                (23)                (24)               1                 (67)             (76)               9
Adjusted EBITDA related to
unconsolidated affiliates                3                   2                1                   7                7                -
Inventory valuation adjustments         (9)                (11)               2                (168)             126             (294)
Other                                    3                   4               (1)                 14               14                -
Segment Adjusted EBITDA         $      198             $   189          $     9          $      556          $   580          $   (24)


The Investment in Sunoco LP segment reflects the consolidated results of Sunoco
LP.
Segment Adjusted EBITDA. For the three months ended September 30, 2021 compared
to the same period last year, Segment Adjusted EBITDA related to our investment
in Sunoco LP segment increased due to the net impacts of the following:
•an increase in the gross profit on motor fuel sales of $4 million primarily due
to a 6.4% increase in gallons sold, partially offset by a 7.3% decrease in gross
profit per gallon sold; and
•an increase in non-motor fuel sales of $5 million primarily due to increased
credit card transactions, merchandise gross profit and franchise fee income.
Segment Adjusted EBITDA. For the nine months ended September 30, 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 $62 million primarily due
to a 14.8% decrease in gross profit per gallon sold, partially offset by a 7.5%
increase in gallons sold; partially offset by
•a decrease in operating expenses and selling, general and administrative
expenses of $38 million primarily due to lower employee costs of and lower
expected credit losses.
Investment in USAC
                                      Three Months Ended                                     Nine Months Ended
                                        September 30,                                          September 30,
                                    2021               2020            Change              2021              2020            Change
Revenues                        $      159          $   161          $     (2)         $     473          $   509          $    (36)
Cost of products sold                   19               20                (1)                61               62                (1)
Segment margin                         140              141                (1)               412              447               (35)

Operating expenses, excluding
non-cash compensation expense          (31)             (27)               (4)               (83)             (92)                9
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                (10)             (10)                -                (30)             (40)               10

Segment Adjusted EBITDA         $       99          $   104          $     (5)         $     299          $   315          $    (16)

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

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Segment Adjusted EBITDA. For the three months ended September 30, 2021 compared
to the same period last year, Segment Adjusted EBITDA related to our investment
in USAC segment decreased due to the following:
•a decrease of $1 million in segment margin primarily due to slightly lower
revenue generating horsepower; and
•an increase of $4 million in operating expenses primarily due to an increase in
property taxes and expenses related to our vehicle fleet.
Segment Adjusted EBITDA. For the nine months ended September 30, 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 $35 million in segment margin primarily due to lower revenue
generating horsepower; partially offset by
•a decrease of $9 million in operating expenses primarily driven by a $7 million
decrease in direct labor expenses and a $4 million decrease primarily due to
sales tax refunds received in 2021; and
•a decrease of $10 million in selling, general and administrative expenses
primarily due to a $6 million decrease in the provision for expected credit
losses, a $2 million decrease in severance charges related to the departure of
an executive and a $2 million decrease in employee-related expenses.
All Other
                                      Three Months Ended                                     Nine Months Ended
                                        September 30,                                          September 30,
                                    2021               2020            Change              2021               2020            Change
Revenues                        $      696          $   367          $    329          $    2,784          $ 1,372          $ 1,412
Cost of products sold                  652              318               334               2,464            1,110            1,354
Segment margin                          44               49                (5)                320              262               58
Unrealized losses on commodity
risk management activities               6                3                 3                   8                -                8
Operating expenses, excluding
non-cash compensation expense          (29)             (35)                6                (118)            (100)             (18)
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                (13)             (23)               10                 (71)             (80)               9
Adjusted EBITDA related to
unconsolidated affiliates                2                1                 1                   1                1                -
Other and eliminations                   8               27               (19)                 13              (21)              34
Segment Adjusted EBITDA         $       18          $    22          $     (4)         $      153          $    62          $    91


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 September 30, 2021 compared
to the same period last year, Segment Adjusted EBITDA related to our all other
segment decreased primarily due to the net impacts of the following:
•a decrease of $12 million due to the settlement of customer disputes related to
prior period activity;
•a decrease of $7 million due to the revaluation of natural gas inventory; and
•a decrease of $2 million due to lower trading gains; partially offset by
•an increase of $5 million due to higher compressor sales and lower operating
expenses in our compressor business;
•an increase of $2 million from Energy Transfer Canada due to the aggregate
impact of multiples smaller changes; and
•an increase of $2 million due to lower utility expense.
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Segment Adjusted EBITDA. For the nine months ended September 30, 2021 compared
to the same period last year, Segment Adjusted EBITDA related to our all other
segment increased primarily due to the net impacts of the following:
•an increase of $60 million from power trading activities primarily due to
short-term, favorable market conditions created by Winter Storm Uri in February
of 2021;
•an increase of $17 million primarily due to revenues earned by our dual drive
compression business under the Electric Reliability Council of Texas ("ERCOT")
responsive reserve program during Winter Storm Uri;
• an increase of $11 million due to improved margins at our dual drive
compression business resulting from more favorable market pricing conditions;
•an increase of $12 million due to lower merger and acquisition expenses;
•an increase of $6 million from Energy Transfer Canada due to the aggregate
impact of multiples smaller changes;
•an increase of $2 million due to a contract expiration at our natural resources
business in 2020; and
•an increase of $2 million due to higher compressor sales and lower operating
expenses in our compressor business; partially offset by
•a decrease of $22 million from 2020 insurance proceeds received on settled
claims related to our MTBE litigation.
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.
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      $    25      $   30      $  35
Interstate transportation and storage (1)                    50           75         115        120
Midstream                                                   445          470         115        120
NGL and refined products transportation and services        650          725         110        120
Crude oil transportation and services (1)                   275          325          90        100
All other (including eliminations)                           90          115          45         55
Total capital expenditures                              $ 1,525      $ 1,735      $  505      $ 550


(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 $20 million in maintenance capital
expenditures and currently has budgeted between $30 million and $40 million in
expansion capital expenditures for the full year 2021.
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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
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"), 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.
Nine months ended September 30, 2021 compared to nine months ended September 30,
2020. Cash provided by operating activities during 2021 was $9.42 billion
compared to $5.46 billion for 2020, and net income was $5.46 billion for 2021
and net loss was $693 million for 2020. The difference between net income and
net cash provided by operating activities for the nine months ended September
30, 2021 primarily consisted of net changes in operating assets and liabilities
(net of effects of acquisitions) of $970 million and other non-cash items
totaling $2.79 billion.
The non-cash activity in 2021 and 2020 consisted primarily of depreciation,
depletion and amortization of $2.84 billion and $2.72 billion, respectively,
non-cash compensation expense of $81 million and $93 million, respectively,
favorable inventory valuation adjustments of $168 million and unfavorable
inventory valuation adjustments of $126 million, respectively, deferred income
taxes of $199 million and $159 million, respectively, losses on extinguishments
of debt of $8 million and $62 million, respectively, and impairment losses of
$11 million and $2.80 billion, respectively. Non-cash activity also included
equity in earnings of unconsolidated affiliates of $191 million and $46 million
in 2021 and 2020, respectively, and impairment of investment in an
unconsolidated affiliate of $129 million in 2020.
Cash provided by operating activities includes cash distributions received from
unconsolidated affiliates that are deemed to be paid from cumulative earnings,
which distributions were $226 million in 2021 and $176 million in 2020.
Cash paid for interest, net of interest capitalized, was $1.57 billion and $1.47
billion for the nine months ended September 30, 2021 and 2020, respectively.
Interest capitalized was $97 million and $163 million for the nine months ended
September 30, 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.
Nine months ended September 30, 2021 compared to nine months ended September 30,
2020. Cash used in investing activities during 2021 was $1.91 billion compared
to $3.86 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 $2.02 billion compared to $3.97 billion for
2020. Additional detail related to our capital expenditures is provided in the
table below.
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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
nine months ended September 30, 2021:
                                                              Capital 

Expenses recorded during the period

                                                            Growth             Maintenance            Total
Intrastate transportation and storage                   $        17          $         24          $      41
Interstate transportation and storage                            24                    72                 96
Midstream                                                       272                    74                346
NGL and refined products transportation and services            508                    77                585
Crude oil transportation and services                           208                    61                269
Investment in Sunoco LP                                          70                    22                 92
Investment in USAC                                               26                    15                 41
All other (including eliminations)                               48                    26                 74
Total capital expenditures                              $     1,173         

$ 371 $ 1,544

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.
Nine months ended September 30, 2021 compared to nine months ended September 30,
2020. Cash used in financing activities during 2021 was $7.57 billion compared
to $1.61 billion for 2020. During 2021, we had a net decrease in our debt level
of $6.00 billion compared to a net increase of $358 million for 2020. In 2021
and 2020, we paid debt issuance costs of $3 million and $53 million,
respectively. During 2021, we received $889 million from offerings of preferred
units, and during 2020, our subsidiaries received $1.58 billion from offerings
of preferred units.
In 2021 and 2020, we paid distributions of $1.38 billion and $2.40 billion,
respectively, to our partners. In 2021 and 2020, we paid distributions of
$1.15 billion and $1.28 billion, respectively, to noncontrolling interests. In
2021 and 2020, we paid distributions of $37 million to our redeemable
noncontrolling interests. In addition, we received capital contributions of
$114 million in cash from noncontrolling interests in 2021 compared to $203
million in cash from noncontrolling interests in 2020.
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Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
                                                                      September 30,           December 31,
                                                                          2021                    2020
ET Indebtedness:
Senior Notes (1)                                                    $       36,454          $      37,855
Term Loan (2)                                                                    -                  2,000
Five-Year Credit Facility (2)                                                  599                  3,103
Subsidiary Indebtedness:
Transwestern Senior Notes                                                      400                    400
Panhandle Senior Notes                                                         235                    235
Bakken Senior Notes (3)                                                      2,500                  2,500
Sunoco LP Senior Notes and lease-related obligations                         2,701                  3,139
USAC Senior Notes                                                            1,475                  1,475
HFOTCO Tax Exempt Notes                                                        225                    225
Revolving credit facilities:
Sunoco LP Credit Facility                                                      250                      -
USAC Credit Facility                                                           506                    474
Energy Transfer Canada Revolving Credit Facility                                81                     57
Energy Transfer Canada Term Loan A                                             252                    261
Energy Transfer Canada KAPS Facility                                            51                      -

Other long-term debt                                                             4                      3
Net unamortized premiums, discounts, and fair value adjustments                (14)                   (10)
Deferred debt issuance costs                                                  (248)                  (279)
Total debt                                                                  45,471                 51,438
Less: current maturities of long-term debt                                     678                     21
Long-term debt, less current maturities                             $       

44 793 $ 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.
(3)The balance includes $650 million of 3.625% Senior Notes due April 2022
included in current maturities of long-term debt as of September 30, 2021.
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 second quarter of 2021, ET repaid $1.5 billion on the Term Loan in
part through proceeds from its Series H Preferred Unit issuance. During the
third quarter of 2021, the Partnership repaid the remaining $500 million balance
and terminated the Term Loan.
During the first quarter of 2021, ETO redeemed its $600 million aggregate
principal amount of 4.40% senior notes due April 1, 2021 and its $800 million
aggregate principal amount of 4.65% senior notes due June 1, 2021, using
proceeds from the Five-Year Credit Facility.
During the third quarter of 2021, ET issued par call notices to redeem in full
its $1.0 billion aggregate principal amount of 5.2% senior notes due February 1,
2022, and $900 million aggregate principal amount of 5.875% senior notes due
March 1, 2022.
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The Partnership expects to redeem both series of senior notes during the fourth
quarter of 2021, utilizing proceeds from its Five-Year Credit Facility.
On October 20, 2021, Sunoco LP completed a private offering of $800 million in
aggregate principal amount of 4.500% senior notes due 2030 (the "2030 Notes").
Sunoco LP used the proceeds from the private offering to fund a tender offer and
repurchase all of its senior notes due 2026.
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. During the third quarter of 2021, the Term Loan was repaid
in full and terminated.
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, 2024. 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 September 30, 2021, the Five-Year Credit Facility had $599 million of
outstanding borrowings, of which $590 million consisted of commercial paper. The
amount available for future borrowings was $4.37 billion, after accounting for
outstanding letters of credit in the amount of $31 million. The weighted average
interest rate on the total amount outstanding as of September 30, 2021 was
0.43%.
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
September 30, 2021, the 364-Day Facility had no outstanding borrowings.
Sunoco LP Credit Facility
As of September 30, 2021, the Sunoco LP Credit Facility had $250 million of
outstanding borrowings and $6 million in standby letters of credit and matures
in July 2023. The amount available for future borrowings at September 30, 2021
was $1.24 billion. The weighted average interest rate on the total amount
outstanding as of September 30, 2021 was 2.09%.
USAC Credit Facility
As of September 30, 2021, USAC had $506 million of outstanding borrowings under
the credit agreement. As of September 30, 2021, USAC had $1.09 billion of
availability under its credit facility, and subject to compliance with
applicable financial covenants, available borrowing capacity of $114 million.
The weighted average interest rate on the total amount outstanding as of
September 30, 2021 was 2.96%.
Energy Transfer Canada Credit Facilities
As of September 30, 2021, the Energy Transfer Canada Term Loan A and the Energy
Transfer Canada Revolving Credit Facility had outstanding borrowings of C$320
million and C$103 million, respectively (US$252 million and US$81 million,
respectively, at the September 30, 2021 exchange rate). As of September 30,
2021, the KAPS Facility had outstanding borrowings of C$65 million (US$51
million at the September 30, 2021 exchange rate).
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 September 30,
2021.
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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.
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
June 30, 2021           August 6, 2021        August 19, 2021           0.1525
September 30, 2021      November 5, 2021      November 19, 2021         0.1525


Cash Distributions on ET Preferred Units
As discussed in "Recent Developments", 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)          Series H (1)

March 31, 2021             May 3, 2021              May 17, 2021              $          -          $          -          $ 0.4609          $ 0.4766          $ 0.4750          $       33.75          $      35.625          $          -
June 30, 2021              August 2, 2021           August 16, 2021                  31.25                33.125            0.4609            0.4766            0.4750                      -                      -                     -
September 30, 2021         November 1, 2021         November 15, 2021                    -                     -            0.4609            0.4766            0.4750                  33.75                 35.625                 27.08    (2)


(1)Series A, Series B, Series F, Series G and Series H distributions are paid on
a semi-annual basis.
(2)Represents initial prorated distribution.
Description of ET Preferred Units
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
June 30, 2021           August 6, 2021        August 19, 2021           0.8255
September 30, 2021      November 5, 2021      November 19, 2021         0.8255


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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      $ 0.525
March 31, 2021          April 26, 2021        May 7, 2021             0.525
June 30, 2021           July 26, 2021         August 6, 2021          0.525
September 30, 2021      October 25, 2021      November 5, 2021        0.525


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.
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 possibility of cyber and malware attacks;
•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;
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•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;
•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 filed with the SEC on February 19, 2021 and "Part II -
Item 1A. Risk Factors" of our Quarterly Report on Form 10-Q for the quarter
ended June 30, 2021 filed with the SEC on August 5, 2021. 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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