Energy Transfer LP

ET

US29273V1008

Oil & Gas Transportation Services

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

November 05, 2020 at 12:29 pm EST

(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, 2019 filed with the
SEC on February 21, 2020. 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, 2019 filed with the SEC on
February 21, 2020, "Part II - Item 1A. Risk Factors" of our Quarterly Reports on
Form 10-Q for the quarter ended March 31, 2020 filed with the SEC on May 11,
2020 and in this Quarterly Report on Form 10-Q. 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, which include ETO. References to the "Parent Company" mean Energy
Transfer LP on a stand-alone basis.
RECENT DEVELOPMENTS
COVID-19
In 2020, the COVID-19 pandemic prompted several states and municipalities in
which we operate to take extraordinary and wide-ranging actions to contain and
combat the outbreak and spread of the virus, including mandates for many
individuals to substantially restrict daily activities and for many businesses
to curtail or cease normal operations. To the extent COVID-19 continues or
worsens, governments may impose additional similar restrictions. As a provider
of critical energy infrastructure, our business has been designated as a
"critical infrastructure sector" and our employees as "essential critical
infrastructure workers" pursuant to the Department of Homeland Security Guidance
on Essential Critical Infrastructure Workforce(s). To date, our field operations
have continued uninterrupted, and remote work and other COVID-19 related
conditions have not significantly impacted our ability to maintain operations or
caused us to incur significant additional expenses; however, we are unable to
predict the magnitude or duration of current and potential future COVID-19
mitigation measures. As an essential business providing critical energy
infrastructure, the safety of our employees and the continued operation of our
assets are our top priorities and we will continue to operate in accordance with
federal and state health guidelines and safety protocols. We have implemented
several new policies and provided employee training to help maintain the health
and safety of our workforce.
ET Contribution of SemGroup Assets to ETO
On December 5, 2019, ET completed the acquisition of SemGroup. During the first
and second quarters of 2020, ET contributed former SemGroup assets to ETO
through sale and contribution transactions.
ETO Series F and Series G Preferred Units Issuance
On January 22, 2020, ETO issued 500,000 of its Series F Preferred Units at a
price of $1,000 per unit and 1,100,000 of its Series G Preferred Units at a
price of $1,000 per unit. The net proceeds were used to repay amounts
outstanding under ETO's revolving credit facility and for general partnership
purposes.
ETO January 2020 Senior Notes Offering and Redemption
On January 22, 2020, ETO completed a registered offering (the "January 2020
Senior Notes Offering") of $1.00 billion aggregate principal amount of ETO's
2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of the
Partnership's 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal
amount of ETO's 5.000% Senior Notes due 2050 (collectively, the "Notes"). The
Notes are fully and unconditionally guaranteed by ETO's wholly-owned subsidiary,
Sunoco Logistics Operations, on a senior unsecured basis.
Using proceeds from the January 2020 Senior Notes Offering, ETO redeemed its
$400 million aggregate principal amount of 5.75% Senior Notes due September 1,
2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due
October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior
Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50%
Senior Notes due February 15, 2020, ET's $52 million aggregate principal amount
of 7.50% Senior Notes due October 15, 2020 and Transwestern's $175 million
aggregate principal amount of 5.36% Senior Notes due December 9, 2020.
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Lake Charles LNG
On March 30, 2020, Royal Dutch Shell plc ("Shell") announced that it would not
proceed with a proposed equity interest in the Lake Charles LNG liquefaction
project due to adverse market factors affecting Shell's business and its desire
to preserve cash in light of the current environment. We intend to continue to
develop the project, possibly in conjunction with one or more equity partners,
and we plan to evaluate a variety of alternatives to advance the project,
including the possibility of reducing the size of the project from three trains
(16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million
tonnes per annum). The project is fully permitted by federal, state and local
authorities, has all necessary export licenses and benefits from the
infrastructure related to the existing regasification facility at the same site,
including four LNG storage tanks, two deep water docks and other assets. In
light of the existing brownfield infrastructure and the advanced state of the
development of the project, we plan to continue to pursue the project on a
disciplined, cost effective basis, and ultimately we will determine whether to
make a final investment decision to proceed with the project based on market
conditions, capital expenditure considerations and our success in securing
equity participation by third parties as well as long-term LNG offtake
commitments on satisfactory terms.
Quarterly Cash Distribution
In October 2020, ET announced its quarterly distribution of $0.1525 per unit
($0.61 annualized) on ET common units for the quarter ended September 30, 2020.
On October 26, 2020 we announced a cash distribution for the third quarter of
$0.1525 per unit ($0.61 annualized) on ET common units. This distribution
represents a 50% decrease as compared to the distribution for the prior quarter.
The Partnership intends to use the excess cash flow resulting from this
distribution decrease to reduce its level of indebtedness. The Partnership will
continue to evaluate its cash distribution policy in light of its leverage ratio
and its capital expenditure outlook in order to preserve its investment grade
credit ratings.
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
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 Colombia 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 individual entities' ability to argue
in support of recovery of an income tax allowance, the impacts of the FERC's
policy on the treatment of income taxes may have on the rates ETO can charge for
the FERC regulated transportation services are unknown at this time.
The FERC also issued a Notice of Inquiry ("2017 Tax Law NOI") on March 15, 2018,
requesting comments on the effect of the Tax Act on FERC jurisdictional rates.
The 2017 Tax Law NOI states that of particular interest to the FERC is whether,
and if so how, the FERC should address changes relating to accumulated deferred
income taxes and bonus depreciation. Comments in response to the 2017 Tax Law
NOI were due on or before May 21, 2018. 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 Natural Gas Act
("NGA") to determine whether the rates currently charged by Panhandle are just
and reasonable and set the matter for hearing. Panhandle filed a cost and
revenue study on April 1, 2019. Panhandle filed a NGA Section 4 rate case on
August 30, 2019.
In March 2019, following the decision of the D.C. Circuit in Emera Maine v.
Federal Energy Regulatory Commission, the FERC issued a Notice of Inquiry
regarding its policy for determining return on equity ("ROE"). The FERC
specifically sought
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information and stakeholder views to help the FERC explore whether, and if so
how, it should modify its policies concerning the determination of ROE to be
used in designing jurisdictional rates charged by public utilities. The FERC
also expressly sought comment on whether any changes to its policies concerning
public utility ROEs should be applied to interstate natural gas and oil
pipelines. Initial comments were due in June 2019, and reply comments were due
in July 2019. On May 21, 2020, the FERC issued a Policy Statement on Determining
Return on Equity for Natural Gas and Oil Pipelines establishing a revised policy
for determining ROE, including the use of the Capital Asset Pricing Model in
addition to the Discounted Cash Flow Model for determining ROE and clarification
regarding the formation of proxy groups for establishing a pipeline's ROE.
Even without application of the FERC's recent policy statements on income tax
allowance or ROE or any additional action with respect to the 2017 Tax Law NOI,
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 including the allowance for income
taxes and the amount for accumulated deferred income taxes but also other
pipeline costs that will continue to affect the FERC's determination of just and
reasonable cost of service rates. Although changes in these two tax related
components may decrease, other components in the cost of service rate
calculation may increase and result in a newly calculated cost of service rate
that is the same as or greater than the prior cost of service rate. Moreover, we
receive revenues from our pipelines based on a variety of rate structures,
including cost of service rates, negotiated rates, discounted rates and
market-based rates. Many of our interstate pipelines, such as ETC Tiger
Pipeline, LLC, MEP and FEP, have negotiated market rates that were agreed to by
customers in connection with long-term contracts entered into to support the
construction of the pipelines. Other systems, such as FGT, Transwestern and
Panhandle, have a mix of tariff rate, discount rate, and negotiated rate
agreements. We do not expect market-based rates, negotiated rates or discounted
rates that are not tied to the cost of service rates to be affected by the
Revised Policy Statement or other regulations resulting from the March 15, 2018
proposals. The revenues we receive from natural gas transportation services we
provide pursuant to cost of service based rates may decrease in the future as a
result of the 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 ETO's
cost of service components and the outcomes of any challenges to our rates by
the FERC or our shippers.
Pipeline Certification
The FERC issued a Notice of Inquiry on April 19, 2018 ("Pipeline Certification
NOI"), thereby initiating a review of its policies on certification of natural
gas pipelines, including an examination of its long-standing Policy Statement on
Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999,
that is used to determine whether to grant certificates for new pipeline
projects. We are unable to predict what, if any, changes may be proposed as a
result of the Pipeline Certification NOI that will affect our natural gas
pipeline business or when such proposals, if any, might become effective.
Comments in response to the Pipeline Certification NOI were due on or before
July 25, 2018. We do not expect that any change in this policy would affect us
in a materially different manner than any other natural gas pipeline company
operating in the United States.
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. The indexing methodology is applicable to existing rates, with the
exclusion of market-based rates. The FERC's indexing methodology is subject to
review every five years. During the five-year period commencing July 1, 2016 and
ending June 30, 2021, common carriers charging indexed rates are permitted to
adjust their indexed ceilings annually by PPI-FG plus 1.23 percent. Many
existing pipelines utilize the FERC liquids index to change transportation rates
annually every July 1. With respect to liquids and refined products pipelines
subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline
to reflect the impacts to its cost of service from the Revised Policy Statement
and the Tax Act on Page 700 of the FERC Form No. 6. This information will be
used by the FERC in its next five year review of the liquids pipeline index to
generate the index level to be effective July 1, 2021, thereby including the
effect of the Revised Policy Statement and the Tax Act in the determination of
indexed rates prospectively, effective July 1, 2021. On June 18, 2020, the FERC
issued a Notice of Inquiry requesting comments on a proposed oil pipeline index
for the five-year period commencing July 1, 2021 and ending June 30, 2026, using
the PPI-FG plus 0.09% as the index level, and requested comments on whether and
how the index should reflect the Revised Policy Statement and the FERC's
treatment of accumulated deferred income taxes as well as the FERC's revised ROE
methodology. Comments on the indexing rate methodology Notice of Inquiry were
due August 17, 2020, with reply comments due September 11, 2020. The FERC's
establishment of a just and reasonable rate, including the determination of the
appropriate liquids pipeline index, is based on many components, and as noted,
the FERC's tax related changes will affect two such components, the allowance
for income taxes and the amount for accumulated deferred income taxes, while the
FERC's ROE policy and other pipeline costs also will continue to affect the
FERC's determination of the appropriate pipeline index. Accordingly, depending
on the FERC's application of its indexing rate methodology for the next five
year term of index
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rates, the Revised Policy Statement and tax effects related to the Tax Act may
impact our revenues associated with any transportation services we may provide
pursuant to cost of service based rates in the future, including indexed rates.
Trends and Outlook
Recent market disruptions involving the COVID-19 pandemic have negatively
impacted our earnings and cash flows from operations and may continue to do so.
Reduced demand for natural gas, NGLs, refined products and/or crude oil caused
by the COVID-19 pandemic and a continuation of low WTI crude oil prices may
result in the continued shut-in of production from U.S. oil and gas wells, which
in turn may result in decreased volumes transported on our pipeline systems and
decreased overall utilization of our midstream services.
With respect to commodity prices, natural gas prices have strengthened in recent
months as a reduction in crude oil production has led to decreased supplies of
associated natural gas from these wells. Natural gas fundamentals point to an
undersupplied market over the upcoming winter with demand outpacing supply in
the near term. Meanwhile, crude oil prices saw a sharp decline as a result of
actions by foreign oil-producing nations and a decrease in global demand as
result of the COVID-19 pandemic but have subsequently risen and stabilized. We
cannot predict the future impacts, or the duration of such impacts, from the
COVID-19 pandemic.
The outlook for commodity prices is mixed and could have a varying impact on our
business. Reduced demand and increased supply of crude oil has resulted in an
increase in worldwide crude oil storage inventories, which is expected to keep
crude oil prices depressed for the near term. With respect to natural gas
markets, a relatively more moderate decrease in demand, coupled with the
previously mentioned decreases in gas production associated with wells drilled
to produce crude oil, have more than counterbalanced the reduction in demand.
The overall outlook for our midstream services will depend, in part, on the
timing and extent of recovery in the commodity markets.
While we anticipate that current and projected commodity prices and the related
impact to activity levels in both the upstream and midstream sectors will impact
our business, we cannot predict the ultimate magnitude of that impact and expect
it to be varied across our operations, depending on the region, customer, type
of service, contract term and other factors.
While the vast majority of our counterparties are investment grade rated
companies, some of our counterparties may be forced to file for bankruptcy
protection, in which case our existing contracts with those counterparties may
be rejected by the bankruptcy court, in which case we may pursue legal action to
prevent such a rejection. For example, following the request of one of our
FERC-regulated natural pipelines, the FERC commenced an investigation into
whether the public interest requires abrogation or modification of a firm
transportation agreement and an interruptible transportation agreement with one
of our shippers. We anticipate FERC will issue a final ruling in the proceeding
in mid-November 2020; however, actual determination regarding the contract will
depend upon further action by the counterparty and any further
bankruptcy-related proceedings. If a counterparty is successful in rejecting an
existing contract in bankruptcy, we expect that we would attempt to negotiate
replacement contracts with those counterparties and, depending on the
availability of alternatives to our services, these contracts may have terms
that are less favorable to us than the contracts rejected in bankruptcy court.
Ultimately, the extent to which our business will be impacted by recent market
developments depends on the factors described above as well as future
developments beyond our control, which are highly uncertain and cannot be
predicted. In response to these market events and uncertainties, we have cut our
already reduced 2020 growth capital spending budget by a total of $700 million
and reduced planned operating expenses by approximately $500 million. While
current market volatility makes the near-term unpredictable, we believe that
overall the long-term demand for our services will continue given the essential
nature of the midstream natural gas, NGLs, refined products and crude oil
businesses, although we cannot predict any possible changes in such demand with
reasonable certainty.
We currently have ample liquidity to fund our business and we do not anticipate
any liquidity concerns in the immediate future (see "Liquidity and Capital
Resources" below). In addition, while the trading price of ET common units
declined significantly during the first nine months of 2020, thereby making
equity capital market transactions less attractive in the near term, we continue
to have access to the debt capital markets on generally favorable terms. In the
event we seek additional equity or debt capital, our blended cost of capital for
equity and debt is expected to be modestly higher in the near term; however, we
will continue to evaluate growth projects and acquisitions as such opportunities
may be identified in the future in light of this higher cost of capital.
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
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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 last-in,
first-out ("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.
As discussed in Note 1 of the Partnership's consolidated financial statements
included in "Item 1. Financial Statements," during the first quarter of 2020,
the Partnership elected to change its inventory accounting policy related to
certain barrels of crude oil that were previously accounted for as inventory.
These changes have been applied retrospectively to all prior periods, and the
prior period amounts reflected below have been adjusted from those amounts
previously reported.
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Consolidated Results
                                          Three Months Ended                                        Nine Months Ended
                                             September 30,                                            September 30,
                                         2020               2019*            Change               2020               2019*            Change
Segment Adjusted EBITDA:
Intrastate transportation and
storage                            $     203              $   235          $    (32)         $     630             $   777          $   (147)
Interstate transportation and
storage                                  425                  442               (17)             1,232               1,358              (126)
Midstream                                530                  411               119              1,280               1,205                75
NGL and refined products
transportation and services              762                  667                95              2,099               1,923               176
Crude oil transportation and
services                                 631                  726               (95)             1,741               2,222              (481)
Investment in Sunoco LP                  189                  192                (3)               580                 497                83
Investment in USAC                       104                  104                 -                315                 310                 5
All other                                 22                   35               (13)                62                  80               (18)
Adjusted EBITDA (consolidated)         2,866                2,812                54              7,939               8,372              (433)
Depreciation, depletion and
amortization                            (912)                (784)             (128)            (2,715)             (2,343)             (372)
Interest expense, net of interest
capitalized                             (569)                (579)               10             (1,750)             (1,747)               (3)
Impairment losses                     (1,474)                 (12)           (1,462)            (2,803)                (62)           (2,741)
Gains (losses) on interest rate
derivatives                               55                 (175)              230               (277)               (371)               94
Non-cash compensation expense            (30)                 (27)               (3)               (93)                (85)               (8)
Unrealized gains (losses) on
commodity risk management
activities                               (30)                  64               (94)               (27)                 90              (117)
Losses on extinguishments of debt          -                    -                 -                (62)                (18)              (44)
Inventory valuation adjustments
(Sunoco LP)                               11                  (26)               37               (126)                 71              (197)
Adjusted EBITDA related to
unconsolidated affiliates               (169)                (161)               (8)              (480)               (470)              (10)
Equity in earnings (loss) of
unconsolidated affiliates                (32)                  82              (114)                46                 224              (178)
Impairment of investment in an
unconsolidated affiliate                (129)                   -              (129)              (129)                  -              (129)
Other, net                                53                   47                 6                (48)                 67              (115)
Income (loss) before income tax
expense                                 (360)               1,241            (1,601)              (525)              3,728            (4,253)
Income tax expense                       (41)                 (54)               13               (168)               (214)               46

Net income (loss)                  $    (401)             $ 1,187          $ (1,588)         $    (693)            $ 3,514          $ (4,207)


*As adjusted.
Adjusted EBITDA (consolidated). For the three months ended September 30, 2020
compared to the same period last year, Adjusted EBITDA increased 2% due to the
net effects of multiple drivers within several of the Partnership's segments.
Among these impacts, the most significant were an increase of $104 million
related to the restructuring and assignment of certain gathering and processing
contracts in our midstream segment and an increase of $88 million in marketing
margin in our NGL and refined products transportation and services segment
primarily driven by higher optimization gains from the sale of NGL component
products. The increase in Adjusted EBITDA also reflected a net increase of
approximately $150 million from recent acquisitions and assets placed in
service. These increases in Adjusted EBITDA were partially offset by multiple
other changes, the most significant of which were the impacts of lower volumes
and market prices among several of our core operating segments resulting
primarily from COVID-19 related demand reductions.
For the nine months ended September 30, 2020 compared to the same period last
year, Adjusted EBITDA decreased 5%, primarily due to the impacts of lower
volumes and market prices among several of our core operating segments resulting
primarily from COVID-19 related demand reductions. These decreases were
partially offset by an increase of $156 million
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from our NGL and refined products transportation and services segment primarily
due to higher throughput volumes, an increase of $79 million from our midstream
segment primarily due to the contract restructuring discussed above, and an
increase of $83 million from our investment in Sunoco LP segment primarily due
to increased gross profit per gallon sold. The increase in Adjusted EBITDA also
reflected a net increase of approximately $440 million from recent acquisitions
and assets placed in service.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization increased for the three and nine months ended September 30, 2020
compared to the same periods last year due to the acquisition of SemGroup on
December 5, 2019, as well as incremental depreciation related to assets recently
placed in service.
Interest Expense, Net of Interest Capitalized. Interest expense, net of interest
capitalized, decreased for the three months ended September 30, 2020 compared to
the same period last year primarily due to the following:
•a decrease of $7 million recognized by the Partnership due to lower borrowing
costs on both recently refinanced and floating rate debt, and higher capitalized
interest;
•a decrease of $1 million for USAC for the three months ended September 30, 2020
compared to the same period last year was primarily attributable to lower
weighted average interest rates under its credit agreement, offset by increased
borrowings under its credit agreement; and
•a decrease of $2 million for Sunoco LP for the three months ended September 30,
2020 compared to the same period last year primarily related to a slight
decrease in average total long-term debt.
Interest expense, net of interest capitalized increased for the nine months
ended September 30, 2020 compared to the same periods last year primarily due to
the following:
•interest expenses recognized by the Partnership was unchanged due to lower
borrowing costs on both recently refinanced and floating rate debt, and higher
capitalized interest offsetting a higher consolidated debt balance;
•an increase of of $2 million for USAC for the nine months ended September 30,
2020 compared to the nine months ended September 30, 2019 was primarily
attributable to a full nine months of interest expense incurred in the current
period on its senior notes issued March 2019, partially offset by reduced
borrowings and lower weighted average interest rates under the credit agreement;
and
•an increase of $1 million for Sunoco LP for the nine months ended September 30,
2020 compared to the same period last year primarily related to a slight
increase in average total long-term debt.
Impairment Losses. During the three months ended March 31, 2020, the Partnership
performed an interim impairment test on certain reporting units within its
midstream, interstate, crude, NGL and all other operations. As a result of the
interim impairment test, the Partnership recognized a goodwill impairment of
$483 million related to our Arklatex and South Texas operations within the
midstream segment, a goodwill impairment of $183 million related to our Lake
Charles LNG regasification operations with the interstate transportation and
storage segment, and a goodwill impairment of $40 million related to our all
other operations primarily due to decreases in projected future revenues and
cash flows as a result of the overall market demand decline. During the three
months ended September 30, 2020, the Partnership performed interim impairment
testing on certain reporting units within its midstream, interstate, crude, NGL
and all other operations. As a result, the Partnership recognized an impairment
of $1.28 billion related to our crude operations, a goodwill impairment of $132
million related to our SemCAMS operations, a goodwill impairment of $43 million
and a fixed asset impairment of $19 million related to our interstate operations
primarily due to decreases in projected future cash flow as a result of the
overall market demand decline. In addition, USAC recognized a goodwill
impairment of $619 million, during the three months ended March 31, 2020, which
is included in the Partnership's consolidated results of operations. During the
three months ended March 31, 2019, USAC recorded a $3 million impairment of
compression equipment as a result of its evaluations of the future deployment of
USAC's idle fleet under then-current market conditions. USAC recorded $4 million
and $2 million impairment of compression equipment during the three months ended
June 30, 2020 and September 30, 2020, respectively, as a result of its
evaluations of the future deployment of its idle fleet under current market
conditions.
Gains (Losses) on Interest Rate Derivatives. Gains and losses on interest rate
derivatives during the three and nine months ended September 30, 2020 resulted
from changes in forward interest rates, which caused our forward-starting swaps
to change in value.
Unrealized Gains (Losses) on Commodity Risk Management Activities. See
additional information on the unrealized gains (losses) on commodity risk
management activities included in "Segment Operating Results" below.
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Losses on Extinguishments of Debt. During the three and nine months ended
September 30, 2020, amounts were related to ETO senior notes redemption in
January 2020.
Inventory Valuation Adjustments. Inventory valuation adjustments were recorded
for the inventory associated with Sunoco LP due to changes in fuel prices
between periods.
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 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 acquisition and related purchase price
allocation in December 2019.
Other, net. Other, net primarily includes the amortization of regulatory assets
and other income and expense amounts.
Income Tax Expense. For the three months ended September 30, 2020 compared to
the same period in the prior year, income tax expense decreased due to lower
earnings at our corporate subsidiaries in the current period. For the nine
months ended September 30, 2020 compared to the same period in the prior year,
income tax expense decreased due to the recognition of a taxable gain on the
sale of assets and higher earnings at our corporate subsidiaries in the prior
period.
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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,
                                      2020               2019            Change             2020              2019            Change
Equity in earnings (losses) of
unconsolidated affiliates:
Citrus                            $       50          $    44          $     6          $     127          $   115          $    12
FEP                                     (106)              15             (121)              (158)              43             (201)
MEP                                       (1)               1               (2)                (3)              15              (18)
White Cliffs                               2                -                2                 19                -               19
Other                                     23               22                1                 61               51               10

Total equity in earnings (losses) of unconsolidated affiliates $ (32) $ 82 $ (114) $ 46 $ 224 $ (178)



Adjusted EBITDA related to
unconsolidated affiliates(1):
Citrus                            $       96          $    92          $     4          $     264          $   260          $     4
FEP                                       19               19                -                 57               56                1
MEP                                        8               13               (5)                23               52              (29)
White Cliffs                              11                -               11                 38                -               38
Other                                     35               37               (2)                98              102               (4)
Total Adjusted EBITDA related to
unconsolidated affiliates         $      169          $   161          $

8 $ 480 $ 470 $ 10



Distributions received from
unconsolidated affiliates:
Citrus                            $       48          $    54          $    (6)         $     155          $   128          $    27
FEP                                       20               20                -                 55               53                2
MEP                                        4                7               (3)                22               33              (11)
White Cliffs                               2                -                2                 25                -               25
Other                                     24               22                2                 63               80              (17)

Total distributions received from unconsolidated affiliates $ 98 $ 103 $ (5) $ 320 $ 294 $ 26




(1)These amounts represent our proportionate share of the Adjusted EBITDA of our
unconsolidated affiliates and are based on our equity in earnings or losses of
our unconsolidated affiliates adjusted for our proportionate share of the
unconsolidated affiliates' interest, depreciation, depletion, amortization,
non-cash items and taxes.
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we
believe is an important performance measure of the core profitability of our
operations. This measure represents the basis of our internal financial
reporting and is one of the performance measures used by senior management in
deciding how to allocate capital resources among business segments.
The tables below identify the components of Segment Adjusted EBITDA, which is
calculated as follows:
•Segment margin, operating expenses, and selling, general and administrative
expenses. These amounts represent the amounts included in our consolidated
financial statements that are attributable to each segment.
•Unrealized gains or losses on commodity risk management activities and
inventory valuation adjustments. These are the unrealized amounts that are
included in cost of products sold to calculate segment margin. These amounts are
not included
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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.
Intrastate Transportation and Storage
                                      Three Months Ended                                      Nine Months Ended
                                         September 30,                                          September 30,
                                    2020               2019             Change              2020               2019            Change
Natural gas transported
(BBtu/d)                            12,185            12,560              (375)             12,745           12,221               524
Withdrawals from (injections
to) storage natural gas
inventory (BBtu)                    10,315                 -            10,315              15,380                -            15,380
Revenues                        $      654          $    764          $   (110)         $    1,763          $ 2,385          $   (622)
Cost of products sold                  434               501               (67)                985            1,473              (488)
Segment margin                         220               263               (43)                778              912              (134)
Unrealized (gains) losses on
commodity risk management
activities                              23                19                 4                 (16)               3               (19)
Operating expenses, excluding
non-cash compensation expense          (42)              (48)                6                (131)            (137)                6
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                 (7)               (7)                -                 (22)             (20)               (2)
Adjusted EBITDA related to
unconsolidated affiliates                7                 7                 -                  19               18                 1
Other                                    2                 1                 1                   2                1                 1
Segment Adjusted EBITDA         $      203          $    235          $    (32)         $      630          $   777          $   (147)


Volumes. For the three months ended September 30, 2020 compared to the same
period last year, transported volumes decreased primarily due to the bankruptcy
filing of a transportation customer. For the nine months ended September 30,
2020 compared to the same period last year, transported volumes increased
primarily due to increased utilization of our Texas pipelines, partially offset
by the bankruptcy filing of a transportation customer.
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Table of Contents Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:


                                       Three Months Ended                                     Nine Months Ended
                                         September 30,                                          September 30,
                                     2020               2019            Change              2020              2019            Change
Transportation fees              $      151          $   150          $      1          $     460          $   452          $     8
Natural gas sales and other
(excluding unrealized gains and
losses)                                  75              112               (37)               231              405             (174)
Retained fuel revenues
(excluding unrealized gains and
losses)                                  12               14                (2)                31               37               (6)
Storage margin (excluding
unrealized gains and losses and
fair value inventory
adjustments)                              5                6                (1)                40               21               19
Unrealized gains (losses) on
commodity risk management
activities and fair value
inventory adjustments                   (23)             (19)               (4)                16               (3)              19
Total segment margin             $      220          $   263          $    (43)         $     778          $   912          $  (134)


Segment Adjusted EBITDA. For the three months ended September 30, 2020 compared
to the same period last year, Segment Adjusted EBITDA related to our intrastate
transportation segment decreased due to the net impacts of the following:
•a decrease of $37 million in realized natural gas sales and other primarily due
to lower realized gains from pipeline optimization activity;
•a decrease of $2 million in retained fuel revenues primarily due to lower gas
prices; and
•a decrease of $1 million in realized storage margin due to lower realized gains
from financial derivatives used to hedge physical storage gas; partially offset
by
•a decrease of $6 million in operating expenses primarily due to $2 million
decrease in employee costs, a $2 million decrease in maintenance project costs
and a $1 million decrease in outside services.
Segment Adjusted EBITDA. For the nine months ended September 30, 2020 compared
to the same period last year, Segment Adjusted EBITDA related to our intrastate
transportation segment decreased due to the net impacts of the following:
•a decrease of $174 million in realized natural gas sales and other primarily
due to lower realized gains from pipeline optimization activity;
•a decrease of $6 million in retained fuel revenues primarily due to lower gas
prices; and
•an increase of $2 million in selling, general and administrative expenses
primarily due to higher allocated corporate costs; partially offset by
•an increase of $19 million in realized storage margin primarily due to higher
realized gains on financial hedges used to hedge physical storage gas;
•an increase of $8 million in transportation fees primarily due to volume
ramp-ups on the Red Bluff Express pipeline and new contracts, partially offset
by the expiration of certain contracts on Regency Intrastate Gas System;
•a decrease of $6 million in operating expenses primarily due to a decrease of
$4 million in employee costs and a decrease of $4 million in outside services,
partially offset by an increase of $1 million in allocated costs and an increase
of $1 million in utilities; and
•an increase of $1 million in Adjusted EBITDA related to unconsolidated
affiliates primarily due to higher fee revenue on the Trans-Pecos and Comanche
Trail pipelines.

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Interstate Transportation and Storage
                                       Three Months Ended                                       Nine Months Ended
                                          September 30,                                           September 30,
                                     2020               2019              Change              2020               2019            Change
Natural gas transported (BBtu/d)     10,387            11,407             (1,020)             10,422           11,254             (832)
Natural gas sold (BBtu/d)                15                17                 (2)                 16               18               (2)
Revenues                         $      471          $    479          $      (8)         $    1,380          $ 1,470          $   (90)

Operating expenses, excluding
non-cash compensation,
amortization and accretion
expenses                               (147)             (141)                (6)               (429)            (425)              (4)
Selling, general and
administrative expenses,
excluding non-cash compensation,
amortization and accretion
expenses                                (20)              (17)                (3)                (57)             (49)              (8)
Adjusted EBITDA related to
unconsolidated affiliates               122               124                 (2)                343              368              (25)
Other                                    (1)               (3)                 2                  (5)              (6)               1
Segment Adjusted EBITDA          $      425          $    442          $     (17)         $    1,232          $ 1,358          $  (126)


Volumes. For the three and nine months ended September 30, 2020 compared to the
same periods last year, transported volumes decreased primarily due to lower
crude production resulting in lower associated gas production and a decrease in
demand for LNG export.
Segment Adjusted EBITDA. For the three months ended September 30, 2020 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 $8 million in revenues primarily due to a decrease of $16 million
due to a contractual rate adjustment on commitments at our Lake Charles LNG
facility effective January 2020 and a decrease of $9 million due to less
capacity sold on our Panhandle and Trunkline systems. These decreases were
partially offset by increased margin from short-term firm contracts on our
Transwestern and Rover systems due to increased demand and higher parking due to
the timing of transactions;
•an increase of $6 million in operating expense primarily due to an increase in
bad debt reserves and higher ad valorem taxes, partially offset by the impact of
cost cutting initiatives;
•an increase of $3 million in selling, general and administrative expenses
primarily resulting from legal and consulting fees related to an ongoing rate
case and a shipper bankruptcy; and
•a decrease of $2 million in Adjusted EBITDA related to unconsolidated
affiliates primarily due to lower earnings of $6 million from our Midcontinent
Express Pipeline primarily as a result of lower rates received following the
expiration of certain contracts, partially offset by a $4 million increase from
Citrus primarily due to higher margins and lower operating expenses.
Segment Adjusted EBITDA. For the nine months ended September 30, 2020 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 $90 million in revenues primarily due to a decrease of $48
million due to a contractual rate adjustment on commitments at our Lake Charles
LNG facility effective January 2020, a decrease of $30 million due to a shipper
bankruptcy in 2019, a decrease of $28 million due to lower demand and lower
rates on our Panhandle and Trunkline systems, and a decrease of $5 million from
lower interruptible transportation resulting from lower customer demand and
lower liquids as a result of multiple weather events and-third party maintenance
on our Sea Robin and Trunkline systems. These decreases were partially offset by
increased margins from higher reservation revenue on Transwestern, Tiger and
Rover resulting from higher contracted capacity and an increase in parking
revenue on Panhandle and Trunkline;
•an increase of $4 million in operating expenses primarily due to an increase in
bad debt reserves and a decrease in the valuation of inventory on Panhandle in
2020, partially offset by lower employee costs and project expense resulting
from cost cutting initiatives and lower ad valorem taxes due in part to appeals
made to various taxing authorities;
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•an increase of $8 million in selling, general and administrative expenses
primarily resulting from higher allocated overhead costs, an increase in
insurance premiums and higher legal and consulting fees related to an ongoing
rate case and a shipper bankruptcy, partially offset by lower management
incentive compensation; and
•a decrease of $25 million in Adjusted EBITDA related to unconsolidated
affiliates primarily due to lower earnings from our Midcontinent Express
Pipeline primarily as a result of lower rates received following the expiration
of certain contracts, partially offset by a $4 million increase from Citrus
primarily due to higher margins resulting from new contracts, rate increases on
existing contracts and the recognition of a contract exit fee.
Midstream
                                       Three Months Ended                                        Nine Months Ended
                                          September 30,                                            September 30,
                                      2020                2019             Change              2020               2019            Change
Gathered volumes (BBtu/d)           12,904              13,955             (1,051)             13,071           13,278             (207)
NGLs produced (MBbls/d)                635                 574                 61                 616              567               49
Equity NGLs (MBbls/d)                   32                  30                  2                  35               32                3
Revenues                        $    1,377             $ 1,580          $    (203)         $    3,565          $ 4,496          $  (931)
Cost of products sold                  668                 953               (285)              1,716            2,678             (962)
Segment margin                         709                 627                 82               1,849            1,818               31

Operating expenses, excluding
non-cash compensation expense         (169)               (202)                33                (528)            (574)              46
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                (21)                (21)                 -                 (67)             (63)              (4)
Adjusted EBITDA related to
unconsolidated affiliates                9                   6                  3                  23               21                2
Other                                    2                   1                  1                   3                3                -
Segment Adjusted EBITDA         $      530             $   411          $     119          $    1,280          $ 1,205          $    75


Volumes. Gathered volumes decreased during the three months ended September 30,
2020 compared to the same period last year primarily due to decreases in the
South Texas and Northeast Texas regions, partially offset by the impact of the
SemGroup acquisition in the Mid-Continent/Panhandle region and volume growth in
the Permian region. NGL production increased due to the impact of the SemGroup
acquisition in the Mid-Continent/Panhandle region and increased ethane recovery
in the Permian, South Texas and North Texas regions.
Gathered volumes decreased during the nine months ended September 30, 2020
compared to the same period last year primarily due to decreases in the South
Texas region, partially offset by the impact of the SemGroup acquisition in the
Mid-Continent/Panhandle region and volume growth in the Permian region. NGL
production increased due to the impact of the SemGroup acquisition in the
Mid-Continent/Panhandle region and increased ethane recovery in the Permian,
South Texas and North Texas regions.
Segment Margin. The table below presents the components of our midstream segment
margin. For the prior period included in the table below, the amounts previously
reported for fee-based and non-fee-based margin have been adjusted to reflect
reclassification of certain contractual minimum fees in order to conform to the
current period classification:
                                      Three Months Ended                                     Nine Months Ended
                                        September 30,                                          September 30,
                                    2020               2019            Change              2020               2019            Change
Gathering and processing
fee-based revenues              $      642          $   550          $     92          $    1,675          $ 1,584          $     91
Non-fee-based contracts and
processing                              67               77               (10)                174              234               (60)

Total segment margin            $      709          $   627          $     82          $    1,849          $ 1,818          $     31


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Segment Adjusted EBITDA. For the three months ended September 30, 2020 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 $92 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, which included the recognition of
$75 million of deferred revenue received in prior periods;
•a decrease of $33 million in operating expenses due to decreases of $17 million
in outside services, $10 million in employee costs and $9 million in materials;
and
•an increase of $2 million in non fee-based margin due to unfavorable NGL prices
of $5 million and favorable gas prices of $7 million; partially offset by
•a decrease of $12 million in non fee-based margin due to decreased throughput
volumes, primarily in the South Texas region.
Segment Adjusted EBITDA. For the nine months ended September 30, 2020 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 $91 million in fee-based margin due to volume growth in the
Mid-Continent/Panhandle region and the recognition of $103 million related to
the restructuring and assignment of certain gathering and processing contracts
in the Ark-La-Tex region, which included the recognition of $75 million of
deferred revenue received in prior periods; and
•a decrease of $46 million in operating expenses due to decreases of $28 million
in outside services, $14 million in employee costs and $12 million in materials,
partially offset by an increase of $9 million in maintenance project costs;
partially offset by
•a decrease of $59 million in non-fee-based margin due to unfavorable NGL prices
of $61 million and favorable gas prices of $2 million;
•a decrease of $1 million in non-fee-based margin due to decreased throughput
volumes, primarily in the South Texas region; and
•an increase of $4 million in selling, general and administrative expenses due
to an increase of $3 million in insurance and an increase of $1 million in legal
fees.
NGL and Refined Products Transportation and Services
                                          Three Months Ended                                      Nine Months Ended
                                             September 30,                                          September 30,
                                         2020                2019            Change             2020               2019            Change
NGL transportation volumes
(MBbls/d)                               1,493               1,358              135               1,431            1,280               151
Refined products transportation
volumes (MBbls/d)                         460                 552              (92)                460              599              (139)
NGL and refined products terminal
volumes (MBbls/d)                         850                 872              (22)                813              845               (32)
NGL fractionation volumes
(MBbls/d)                                 877                 713              164                 839              697               142
Revenues                           $    2,623             $ 2,878          $  (255)         $    7,457          $ 8,521          $ (1,064)
Cost of products sold                   1,712               1,962             (250)              4,916            6,136            (1,220)
Segment margin                            911                 916               (5)              2,541            2,385               156
Unrealized (gains) losses on
commodity risk management
activities                                 11                 (81)              92                  34               15                19
Operating expenses, excluding
non-cash compensation expense            (162)               (167)               5                (475)            (471)               (4)
Selling, general and
administrative expenses, excluding
non-cash compensation expense             (20)                (22)               2                 (64)             (67)                3
Adjusted EBITDA related to
unconsolidated affiliates                  22                  24               (2)                 63               63                 -
Other                                       -                  (3)               3                   -               (2)                2
Segment Adjusted EBITDA            $      762             $   667          $    95          $    2,099          $ 1,923          $    176


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Volumes. For the three and nine months ended September 30, 2020 compared to the
same periods last year, NGL transportation volumes increased due to higher
throughput volumes on our Mariner East pipeline system. In addition, throughput
barrels on our Texas NGL pipeline system increased due to higher receipt of
liquids production from both wholly-owned and third-party gas plants primarily
in the Permian and North Texas regions.
Refined products transportation volumes decreased for the three and nine months
ended September 30, 2020 compared to the same periods last year due to the
closure of a third-party refinery during the third quarter of 2019, which
negatively impacted supply to our refined products transportation system, and
less domestic demand for jet fuel and other refined products. These decreases in
volumes were partially offset by the initiation of service of our JC Nolan
diesel fuel pipeline in the third quarter of 2019.
NGL and refined products terminal volumes decreased for the three and nine
months ended September 30, 2020 compared to the same periods last year primarily
due to the closure of a third-party refinery during the third quarter of 2019,
and less domestic demand for jet fuel and other refined products. These
decreases were partially offset by higher volumes from our Mariner East system,
and the initiation of service on our JC Nolan diesel fuel pipeline and natural
gasoline export project, both of which commenced service in the third quarter of
2019.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility
increased for the three and nine months ended September 30, 2020 compared to the
same periods last year primarily due to the commissioning of our seventh
fractionator in February 2020.
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,
                                       2020               2019            Change              2020               2019            Change
Transportation margin              $      494          $   474          $     20          $    1,419          $ 1,259          $    160
Fractionators and refinery
services margin                           189              171                18                 541              491                50
Terminal services margin                  130              175               (45)                410              478               (68)
Storage margin                             63               57                 6                 181              166                15
Marketing margin                           46              (42)               88                  24                6                18
Unrealized gains (losses) on
commodity risk management
activities                                (11)              81               (92)                (34)             (15)              (19)
Total segment margin               $      911          $   916          $     (5)         $    2,541          $ 2,385          $    156


Segment Adjusted EBITDA. For the three months ended September 30, 2020 compared
to the same period last year, Segment Adjusted EBITDA related to our NGL and
refined products transportation and services segment increased due to the net
impacts of the following:
•an increase of $88 million in marketing margin primarily due to a $66 million
increase driven by higher optimization gains from the sale of NGL component
products at our Mont Belvieu facility, a $12 million increase from capacity
lease fees incurred by our marketing affiliate on our Mariner East pipeline
system, and a $10 million increase in gasoline blending and optimization;
•an increase of $20 million in transportation margin primarily due to a $13
million increase from higher throughput volumes on our Mariner East pipeline
system, a $9 million increase from higher throughput volumes received from the
Permian region on our Texas NGL pipelines, a $4 million increase due to the
initiation of service on our JC Nolan diesel fuel pipeline in the third quarter
of 2019, and a $3 million increase due to higher throughput volumes from the
Barnett region. These increases were partially offset by a $3 million decrease
resulting from the recognition of third party deferred revenue on our export
pipeline in the third quarter of 2019, a $2 million decrease due to less
domestic demand for jet fuel and other refined products, and a $2 million
decrease resulting from the closure of a third-party refinery during the third
quarter of 2019;
•an increase of $18 million in fractionators and refinery services margin
primarily due to the commissioning of our seventh fractionator in February 2020
and higher NGL volumes from the Permian and Barnett regions feeding our Mont
Belvieu fractionation facility;
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•a decrease of $5 million in operating expenses primarily due to a $9 million
decrease in power costs, partially offset by increases totaling $4 million for
costs associated with operating additional assets; and
•an increase of $6 million in storage margin primarily due to a $4 million
increase primarily from a new intra-segment storage contract effective June 2020
and a $2 million increase in throughput fees generated primarily from exported
volumes; partially offset by
•a decrease of $45 million in terminal services margin primarily due to a $40
million decrease resulting from the expiration of a third party contract at our
Nederland export facility in the second quarter of 2020, a $6 million decrease
due to lower storage fees at our Marcus Hook Industrial Complex due to the
closure of a third-party refinery during the third quarter of 2019, a $3 million
decrease due to less domestic demand for jet fuel and other refined products,
and a $2 million decrease due to the closure of a third-party refinery. These
decreases were partially offset by an $11 million increase due to higher
throughput on our Mariner East system.
Segment Adjusted EBITDA. For the nine months ended September 30, 2020 compared
to the same period last year, Segment Adjusted EBITDA related to our NGL and
refined products transportation and services segment increased due to the net
impacts of the following:
•an increase of $160 million in transportation margin primarily due to a $116
million increase from higher throughput volumes on our Mariner East pipeline
system, a $55 million increase resulting from higher throughput volumes received
from the Permian region on our Texas NGL pipelines, a $18 million increase due
to the initiation of service of our JC Nolan diesel fuel pipeline in the third
quarter of 2019, and a $13 million increase due to higher throughput volumes
from the Barnett region. These increases were partially offset by a $13 million
decrease resulting from the closure of a third-party refinery during the third
quarter of 2019, a $13 million decrease due to less domestic demand for jet fuel
and other refined products, a $12 million decrease due to the reclassification
of certain items, and a $3 million decrease resulting from the recognition of
third-party deferred revenue on our export pipeline in the third quarter of
2019;
•an increase of $50 million in fractionators and refinery services margin
primarily due to a $47 million increase resulting from the commissioning of our
sixth and seventh fractionators in February 2019 and February 2020,
respectively, and higher NGL volumes from the Permian and Barnett regions
feeding our Mont Belvieu fractionation facility, a $6 million increase due to a
reclassification between our transportation and fractionators margins in the
third quarter of 2019, and a $5 million increase in truck and rail volumes
feeding our refinery services facility. These increases were partially offset by
a $5 million decrease due primarily to an expiration of a third-party blending
contract during the second quarter of 2020;
•an increase of $18 million in marketing margin primarily due to higher
optimization gains from the sale of NGL component products at our Mont Belvieu
facility and a $12 million increase in gasoline blending and optimization. These
increases were partially offset by a $47 million decrease due to lower margin
from our butane blending business, an $18 million decrease in capacity lease
fees incurred by our marketing affiliate on our Mariner East pipeline system, a
$15 million decrease due to unfavorable hedge adjustments, and an $8 million
decrease in NGL export and rack volumes; and
•an increase of $15 million in storage margin primarily due to a $10 million
increase in throughput fees generated primarily from exported volumes and a $6
million increase resulting primarily from a new intra-segment storage contract
effective June 2020; partially offset by
•a decrease of $68 million in terminal services margin primarily due to a $64
million decrease resulting from an expiration of a third-party contract at our
Nederland export facility in the second quarter of 2020, a $26 million decrease
due to lower storage fees at our Marcus Hook Industrial Complex and lower
refined product transport volumes due to the closure of a third-party refinery
during the third quarter of 2019, an $11 million decrease due to lower NGL
volumes received into our Marcus Hook Industrial complex from third party
pipelines, a $10 million decrease due to less domestic demand for jet fuel and
other refined products, and a $7 million decrease due to lower expense
reimbursements in 2020. These decreases were partially offset by a $46 million
increase due to higher throughput on our Mariner East system and a $4 million
increase resulting from initiation of service of our natural gasoline export in
the third quarter of 2019.
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Crude Oil Transportation and Services
                                         Three Months Ended                                       Nine Months Ended
                                            September 30,                                           September 30,
                                        2020                2019            Change              2020              2019             Change
Crude transportation volumes
(MBbls/d)                              3,587               4,223              (636)             3,880             4,180              (300)
Crude terminals volumes (MBbls/d)      2,276               2,322               (46)             2,662             2,575                87
Revenues                          $    2,850             $ 4,453          $ (1,603)         $   8,877          $ 13,685          $ (4,808)
Cost of products sold                  2,096               3,594            (1,498)             6,704            10,892            (4,188)
Segment margin                           754                 859              (105)             2,173             2,793              (620)
Unrealized (gains) losses on
commodity risk management
activities                                (1)                 (2)                1                  9              (100)              109
Operating expenses, excluding
non-cash compensation expense           (112)               (110)               (2)              (401)             (410)                9
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                  (28)                (21)               (7)               (82)              (61)              (21)
Adjusted EBITDA related to
unconsolidated affiliates                  9                   1                 8                 32                 -                32
Other                                      9                  (1)               10                 10                 -                10
Segment Adjusted EBITDA           $      631             $   726          $    (95)         $   1,741          $  2,222          $   (481)


Volumes. For the three months ended September 30, 2020 compared to the same
period last year, crude transportation volumes were lower on our Texas pipeline
system and our Bakken pipeline, primarily driven by lower production in these
regions and refinery utilization due to COVID-19 related demand decreases,
partly offset by contributions from assets acquired in 2019. Crude terminal
volumes were lower primarily due to lower pipeline volumes, refinery
utilization, and impacts from weather events in the third quarter of 2020,
partially offset by contributions from assets acquired in 2019.
For the nine months ended September 30, 2020 compared to the same period last
year, crude transportation volumes were lower on our Texas pipeline system and
our Bakken pipeline, primarily driven by lower production in these regions and
lower refinery utilization due to COVID-19 related demand decreases, partially
offset by contributions from assets acquired in 2019. Terminal volumes were
higher due to contributions from assets acquired in 2019, partially offset by
lower pipeline volumes, refinery utilization, and impacts from weather events in
the third quarter of 2020.
Segment Adjusted EBITDA. For the three months ended September 30, 2020 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 $104 million in segment margin (excluding unrealized gains and
losses on commodity risk management activities) primarily due to a $113 million
decrease from our Texas crude pipeline system due to lower utilization and lower
average tariff rates realized, an $84 million decrease due to lower volumes on
our Bakken Pipeline from lower basin production, and a $7 million decrease in
throughput at our crude terminals primarily driven by lower Permian and Bakken
pipeline volumes, reduced refinery utilization, and weather events in the third
quarter of 2020 impacting operations, partially offset by a $78 million increase
related to assets acquired in 2019 and a $31 million increase (excluding a net
change of $2 million in unrealized gains and losses on commodity risk management
activities) from our crude oil acquisition and marketing business primarily due
to trading gains realized from contango storage positions, as well as an
inventory valuation write-down recognized in the prior period;
•an increase of $2 million in operating expenses primarily due to increased
costs related to assets acquired in 2019, partially offset by lower
volume-driven pipeline expenses; and
•an increase of $7 million in selling, general and administrative expenses
primarily due to a $3 million increase in legal expenses, a $2 million increase
in insurance expenses, a $1 million increase in information technology expenses,
and a $1 million increase in employee costs; partially offset by
•an increase of $8 million in Adjusted EBITDA related to unconsolidated
affiliates due to assets acquired in 2019.
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Segment Adjusted EBITDA. For the nine months ended September 30, 2020 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 $511 million in segment margin (excluding unrealized gains and
losses on commodity risk management activities) primarily due to a $324 million
decrease from our Texas crude pipeline system due to lower utilization and lower
average tariff rates realized, a $237 million decrease (excluding a net change
of $109 million in unrealized gains and losses on commodity risk management
activities) from our crude oil acquisition and marketing business due primarily
to less favorable pricing conditions impacting our Permian to Gulf Coast and
Bakken to Gulf Coast trading operations, as well as inventory valuation losses
recognized in 2020, partially offset by trading gains realized from storage
positions in 2020, a $181 million decrease due to lower volumes on our Bakken
Pipeline from lower basin production, and an $18 million decrease in throughput
at our crude terminals primarily driven lower Permian and Bakken volumes, lower
refinery utilization, and weather events in the third quarter of 2020 impacting
Gulf Coast operations, partially offset by a $240 million increase related to
assets acquired in 2019 and a $6 million increase due to higher volumes on our
Bayou Bridge Pipeline;
•a decrease of $9 million in operating expenses primarily due to lower
volume-driven pipeline expenses, partially offset by increased costs related to
assets acquired in 2019; and
•an increase of $21 million in selling, general and administrative expenses
primarily due to an $8 million increase in legal expenses, a $4 million increase
related to assets acquired in 2019, a $4 million increase in insurance expenses,
a $3 million increase in allocated overhead costs, and a $1 million increase in
information technology expenses; partially offset by
•an increase of $32 million in Adjusted EBITDA related to unconsolidated
affiliates due to assets acquired in 2019.
Investment in Sunoco LP
                                       Three Months Ended                                       Nine Months Ended
                                          September 30,                                           September 30,
                                      2020                2019            Change              2020              2019             Change
Revenues                        $    2,805             $ 4,331          $ (1,526)         $   8,157          $ 12,498          $ (4,341)
Cost of products sold                2,497               4,039            (1,542)             7,383            11,567            (4,184)
Segment margin                         308                 292                16                774               931              (157)
Unrealized gains on commodity
risk management activities              (6)                 (1)               (5)                 -                (4)                4
Operating expenses, excluding
non-cash compensation expense          (84)                (94)               10               (265)             (281)               16
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                (24)                (36)               12                (76)              (91)               15
Adjusted EBITDA related to
unconsolidated affiliates                2                   1                 1                  7                 1                 6
Inventory valuation adjustments        (11)                 26               (37)               126               (71)              197
Other                                    4                   4                 -                 14                12                 2
Segment Adjusted EBITDA         $      189             $   192          $     (3)         $     580          $    497          $     83


The Investment in Sunoco LP segment reflects the consolidated results of Sunoco
LP.
Segment Adjusted EBITDA. For the three months ended September 30, 2020 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 $23 million, primarily
due to a 4% increase in gross profit per gallon sold, offset by a 12% decrease
in gallons sold; and
•a decrease of $3 million in non-motor fuel sales and lease gross margin as a
result of rent concessions during the three months ended September 30, 2020;
partially offset by
•a decrease of $22 million in operating expenses and selling, general and
administrative expenses, primarily attributable to lower employee costs,
professional fees, credit card processing fees and advertising costs; and
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•an increase of $1 million in Adjusted EBITDA related to unconsolidated
affiliates which was attributable to the JC Nolan joint venture entered into in
2019.
Segment Adjusted EBITDA. For the nine months ended September 30, 2020 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:
•an increase in the gross profit on motor fuel sales of $62 million, primarily
due to a 27% increase in gross profit per gallon sold and the receipt of a $13
million make-up payment under the fuel supply agreement with 7-Eleven, Inc.,
partially offset by a 14% decrease in gallons sold;
•a decrease of $31 million in operating expenses and selling, general and
administrative expenses, excluding non-cash compensation expense, primarily
attributable to lower employee costs, maintenance, advertising, credit card fees
and utilities, which was partially offset by a $16 million charge for current
expected credit losses on Sunoco LP's accounts receivable in connection with the
financial impact from COVID-19; and
•an increase in unconsolidated affiliate Adjusted EBITDA of $6 million, which
was attributable to the JC Nolan joint venture entered into in 2019; partially
offset by
•a decrease of $17 million in non motor fuel sales and lease gross profit
primarily due to reduced credit card transactions related to the COVID-19
pandemic and rent concessions in 2020.
Investment in USAC
                                      Three Months Ended                                     Nine Months Ended
                                        September 30,                                          September 30,
                                    2020               2019            Change              2020              2019            Change
Revenues                        $      161          $   175          $    (14)         $     509          $   520          $    (11)
Cost of products sold                   20               23                (3)                62               69                (7)
Segment margin                         141              152               (11)               447              451                (4)

Operating expenses, excluding
non-cash compensation expense          (29)             (35)                6                (94)            (102)                8
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                (11)             (13)                2                (41)             (39)               (2)

Other                                    3                -                 3                  3                -                 3
Segment Adjusted EBITDA         $      104          $   104          $      -          $     315          $   310          $      5


The Investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended September 30, 2020 Segment
Adjusted EBITDA related to our investment in USAC segment was consistent with
the same period last year primarily due to the offsetting impacts of the
following:
•a decrease of $11 million in segment margin primarily driven by a decrease in
U.S. crude oil and natural gas activity; offset by
•a decrease of $6 million in operating expenses primarily driven by a decrease
in average revenue generating horsepower and reduced headcount; and
•a decrease of $2 million in selling, general and administrative expenses
primarily due to a decrease in employee expenses.
Segment Adjusted EBITDA. For the nine months ended September 30, 2020 compared
to the same period last year, Segment Adjusted EBITDA related to our investment
in USAC segment increased due to the net impacts of the following:
•a decrease of $8 million in operating expenses primarily driven by a decrease
in average revenue generating horsepower and reduced headcount; partially offset
by
•a decrease of $4 million in segment margin primarily driven by a decrease in
revenues due to a reduction of ancillary maintenance work and a decrease in
average revenue generating horsepower, offset by a decrease in costs of products
sold of $7 million.

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All Other
                                      Three Months Ended                                     Nine Months Ended
                                        September 30,                                          September 30,
                                    2020               2019            Change              2020               2019            Change
Revenues                        $      367          $   441          $    (74)         $    1,372          $ 1,276          $     96
Cost of products sold                  318              393               (75)              1,110            1,138               (28)
Segment margin                          49               48                 1                 262              138               124
Unrealized (gains) losses on
commodity risk management
activities                               3                1                 2                   -               (4)                4
Operating expenses, excluding
non-cash compensation expense          (35)             (39)                4                (100)             (52)              (48)
Selling, general and
administrative expenses,
excluding non-cash compensation
expense                                (23)             (11)              (12)                (80)             (45)              (35)
Adjusted EBITDA related to
unconsolidated affiliates                1                -                 1                   1                1                 -
Other and eliminations                  27               36                (9)                (21)              42               (63)
Segment Adjusted EBITDA         $       22          $    35          $    (13)         $       62          $    80          $    (18)


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 were acquired in the SemGroup acquisition in
December 2019 and include natural gas gathering and processing assets.
Segment Adjusted EBITDA. For the three months ended September 30, 2020 compared
to the same period last year, Segment Adjusted EBITDA related to our all other
segment decreased due to the net impacts of the following:
•a decrease of $10 million due to lower compression market demand from our
compression equipment business;
•a decrease of $6 million due to power trading activities;
•a decrease of $11 million due to lower demand and operator production, as well
as a contract expiration at our natural resources business; and
•an increase of $10 million in merger and acquisition expense; partially offset
by
•an increase of $26 million from the acquisition of SemCAMS.
Segment Adjusted EBITDA. For the nine months ended September 30, 2020 compared
to the same period last year, Segment Adjusted EBITDA related to our all other
segment decreased due to the net impacts of the following:
•a decrease of $15 million from power trading activities;
•a decrease of $6 million due to increased power costs and increased expenses at
our compression services business;
•a decrease of $31 million due to lower compression market demand from our
compression equipment business;
•a decrease of $34 million due to higher merger and acquisition expense;
•a decrease of $19 million due to lower demand and operator production, as well
as a contract expiration at our natural resources business; and
•a decrease of $6 million due to the elimination of Sunoco LP's interest in our
JC Nolan joint venture; partially offset by
•an increase of $77 million from the acquisition of SemCAMS;
•an increase of $16 million from settlement payments received from our ownership
of PES; and
•an increase of $4 million from management fee income.
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LIQUIDITY AND CAPITAL RESOURCES
Overview
The Parent Company's principal sources of cash flow are derived from
distributions related to our investment in ETO, which derives its cash flows
from its subsidiaries, including ETO's investments in Sunoco LP and USAC.
The Parent Company's primary cash requirements are for general and
administrative expenses, debt service requirements and distributions to its
partners. The Parent Company currently expects to fund its short-term needs for
such items with cash flows from its direct and indirect investments in ETO. The
Parent Company distributes its available cash remaining after satisfaction of
the aforementioned cash requirements to its Unitholders on a quarterly basis.
The Parent Company expects ETO and its respective subsidiaries and investments
in Sunoco LP and USAC to utilize their resources, along with cash from their
operations, to fund their announced growth capital expenditures and working
capital needs; however, the Parent Company may issue debt or equity securities
from time to time, as it deems prudent to provide liquidity for new capital
projects of its subsidiaries or for other partnership purposes.
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 2020 to be within the following
ranges (excluding capital expenditures related to our investments in Sunoco LP
and USAC):
                                                                Growth                Maintenance
                                                           Low         High         Low        High
Intrastate transportation and storage                   $     5      $    15      $   40      $  45
Interstate transportation and storage (1)                    50           75         115        120
Midstream                                                   405          430         115        120
NGL and refined products transportation and services      2,425        2,525          95        105
Crude oil transportation and services (1)                   225          250         105        115
All other (including eliminations)                           75          100          50         55
Total capital expenditures                              $ 3,185      $ 3,395      $  520      $ 560


(1)Includes capital expenditures related to our proportionate ownership of the
Bakken, Rover and Bayou Bridge pipeline projects.
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 factors, 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 fund growth capital expenditures
with borrowings under credit facilities, long-term debt, the issuance of
additional preferred units or a combination thereof.
Sunoco LP currently expects to spend approximately $30 million on growth capital
and $75 million on maintenance capital for the full year 2020.
USAC currently plans to spend approximately $25 million on maintenance capital
expenditures and currently has budgeted between $90 million and $100 million in
expansion capital expenditures for the full year 2020.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of
which we cannot control. These factors include regulatory changes, the price of
our subsidiaries' 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.
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Operating Activities
Changes in cash flows from operating activities between periods primarily result
from changes in earnings (as discussed in "Results of Operations" above),
excluding the impacts of non-cash items and changes in operating assets and
liabilities (net of effects of acquisitions). 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 ETO has a significant amount of interstate pipeline
construction in progress. Changes in operating assets and liabilities between
periods result from factors such as the changes in the value of price risk
management assets and liabilities, timing of accounts receivable collection, the
timing of payments on accounts payable, the timing of purchases and sales of
inventories and the timing of advances and deposits received from customers.
Nine months ended September 30, 2020 compared to nine months ended September 30,
2019. Cash provided by operating activities during 2020 was $5.46 billion
compared to $5.97 billion for 2019, and net loss was $693 million for 2020 and
net income was $3.51 billion for 2019. The difference between net loss and net
cash provided by operating activities for the nine months ended September 30,
2020 primarily consisted of net changes in operating assets and liabilities (net
of effects of acquisitions) of $94 million and other non-cash items totaling
$5.91 billion.
The non-cash activity in 2020 and 2019 consisted primarily of depreciation,
depletion and amortization of $2.72 billion and $2.34 billion, respectively,
non-cash compensation expense of $93 million and $85 million, respectively,
inventory valuation adjustments of $126 million and $71 million, respectively,
and deferred income taxes of $159 million and $191 million, respectively.
Non-cash activity also included losses on extinguishments of debt in 2020 and
2019 of $62 million and $18 million, respectively, impairment losses of
$2.80 billion and $62 million in 2020 and 2019, respectively, and impairment of
investment in an unconsolidated affiliate of $129 million in 2020.
Unconsolidated affiliate activity consisted of equity in earnings of $46 million
and $224 million in 2020 and 2019, respectively, and cash distributions received
of $176 million and $254 million, respectively.
Cash paid for interest, net of interest capitalized, was $1.47 billion and $1.57
billion for the nine months ended September 30, 2020 and 2019, respectively.
Interest capitalized was $163 million and $145 million for the nine months ended
September 30, 2020 and 2019, 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, 2020 compared to nine months ended September 30,
2019. Cash used in investing activities during 2020 was $3.86 billion compared
to $4.42 billion for 2019. Total capital expenditures (excluding the allowance
for equity funds used during construction and net of contributions in aid of
construction costs) for 2020 were $3.97 billion compared to $4.12 billion for
2019. Additional detail related to our capital expenditures is provided in the
table below. During 2019, we received $93 million of cash proceeds from the sale
of a noncontrolling interest in a subsidiary and paid $7 million in cash for all
other acquisitions.
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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, 2020:
                                                              Capital

Expenditures Recorded During Period


                                                            Growth             Maintenance            Total
Intrastate transportation and storage                   $         -          $         42          $      42
Interstate transportation and storage                            36                    66                102
Midstream                                                       322                    82                404

NGL and refined products transportation and services 1,923

            64              1,987
Crude oil transportation and services                           164                    56                220
Investment in Sunoco LP                                          65                    15                 80
Investment in USAC                                               85                    18                103
All other (including eliminations)                               81                    25                106
Total capital expenditures                              $     2,676

$ 368 $ 3,044




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, 2020 compared to nine months ended September 30,
2019. Cash used in financing activities during 2020 was $1.61 billion compared
to $1.75 billion for 2019. During 2020 and 2019, our subsidiaries received $1.58
billion and $780 million, respectively, in net proceeds from offerings of
preferred units. During 2020, we had a net increase in our debt level of $358
million compared to a net increase of $878 million for 2019. In 2020 and 2019,
we paid debt issuance costs of $53 million and $114 million, respectively.
In 2020 and 2019, we paid distributions of $2.40 billion and $2.30 billion,
respectively, to our partners. In 2020 and 2019, we paid distributions of
$1.28 billion and $1.27 billion, respectively, to noncontrolling interests. In
addition, we received capital contributions of $203 million in cash from
noncontrolling interests in 2020 compared to $278 million in cash from
noncontrolling interests in 2019.
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Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
                                                                      September 30,           December 31,
                                                                          2020                    2019
Parent Company Indebtedness:
ET Senior Notes due October 2020                                    $            -          $          52
ET Senior Notes due March 2023                                                   5                      5
ET Senior Notes due January 2024                                                23                     23
ET Senior Notes due June 2027                                                   44                     44
Subsidiary Indebtedness:
ETO Senior Notes                                                            37,783                 36,118
Transwestern Senior Notes                                                      400                    575
Panhandle Senior Notes                                                         235                    235
Bakken Senior Notes                                                          2,500                  2,500
Sunoco LP Senior Notes and lease-related obligations                         2,905                  2,935
USAC Senior Notes                                                            1,475                  1,475
Credit facilities and commercial paper:
ETO $2.00 billion Term Loan facility due October 2022                        2,000                  2,000

ETO $5.00 billion Revolving Credit Facility due December 2023 (1)

  3,231                  4,214
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023                 87                    162
USAC $1.60 billion Revolving Credit Facility due April 2023                    497                    403
HFOTCO Tax Exempt Notes due 2050                                               225                    225
SemCAMS Revolver due February 2024                                              74                     92
SemCAMS Revolver Term Loan A due February 2024                                 253                    269
Other long-term debt                                                             3                      2
Net unamortized premiums, discounts, and fair value adjustments                (12)                     4
Deferred debt issuance costs                                                  (283)                  (279)
Total debt                                                                  51,445                 51,054
Less: current maturities of long-term debt                                      21                     26
Long-term debt, less current maturities                             $

51,424 $ 51,028




(1)Includes $1.63 billion and $1.64 billion of commercial paper outstanding at
September 30, 2020 and December 31, 2019, respectively.
Recent Transactions
ETO January 2020 Senior Notes Offering and Redemption
On January 22, 2020, ETO completed a registered offering (the "January 2020
Senior Notes Offering") of $1.00 billion aggregate principal amount of the
Partnership's 2.900% Senior Notes due 2025, $1.50 billion aggregate principal
amount of the Partnership's 3.750% Senior Notes due 2030 and $2.00 billion
aggregate principal amount of the Partnership's 5.000% Senior Notes due 2050
(collectively, the "Notes"). The Notes are fully and unconditionally guaranteed
by the Partnership's wholly-owned subsidiary, Sunoco Logistics Partners
Operations L.P., on a senior unsecured basis.
Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its
$400 million aggregate principal amount of 5.75% Senior Notes due September 1,
2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due
October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior
Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50%
Senior Notes due February 15, 2020, ET's $52 million aggregate principal amount
of 7.50% Senior Notes due October 15, 2020 and Transwestern's $175 million
aggregate principal amount of 5.36% Senior Notes due December 9, 2020.
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Credit Facilities and Commercial Paper
ETO Term Loan
ETO's term loan credit agreement provides for a $2 billion three-year term loan
credit facility (the "ETO Term Loan"). Borrowings under the term loan agreement
mature on October 17, 2022 and are available for working capital purposes and
for general partnership purposes. The ETO Term Loan is unsecured and is
guaranteed by ETO's subsidiary, Sunoco Logistics Operations.
As of September 30, 2020, the ETO Term Loan had $2 billion outstanding and was
fully drawn. The weighted average interest rate on the total amount outstanding
as of September 30, 2020 was 1.15%.
ETO Five-Year Credit Facility
ETO's revolving credit facility (the "ETO Five-Year Credit Facility") allows for
unsecured borrowings up to $5.00 billion and matures on December 1, 2023. The
ETO Five-Year Credit Facility contains an accordion feature, under which the
total aggregate commitment may be increased up to $6.00 billion under certain
conditions.
As of September 30, 2020, the ETO Five-Year Credit Facility had $3.23 billion of
outstanding borrowings, $1.63 billion of which was commercial paper. The amount
available for future borrowings was $1.65 billion, after taking into account
letters of credit of $117 million. The weighted average interest rate on the
total amount outstanding as of September 30, 2020 was 1.16%.
ETO 364-Day Facility
ETO's 364-day revolving credit facility (the "ETO 364-Day Facility") allows for
unsecured borrowings up to $1.00 billion and matures on November 27, 2020. As of
September 30, 2020, the ETO 364-Day Facility had no outstanding borrowings.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion senior secured revolving credit facility
(the "Sunoco LP Credit Facility"), which matures in July 2023. As of
September 30, 2020, the Sunoco LP Credit Facility had $87 million of outstanding
borrowings and $8 million in standby letters of credit. As of September 30,
2020, Sunoco LP had $1.41 billion of availability under the Sunoco LP Credit
Facility. The weighted average interest rate on the total amount outstanding as
of September 30, 2020 was 2.15%.
USAC Credit Facility
USAC maintains a $1.60 billion senior secured revolving credit facility (the
"USAC Credit Facility"), with a further potential increase of $400 million,
which matures in April 2023. As of September 30, 2020, the USAC Credit Facility
had $497 million of outstanding borrowings and no outstanding letters of credit.
As of September 30, 2020, USAC had $1.10 billion of borrowing base availability
and, subject to compliance with the applicable financial covenants, available
borrowing capacity of $412 million under the USAC Credit Facility. The weighted
average interest rate on the total amount outstanding as of September 30, 2020
was 3.03%.
SemCAMS Credit Facilities
SemCAMS is party to a credit agreement providing for a C$350 million (US$262
million at the September 30, 2020 exchange rate) senior secured term loan
facility, a C$525 million (US$394 million at the September 30, 2020 exchange
rate) senior secured revolving credit facility, and a C$300 million (US$225
million at the September 30, 2020 exchange rate) senior secured construction
loan facility (the "KAPS Facility"). The term loan facility and the revolving
credit facility mature on February 25, 2024. The KAPS Facility matures on
June 13, 2024. SemCAMS may incur additional term loans and revolving commitments
in an aggregate amount not to exceed C$250 million (US$187 million at the
September 30, 2020 exchange rate), subject to receiving commitments for such
additional term loans or revolving commitments from either new lenders or
increased commitments from existing lenders. As of September 30, 2020, the
SemCAMS senior secured term loan facility and senior secured revolving credit
facility had $253 million and $74 million, respectively, of outstanding
borrowings. As of September 30, 2020, the KAPS Facility had no outstanding
borrowings.
Covenants Related to Our Credit Agreements
We and our subsidiaries were in compliance with all requirements, tests,
limitations, and covenants related to our debt agreements as of September 30,
2020.
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CASH DISTRIBUTIONS
Cash Distributions Paid by the Parent Company
Under the Parent Company partnership agreement, the Parent Company will
distribute all of its Available Cash, as defined 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.
Distributions declared and/or paid subsequent to December 31, 2019 were as
follows:
   Quarter Ended           Record Date            Payment Date           Rate
December 31, 2019       February 7, 2020      February 19, 2020       $ 0.3050
March 31, 2020          May 7, 2020           May 19, 2020              0.3050
June 30, 2020           August 7, 2020        August 19, 2020           0.3050
September 30, 2020      November 6, 2020      November 19, 2020         0.1525


Cash Distributions Paid by Subsidiaries
ETO, Sunoco LP and USAC are required by their respective partnership agreements
to distribute all cash on hand at the end of each quarter, less appropriate
reserves determined by the board of directors of their respective general
partners.
Cash Distributions Paid by ETO
Distributions on ETO preferred units declared and/or paid subsequent to
December 31, 2019 were as follows:
    Period Ended              Record Date               Payment Date             Series A (1)           Series B (1)          Series C          Series D          Series E          Series F (2)          Series G (2)
December 31, 2019          February 3, 2020         February 18, 2020          $       31.25          $      33.125          $ 0.4609          $ 0.4766          $ 0.4750          $          -          $          -
March 31, 2020             May 1, 2020              May 15, 2020                           -                      -            0.4609            0.4766            0.4750                 21.19                 22.36
June 30, 2020              August 3, 2020           August 17, 2020                    31.25                 33.125            0.4609            0.4766            0.4750                     -                     -
September 30, 2020         November 2, 2020         November 16, 2020                      -                      -            0.4609            0.4766            0.4750                 33.75                 35.63


(1)ETO Series A Preferred Unit and ETO Series B Preferred Unit distributions are
paid on a semi-annual basis.
(2)ETO Series F and G Preferred Unit distributions related to the period ended
March 31, 2020 represent a prorated initial distribution. Distributions are paid
on a semi-annual basis.
Cash Distributions Paid by Sunoco LP
Distributions declared and/or paid by Sunoco LP to its common unitholders
subsequent to December 31, 2019 were as follows:
   Quarter Ended           Record Date            Payment Date           Rate
December 31, 2019       February 7, 2020      February 19, 2020       $ 0.8255
March 31, 2020          May 7, 2020           May 19, 2020              0.8255
June 30, 2020           August 7, 2020        August 19, 2020           0.8255
September 30, 2020      November 6, 2020      November 19, 2020         0.8255


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Cash Distributions Paid by USAC
Distributions declared and/or paid by USAC to its common unitholders subsequent
to December 31, 2019 were as follows:
   Quarter Ended           Record Date           Payment Date          Rate
December 31, 2019       January 27, 2020      February 7, 2020      $ 0.5250
March 31, 2020          April 27, 2020        May 8, 2020             0.5250
June 30, 2020           July 31, 2020         August 10, 2020         0.5250
September 30, 2020      October 26, 2020      November 6, 2020        0.5250


ESTIMATES AND CRITICAL ACCOUNTING POLICIES
The selection and application of accounting policies is an important process
that has developed as our business activities have evolved and as the accounting
rules have developed. Accounting rules generally do not involve a selection
among alternatives, but involve an implementation and interpretation of existing
rules, and the use of judgment applied to the specific set of circumstances
existing in our business. We make every effort to properly comply with all
applicable rules, and we believe the proper implementation and consistent
application of the accounting rules are critical. We describe our significant
accounting policies in Note 2 to our consolidated financial statements in the
Partnership's Annual Report on Form 10-K filed with the SEC on February 21,
2020. See Note 1 in "Item 1. Financial Statements" for information regarding
recent changes to the Partnership's critical accounting policies related to
inventory.
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 annual report, words
such as "anticipate," "project," "expect," "plan," "goal," "forecast,"
"estimate," "intend," "could," "believe," "may," "will" and similar expressions
and statements regarding our plans and objectives for future operations, are
intended to identify forward-looking statements. Although we and our General
Partner believe that the expectations on which such forward-looking statements
are based are reasonable, neither we nor our General Partner can give assurances
that such expectations will prove to be correct. Forward-looking statements are
subject to a variety of risks, uncertainties and assumptions. If one or more of
these risks or uncertainties materialize, or if underlying assumptions prove
incorrect, our actual results may vary materially from those anticipated,
estimated, projected or expected. Among the key risk factors that may have a
direct bearing on our results of operations and financial condition are:
•changes in the long-term supply of and demand for natural gas, NGLs, refined
products and/or crude oil, including as a result of uncertainty regarding the
length of time it will take for the United States and the rest of the world to
slow the spread of the COVID-19 virus to the point where applicable authorities
are comfortable easing current restrictions on various commercial and economic
activities; such restrictions are designed to protect public health but also
have the effect of reducing demand for natural gas, NGLs, refined products and
crude oil;
•the severity and duration of world health events, including the recent COVID-19
pandemic, related economic repercussions, actions taken by governmental
authorities and other third parties in response to the pandemic and the
resulting severe disruption in the oil and gas industry and negative impact on
demand for natural gas, NGLs, refined products and crude oil, which may
negatively impact our business;
•changes in general economic conditions and changes in economic conditions of
the crude oil and natural gas industries specifically, including the current
significant surplus in the supply of oil and actions by foreign oil-producing
nations with respect to oil production levels and announcements of potential
changes in such levels, including the ability of those countries to agree on and
comply with supply limitations;
•uncertainty regarding the timing, pace and extent of an economic recovery in
the United States and elsewhere, which in turn will likely affect demand for
natural gas, NGLs, refined products and crude oil and therefore the demand for
midstream services we provide and the commercial opportunities available to us;
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•the deterioration of the financial condition of our customers and the potential
renegotiation or termination of customer contracts as a result of such
deterioration;
•operational challenges relating to the COVID-19 pandemic and efforts to
mitigate the spread of the virus, including logistical challenges, protecting
the health and well-being of our employees, remote work arrangements,
performance of contracts and supply chain disruptions;
•actions taken by federal, state or local governments to require producers of
natural gas, NGL, refined products and crude oil to proration or cut their
production levels as a way to address any excess market supply situations;
•the ability of our subsidiaries to make cash distributions to us, which is
dependent on their results of operations, cash flows and financial condition;
•the actual amount of cash distributions by our subsidiaries to us;
•the volumes transported on our subsidiaries' pipelines and gathering systems;
•the level of throughput in our subsidiaries' processing and treating
facilities;
•the fees our subsidiaries charge and the margins they realize for their
gathering, treating, processing, storage and transportation services;
•the prices and market demand for, and the relationship between, natural gas and
NGLs;
•energy prices generally;
•the prices of natural gas and NGLs compared to the price of alternative and
competing fuels;
•the general level of petroleum product demand and the availability and price of
NGL supplies;
•the level of domestic natural gas, NGL, refined products and crude oil
production;
•the availability of imported natural gas, NGLs, refined products and crude oil;
•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 natural gas, NGLs, refined
products and crude oil;
•availability of local, intrastate and interstate transportation systems;
•the continued ability to find and contract for new sources of natural gas
supply;
•availability and marketing of competitive fuels;
•the impact of energy conservation efforts;
•energy efficiencies and technological trends;
•governmental regulation and taxation;
•changes to, and the application of, regulation of tariff rates and operational
requirements related to our subsidiaries' interstate and intrastate pipelines;
•hazards or operating risks incidental to the gathering, treating, processing
and transporting of natural gas and NGLs;
•competition from other midstream companies and interstate pipeline companies;
•loss of key personnel;
•loss of key natural gas producers or the providers of fractionation services;
•reductions in the capacity or allocations of third-party pipelines that connect
with our subsidiaries pipelines and facilities;
•the effectiveness of risk-management policies and procedures and the ability of
our subsidiaries liquids marketing counterparties to satisfy their financial
commitments;
•the nonpayment or nonperformance by our subsidiaries' customers;
•regulatory, environmental, political and legal uncertainties that may affect
the timing and cost of our subsidiaries' internal growth projects, such as our
subsidiaries' construction of additional pipeline systems or our subsidiaries'
continuing operations;
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•risks associated with the construction of new pipelines and treating and
processing facilities or additions to our subsidiaries' existing pipelines and
facilities, including difficulties in obtaining permits and rights-of-way or
other regulatory approvals and the performance by third-party contractors;
•the availability and cost of capital and our subsidiaries' ability to access
certain capital sources;
•a deterioration of the credit and capital markets;
•risks associated with the assets and operations of entities in which our
subsidiaries own less than a controlling interests, including risks related to
management actions at such entities that our subsidiaries may not be able to
control or exert influence;
•the ability to successfully identify and consummate strategic acquisitions at
purchase prices that are accretive to our financial results and to successfully
integrate acquired businesses;
•changes in laws and regulations to which we are subject, including tax,
environmental, transportation and employment regulations or new interpretations
by regulatory agencies concerning such laws and regulations; and
•the costs and effects of legal and administrative proceedings.
Many of the foregoing risks and uncertainties are, and will be, heightened by
the COVID-19 pandemic and any further worsening of the global business and
economic environment. New factors emerge from time to time, and it is not
possible for us to predict all such factors. Should one or more of the risks or
uncertainties described in this Quarterly Report on Form 10-Q or our Annual
Report on Form 10-K occur, or should underlying assumptions prove incorrect,
actual results and plans could differ materially from those expressed in any
forward-looking statements.
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, 2019, "Part II - Item 1A. Risk Factors" in our Quarterly
Report on Form 10-Q for the quarter ended March 31, 2020, for the quarter ended
June 30, 2020 and in this Quarterly Reports on Form 10-Q. 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.

Latest news about Energy Transfer LP

As shale oil gains slow, deepwater port struggles for customers	Apr. 22	RE
Mizuho Securities Adjusts Price Target on Energy Transfer to $19 From $18, Maintains Buy Rating	Apr. 18	MT
Sunoco Completes European Terminal Acquisition, Station Sale to 7-Eleven -- OPIS	Apr. 17	DJ
Energy Transfer Stay on New Pipeline by DT Midstream Overturned by Appeals Court	Apr. 10	MT
Social Buzz: Wallstreetbets Stocks Mixed Premarket Tuesday; MicroStrategy to Decline, Taiwan Semiconductor Manufacturing to Open Higher	Apr. 09	MT
CERAWEEK-Williams delays Louisiana natgas pipeline amid competitor dispute	Mar. 20	RE
Analysis-Peak rates boost U.S. demand for riskier form of corporate debt	Mar. 15	RE
EQT to buy Equitrans Midstream in bid to boost natural gas margins	Mar. 11	RE
Japan boosts reliance on allies Australia, US for long-term LNG supplies	Mar. 10	RE
Energy Transfer LP Appoints Clifford A. Harris as Director	Feb. 28	CI
Sector Update: Energy Stocks Decline in Friday Afternoon Trading	Feb. 23	MT
Sunoco, Energy Transfer Sign Marketing Partnership With Sauber Motorsport	Feb. 23	MT
Sunoco and Energy Transfer Sign First Joint Multi-Year Partnership with Stake F1 Team Kick Sauber	Feb. 23	CI
Citigroup Adjusts Price Target on Energy Transfer to $18 From $17, Maintains Buy Rating	Feb. 21	MT
Sector Update: Energy Stocks Decline Late Afternoon	Feb. 20	MT
Japan's Kyushu Electric Holds Investment in Energy Transfer's Lake Charles Project	Feb. 20	MT
Exclusive-Occidental explores $18 billion-plus sale of Western Midstream, sources say	Feb. 20	RE
Exclusive-Japan's Kyushu Electric to wait for US LNG policy clarity on Lake Charles	Feb. 20	RE
UBS Adjusts Energy Transfer Price Target to $22 From $23, Maintains Buy Rating	Feb. 15	MT
Energy Transfer earnings rise in Q4 on natural gas liquids demand growth	Feb. 14	RE
Energy Transfer Q4 Earnings, Revenue Increase	Feb. 14	MT
Transcript : Energy Transfer LP, Q4 2023 Earnings Call, Feb 14, 2024	Feb. 14
Energy Transfer LP Reports Earnings Results for the Fourth Quarter and Full Year Ended December 31, 2023	Feb. 14	CI
Woodside Energy Reportedly in Talks with Energy Transfer for US LNG Supplies	Feb. 08	CI
US LNG export pause leaves EU, industry at odds over energy security	Feb. 02	RE

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

Sector

Oil & Gas Transportation Services

Calendar

2024-05-08 - Q1 2024 Earnings Release

More about the company

Income Statement Evolution

More financial data

Ratings for Energy Transfer LP

Trading Rating

Investor Rating

ESG Refinitiv

D+

More Ratings

Analysts' Consensus

Sell

Buy

Mean consensus

BUY

Number of Analysts

Last Close Price

15.83 USD

Average target price

18.48 USD

Spread / Average Target

+16.72%

Consensus

EPS Revisions

Estimates Revisions

Quarterly earnings - Rate of surprise

Company calendar

Sector Natural Gas Pipeline

	1st Jan change	Capi.
ENERGY TRANSFER LP	+15.51%	53.31B
SNAM S.P.A.	-5.97%	15.37B
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CENTURI HOLDINGS, INC.	0.00%	2.11B
OQ GAS NETWORKS SAOC	-5.88%	1.62B
NEXTDECADE CORPORATION	+31.34%	1.59B
SHAANXI PROVINCIAL NATURAL GAS CO.,LTD	-5.18%	1.03B
S.N.T.G.N. TRANSGAZ S.A.	+0.53%	764M
TRANSPORTADORA DE GAS DEL NORTE S.A.	-.--%	328M
PETROVIETNAM LOW PRESSURE GAS DISTRIBUTION	-8.03%	142M

Natural Gas Pipeline