Shell Midstream Partners, L.P. ("we," "us," "our" or "the Partnership") is a
Delaware limited partnership formed by Royal Dutch Shell plc on March 19, 2014
to own and operate pipeline and other midstream assets, including certain assets
acquired from Shell Pipeline Company LP ("SPLC") and its affiliates. We conduct
our operations either through our wholly owned subsidiary Shell Midstream
Operating LLC (the "Operating Company") or through direct ownership. Our general
partner is Shell Midstream Partners GP LLC (the "general partner"). References
to "RDS," "Shell" or "Parent" refer collectively to Royal Dutch Shell plc and
its controlled affiliates, other than us, our subsidiaries and our general
partner.

The following discussion and analysis should be read in conjunction with the
unaudited consolidated financial statements and related notes in this quarterly
report and Management's Discussion and Analysis of Financial Condition and
Results of Operations in Part II, Item 7 of our Annual Report on Form 10-K for
the year ended December 31, 2019 (our "2019 Annual Report") and the consolidated
financial statements and related notes therein. Our 2019 Annual Report contains
a discussion of other matters not included herein, such as disclosures regarding
critical accounting policies and estimates and contractual obligations. You
should also read the following discussion and analysis together with the risk
factors set forth in our 2019 Annual Report, Part II, Item 1A of our Quarterly
Report on Form 10-Q for the quarter ended March 31, 2020, Part II, Item 1A of
our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 and Part
II, Item 1A of this report and the "Cautionary Statement Regarding
Forward-Looking Statements" in this report.

Partnership Overview



We own, operate, develop and acquire pipelines and other midstream and logistics
assets. As of September 30, 2020, our assets include interests in entities that
own (a) crude oil and refined products pipelines and terminals that serve as key
infrastructure to transport onshore and offshore crude oil production to Gulf
Coast and Midwest refining markets and deliver refined products from those
markets to major demand centers and (b) storage tanks and financing receivables
that are secured by pipelines, storage tanks, docks, truck and rail racks and
other infrastructure used to stage and transport intermediate and finished
products. Our assets also include interests in entities that own natural gas and
refinery gas pipelines that transport offshore natural gas to market hubs and
deliver refinery gas from refineries and plants to chemical sites along the Gulf
Coast.

For a description of our assets, see Part I, Item 1 - Business and Properties in our 2019 Annual Report.



2020 developments include:

-Purchase and Sale Agreement. On April 1, 2020, we closed the following
transactions (collectively referred to as the "April 2020 Transaction") pursuant
to the Purchase and Sale Agreement dated as of February 27, 2020 (the "Purchase
and Sale Agreement") by and among the Partnership, Triton West LLC ("Triton"),
SPLC, Shell GOM Pipeline Company LLC ("SGOM"), Shell Chemical LP ("Shell
Chemical") and Equilon Enterprises LLC d/b/a Shell Oil Products US ("SOPUS"):
i.We acquired 79% of the issued and outstanding membership interests in Mattox
Pipeline Company LLC from SGOM (the "Mattox Transaction").
ii.SOPUS and Shell Chemical transferred to Triton, as a designee of the
Partnership, certain logistics assets at the Shell Norco Manufacturing Complex
located in Norco, Louisiana, which are comprised of crude, chemicals,
intermediate and finished product pipelines, storage tanks, docks, truck and
rail racks and supporting infrastructure (such assets, the "Norco Assets" and
such transaction, the "Norco Transaction").

-Partnership Interests Restructuring Agreement. On April 1, 2020, simultaneously
with the closing of the transactions contemplated by the Purchase and Sale
Agreement, we also closed the transactions contemplated by the Partnership
Interests Restructuring Agreement with our general partner, dated as of
February 27, 2020 (the "Partnership Interests Restructuring Agreement"),
eliminating all incentive distribution rights ("IDRs") and converting the
economic general partner interest in the Partnership into a non-economic general
partner interest (the "GP/IDR Restructuring"). As consideration for the
transactions contemplated by the Purchase and Sale Agreement and the Partnership
Interests Restructuring Agreement, SPLC received 160,000,000 newly issued common
units, plus 50,782,904 Series A perpetual convertible preferred units (the
"Series A Preferred Units"). The general partner (or its assignee) has also
agreed to waive a portion of the distributions that would otherwise be payable
on the common units issued to SPLC as part of the April 2020 Transaction, in an
amount of $20 million per quarter for four consecutive fiscal quarters,
beginning with the distribution made with respect to the second quarter of 2020.

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Refer to Note 2 - Acquisitions and Other Transactions in the Notes to the Unaudited Consolidated Financial Statements for more details.



We generate revenue from the transportation, terminaling and storage of crude
oil, refined products, and intermediate and finished products through our
pipelines, storage tanks, docks, truck and rail racks, generate income from our
equity and other investments, and generate interest income from financing
receivables on the Norco Assets. Our revenue is generated from customers in the
same industry, our Parent's affiliates, integrated oil companies, marketers and
independent exploration, production and refining companies primarily within the
Gulf Coast region of the United States. We generally do not own any of the crude
oil, refinery gas or refined petroleum products we handle, nor do we engage in
the trading of these commodities. We therefore have limited direct exposure to
risks associated with fluctuating commodity prices, although these risks
indirectly influence our activities and results of operations over the
long-term.

As a result of Hurricanes Laura, Marco and Sally, we incurred an impact of
approximately $12 million to net income and cash available for distribution
("CAFD") in the third quarter of 2020. Certain producers in the Gulf of Mexico
elected to shut-in and evacuate as a safety precaution, while others were forced
to shut-in or curtail production due to onshore closures. Further, certain
onshore assets were impacted by power outages related to the storms. There was
no material impact to our people or assets as a result of the storms. Further,
as a result of Hurricanes Delta and Zeta, we anticipate an impact of
approximately $10 million to net income and CAFD in the fourth quarter of 2020.

Certain connected producers have had planned turnarounds during 2020. We
generally expect turnaround work to be performed mostly in the second and third
quarters; however, we have seen a delay in that schedule due to hurricanes in
the region, the effects of the COVID-19 pandemic and increased complexity of the
work required by certain producers. As a result, the impact to net income and
CAFD from this turnaround activity was approximately $10 million during the
third quarter of 2020, and we expect the impact for the fourth quarter of 2020
to be approximately $5 million. Further, we anticipate a similar level of
planned turnaround activity in 2021.

The broader market environment for our customers was challenging in 2019, and
has continued to be challenging during the first nine months of 2020 given the
continuing effects of the COVID-19 pandemic, which has impacted worldwide demand
for oil and gas and increased downward pressure on oil prices. The responses of
oil and gas producers to the lower demand for, and price of, oil and natural gas
are constantly evolving and remain uncertain. The master limited partnership
("MLP") market has also changed significantly, as capital for high growth fueled
by dropdown activity continues to be constrained. We are fortunate to have the
support of RDS, who has provided us favorable loan and equity terms, allowing us
flexibility to acquire high quality assets from our affiliates. While we expect
to retain this flexibility, we anticipate continuing to moderate inorganic
growth in our asset base and focusing on the sustainable operation of our core
assets, cash preservation and the organic growth of our business in 2021.

Executive Overview



Net income was $423 million and net income attributable to the Partnership
was $414 million during the nine months ended September 30, 2020. We generated
cash from operations of $503 million. As of September 30, 2020, we had cash and
cash equivalents of $329 million, total debt of $2,694 million and unused
capacity under our credit facilities of $896 million.

Our 2020 operations and strategic initiatives demonstrate our continuing focus on our business strategies:



•Maintain operational excellence through prioritization of safety, reliability
and efficiency;
•Enhanced focus on cash optimization and reduced discretionary project spend;
•Focus on advantageous commercial agreements with creditworthy counterparties to
enhance financial results and deliver reliable distribution growth over the
long-term; and
•Optimize existing assets and pursue organic growth opportunities.

How We Evaluate Our Operations



Our management uses a variety of financial and operating metrics to analyze our
performance. These metrics are significant factors in assessing our operating
results and profitability and include: (i) revenue (including pipeline loss
allowance ("PLA") from contracted capacity and throughput); (ii) operations and
maintenance expenses (including capital expenses); (iii) Adjusted EBITDA
(defined below); and (iv) CAFD.

Contracted Capacity and Throughput


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The amount of revenue our assets generate primarily depends on our transportation and storage services agreements with shippers and the volumes of crude oil, refinery gas and refined products that we handle through our pipelines, terminals and storage tanks.



The commitments under our transportation, terminaling and storage services
agreements with shippers and the volumes we handle in our pipelines and storage
tanks are primarily affected by the supply of, and demand for, crude oil,
refinery gas, natural gas and refined products in the markets served directly or
indirectly by our assets. This supply and demand is impacted by the market
prices for these products in the markets we serve. The COVID-19 pandemic
continues to cause significant disruptions in the U.S. economy and financial and
energy markets, including substantial demand destruction in the oil and gas
markets. Responses of oil and gas producers to the lower demand for, and price
of, oil and natural gas are constantly evolving and unpredictable, but further
or continued decreases in demand (including due to renewed economic shutdowns
and restrictions in response to increased COVID-19 infection rates) could force
producers to shut-in certain wellheads or otherwise cease or curtail their
operations. It also could reduce the volumes running through our pipelines and
terminals.

We utilize the commercial arrangements we believe are the most prudent under the market conditions to deliver on our business strategy. The results of our operations will be impacted by our ability to:



•maintain utilization of and rates charged for our pipelines and storage
facilities;
•utilize the remaining uncommitted capacity on, or add additional capacity to,
our pipeline systems;
•increase throughput volumes on our pipeline systems by making connections to
existing or new third-party pipelines or other facilities, primarily driven by
the anticipated supply of, and demand for, crude oil and refined products; and
•identify and execute organic expansion projects.

Operations and Maintenance Expenses

Our operations and maintenance expenses consist primarily of:



•labor expenses (including contractor services);
•insurance costs (including coverage for our consolidated assets and operated
joint ventures);
•utility costs (including electricity and fuel);
•repairs and maintenance expenses; and
•major maintenance costs (related to the terminaling service agreements of the
Norco Assets, which are expensed as incurred because the Partnership does not
own the related assets).

Certain costs naturally fluctuate based on throughput volumes and the grades of
crude oil and types of refined products we handle, whereas other costs generally
remain stable across broad ranges of throughput and storage volumes, but can
vary depending upon the level of both planned and unplanned maintenance activity
in the particular period. Our maintenance activity can be impacted by events
such as turnarounds, asset integrity work and storms.

Our management seeks to maximize our profitability by effectively managing
operations and maintenance expenses. For example, our property and business
interruption insurance is provided by a wholly owned subsidiary of Shell, which
results in cost savings and improved coverage. Further, we, along with our
Parent, are currently undertaking an initiative to reduce operational costs. We
expect that some of these activities, such as re-scoping and/or deferring
projects, evaluating third-party service contracts and reducing the use of
contractors, will directly benefit our assets and their contribution to our net
income. Other activities, such as the streamlining of structure and processes at
the Parent level, will result in a reduction of certain costs and fees for which
we reimburse and pay SPLC. While cost effectiveness has always been a focus of
the business, it is of increased importance given the current operating
environment.

Adjusted EBITDA and Cash Available for Distribution



Adjusted EBITDA and CAFD have important limitations as analytical tools because
they exclude some, but not all, items that affect net income and net cash
provided by operating activities. You should not consider Adjusted EBITDA or
CAFD in isolation or as a substitute for analysis of our results as reported
under GAAP. Additionally, because Adjusted EBITDA and CAFD may be defined
differently by other companies in our industry, our definition of Adjusted
EBITDA and CAFD may not be comparable to similarly titled measures of other
companies, thereby diminishing their utility.

The GAAP measures most directly comparable to Adjusted EBITDA and CAFD are net
income and net cash provided by operating activities. Adjusted EBITDA and CAFD
should not be considered as an alternative to GAAP net income or net cash
provided by operating activities. Please refer to "Results of Operations -
Reconciliation of Non-GAAP Measures" for the
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reconciliation of the GAAP measures net income and cash provided by operating activities to the non-GAAP measures, Adjusted EBITDA and CAFD.



We define Adjusted EBITDA as net income before income taxes, interest expense,
interest income, gain or loss from dispositions of fixed assets, allowance oil
reduction to net realizable value, loss from revision of asset retirement
obligations, and depreciation, amortization and accretion, plus cash distributed
to us from equity method investments for the applicable period, less equity
method distributions included in other income and income from equity
investments. We define Adjusted EBITDA attributable to the Partnership as
Adjusted EBITDA less Adjusted EBITDA attributable to noncontrolling interests
and Adjusted EBITDA attributable to Parent.

We define CAFD as Adjusted EBITDA attributable to the Partnership less
maintenance capital expenditures attributable to the Partnership, net interest
paid by the Partnership, cash reserves, income taxes paid and Series A Preferred
Units distribution, plus net adjustments from volume deficiency payments
attributable to the Partnership, reimbursements from Parent included in
partners' capital, principal and interest payments received on financing
receivables, and certain one-time payments received. CAFD does not reflect
changes in working capital balances.

The definition of CAFD was updated for the second quarter of 2020 due to the
closing of the April 2020 Transaction, which resulted in part in the transfer of
the Norco Assets to be accounted for as a failed sale leaseback under ASC Topic
842, Leases (the "lease standard"). As a result, the Partnership recognized
financing receivables from SOPUS and Shell Chemical. These assets impact CAFD
since principal payments on the financing receivables are not included in net
income. As a result, such principal and interest payments on the financing
receivables have been included as an adjustment to CAFD since the second quarter
of 2020. Also as partial consideration for the April 2020 Transaction, SPLC
received 50,782,904 Series A Preferred Units. The distributions on these Series
A Preferred Units have been deducted from CAFD since the second quarter of 2020.

We define maintenance capital expenditures as cash expenditures, including
expenditures for (a) the acquisition (through an asset acquisition, merger,
stock acquisition, equity acquisition or other form of investment) by the
Partnership or any of its subsidiaries of existing assets or assets under
construction, (b) the construction or development of new capital assets by the
Partnership or any of its subsidiaries, (c) the replacement, improvement or
expansion of existing capital assets by the Partnership or any of its
subsidiaries or (d) a capital contribution by the Partnership or any of its
subsidiaries to a person that is not a subsidiary in which the Partnership or
any of its subsidiaries has, or after such capital contribution will have,
directly or indirectly, an equity interest, to fund the Partnership or such
subsidiary's share of the cost of the acquisition, construction or development
of new, or the replacement, improvement or expansion of existing, capital assets
by such person), in each case if and to the extent such acquisition,
construction, development, replacement, improvement or expansion is made to
maintain, over the long-term, the operating capacity or operating income of the
Partnership and its subsidiaries, in the case of clauses (a), (b) and (c), or
such person, in the case of clause (d), as the operating capacity or operating
income of the Partnership and its subsidiaries or such person, as the case may
be, existed immediately prior to such acquisition, construction, development,
replacement, improvement, expansion or capital contribution. For purposes of
this definition, "long-term" generally refers to a period of not less than
twelve months.

We believe that the presentation of these non-GAAP supplemental financial measures provides useful information to management and investors in assessing our financial condition and results of operations.

Adjusted EBITDA and CAFD are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:



•our operating performance as compared to other publicly traded partnerships in
the midstream energy industry, without regard to historical cost basis or, in
the case of Adjusted EBITDA, financing methods;
•the ability of our business to generate sufficient cash to support our decision
to make distributions to our unitholders;
•our ability to incur and service debt and fund capital expenditures; and
•the viability of acquisitions and other capital expenditure projects and the
returns on investment of various investment opportunities.

Factors Affecting Our Business and Outlook



We believe key factors that impact our business are the supply of, and demand
for, crude oil, natural gas, refinery gas and refined products in the markets in
which our business operates. We also believe that our customers' requirements,
competition and government regulation of crude oil, refined products, natural
gas and refinery gas play an important role in how we manage
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our operations and implement our long-term strategies. In addition, acquisition
opportunities, whether from Shell or third parties, and financing options, will
also impact our business. These factors are discussed in more detail below.

Changes in Crude Oil Sourcing and Refined Product Demand Dynamics



To effectively manage our business, we monitor our market areas for both
short-term and long-term shifts in crude oil and refined products supply and
demand. Changes in crude oil supply such as new discoveries of reserves,
declining production in older fields, operational impacts at producer fields and
the introduction of new sources of crude oil supply affect the demand for our
services from both producers and consumers. In addition, general economic, broad
market and worldwide health considerations, including the continuing effects of
the COVID-19 pandemic, can also affect sourcing and demand dynamics for our
services.

One of the strategic advantages of our crude oil pipeline systems is their
ability to transport attractively priced crude oil from multiple supply markets
to key refining centers along the Gulf Coast. Our crude oil shippers
periodically change the relative mix of crude oil grades delivered to the
refineries and markets served by our pipelines. They also occasionally choose to
store crude longer term when the forward price is higher than the current price
(a "contango market"). While these changes in the sourcing patterns of crude oil
transported or stored are reflected in changes in the relative volumes of crude
oil by type handled by our pipelines, our total crude oil transportation revenue
is primarily affected by changes in overall crude oil supply and demand
dynamics, including the demand destruction resulting from the COVID-19 pandemic,
as well as U.S. exports.

Similarly, our refined products pipelines have the ability to serve multiple
major demand centers. Our refined products shippers periodically change the
relative mix of refined products shipped on our refined products pipelines, as
well as the destination points, based on changes in pricing and demand dynamics.
While these changes in shipping patterns are reflected in relative types of
refined products handled by our various pipelines, our total product
transportation revenue is primarily affected by changes in overall refined
products supply and demand dynamics, including the continuing effects of the
COVID-19 pandemic. Demand can also be greatly affected by refinery performance
in the end market, as refined products pipeline demand will increase to fill the
supply gap created by refinery issues.

We can also be constrained by asset integrity considerations in the volumes we
ship. We may elect to reduce cycling on our systems to reduce asset integrity
risk, which in turn would likely result in lower revenues.

As these supply and demand dynamics shift, we anticipate that we will continue
to actively pursue projects that link new sources of supply to producers and
consumers and to create new services or capacity arrangements that meet customer
requirements. For example, production from Shell's Appomattox platform in the
Gulf of Mexico, which came online during 2019, tied into our existing Proteus
and Endymion systems to bring crude onshore. Similarly, we expect to continue
extending our corridor pipelines to provide developing growth regions in the
Gulf of Mexico with access via our existing corridors to onshore refining
centers and market hubs. By way of example, in the latter part of 2019 we
announced a solicitation of interest for a potential expansion of the Mars
system to address growing production volumes in the Gulf of Mexico regions
served by Mars. We anticipate bringing that project online in late 2021, with
incremental growth volumes beginning to arrive into the Mars system in 2022. We
believe this strategy will allow our offshore business to grow profitably
throughout demand cycles.

Changes in Customer Contracting



We generate a portion of our revenue under long-term transportation service
agreements with shippers, including ship-or-pay agreements and life-of-lease
transportation agreements, some of which provide a guaranteed return, and
storage service agreements with marketers, pipelines and refiners. Historically,
the commercial terms of these long-term transportation and storage service
agreements have substantially mitigated volatility in our financial results by
limiting our direct exposure to reductions in volumes due to supply or demand
variability. Our business could be negatively affected if we are unable to renew
or replace our contract portfolio on comparable terms, by sustained downturns or
sluggishness in commodity prices, or the economy in general (as with the
continuing effects of the COVID-19 pandemic, including the impacts on the demand
for oil and gas), and is impacted by shifts in supply and demand dynamics, the
mix of services requested by the customers of our pipelines, competition and
changes in regulatory requirements affecting our operations. Our business can
also be impacted by asset integrity or customer interruptions and natural
disasters or other events that could lead customers to invoke force majeure or
other defenses to avoid contractual performance.

During the second quarter of 2019, Zydeco recontracted previously expired volumes under certain of its throughput and deficiency agreements ("T&D agreements"). Although we replaced the volumes, the rates under the new T&D agreements were lower than those previously contracted, and therefore net income and CAFD have been lower. Two of these T&D agreements


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will expire in the fourth quarter of 2020, as the shippers did not elect the
option to extend their contracts for an additional six months. The T&D
agreements that are expiring account for less than 10% of our revenue for the
nine months ended September 30, 2020.

The market environment at any given time will dictate the rates, terms and
duration of agreements that shippers are willing to enter into, as well as the
contracts that best satisfy the needs of our business. As we have grown and
diversified our business over the past several years, and as recently as the
second quarter of 2020 with the April 2020 Transaction, we have benefited from
shifting reliance away from the results of any one asset. While Zydeco continues
to serve an important market, and we strive to maximize the long-term value of
the system to both shippers and the pipeline, we will continue to diversify our
risk across products, customers and geographies.

Changes in Commodity Prices and Customers' Volumes



Crude oil prices have fluctuated significantly over the past few years, often
with drastic moves in relatively short periods of time. In the first nine months
of 2020, the demand for, and price of, oil and natural gas decreased
significantly due to the continuing effects of the COVID-19 pandemic and the
resulting governmental regulations and travel restrictions aimed at slowing the
spread of the virus. The current global geopolitical and economic uncertainty
continues to contribute to future volatility in financial and commodity markets.
Our direct exposure to commodity price fluctuations is limited to the PLA
provisions in our tariffs. Indirectly, global demand for refined products and
chemicals could impact our terminal operations and refined products and refinery
gas pipelines, as well as our crude pipelines that feed U.S. manufacturing
demand. Likewise, changes in the global market for crude oil could affect our
crude oil pipeline and terminals and require expansion capital expenditures to
reach growing export hubs. Demand for crude oil, refined products and refinery
gas may decline in the areas we serve as a result of decreased production by our
customers, depressed commodity prices, decreased third-party investment in the
industry, increased competition and other adverse economic factors such as the
current COVID-19 pandemic, which affect the exploration, production and refining
industries. Although we have seen the earlier depressed demand due to the
pandemic for crude oil and refined products level off, an increase in COVID-19
infection rates could have further negative impacts on demand. This could force
producers to shut-in certain wellheads or otherwise cease or curtail their
operations. It also could reduce the volumes running through our pipelines and
terminals. However, fixed contracts with volume minimums and demand for tanks
for storage are expected to moderate any impact on our terminaling and storage
service revenue.

Certain of our assets benefit from long-term fee-based arrangements and are
strategically positioned to connect crude oil volumes originating from key
onshore and offshore production basins to the Texas and Louisiana refining
markets, where demand for throughput has remained strong. Historically, we have
not experienced a material decline in throughput volumes on our crude oil
pipeline systems as a result of lower crude oil prices. However, if crude oil
prices remain at lower levels for a sustained period due to the continuing
effects of the COVID-19 pandemic or other factors, we will continue to see a
reduction in our transportation volumes if production coming into our systems is
deferred and our associated allowance oil sales decrease. Our customers may also
experience liquidity and credit problems or other unexpected events, which could
cause them to defer development or repair projects, avoid our contracts in
bankruptcy, invoke force majeure clauses or other defenses to avoid contractual
performance or renegotiate our contracts on terms that are less attractive to us
or impair their ability to perform under our contracts.

Our throughput volumes on our refined products pipeline systems depend primarily
on the volume of refined products produced at connected refineries and the
desirability of our end markets. These factors in turn are driven by refining
margins, maintenance schedules and market differentials. Refining margins depend
on the cost of crude oil or other feedstocks and the price of refined products,
which have decreased significantly in the three and nine months ended
September 30, 2020. These margins are affected by numerous factors beyond our
control, including the domestic and global supply of and demand for crude oil
and refined products. Our refined products pipelines are continuing to
experience demand destruction in the near term due to the COVID-19 pandemic,
which has resulted in a significant decrease in consumer demand for refined
products such as gasoline and jet fuel.

Other Changes in Customers' Volumes



Onshore crude transportation volumes were down in both the three months ended
September 30, 2020 (the "Current Quarter") and the nine months ended
September 30, 2020 (the "Current Period") versus the three months ended
September 30, 2019 (the "Comparable Quarter") and the nine months ended
September 30, 2019 (the "Comparable Period") due to demand destruction resulting
from the COVID-19 pandemic.

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Offshore crude transportation volumes were down in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period due to planned maintenance activities, storm activity in the Gulf of Mexico and delays to new wells or well work overs due to storm activity.



Onshore terminaling and storage volumes were down in the Current Quarter and
Current Period versus the Comparable Quarter and Comparable Period due to lower
volume throughput from our customers as a result of the demand destruction due
to the COVID-19 pandemic.

Major Maintenance Projects

At the end of 2019, we finalized a directional drill project on the Zydeco
pipeline system to address soil erosion over a two-mile section of our 22-inch
diameter pipeline under the Atchafalaya River and Bayou Shaffer in Louisiana
(the "directional drill project"). Zydeco incurred approximately $42 million in
maintenance capital expenditures for the total directional drill project. In
connection with the acquisitions of additional interests in Zydeco, SPLC agreed
to reimburse us for our proportionate share of certain costs and expenses with
respect to this project. Costs incurred and reimbursed for the three and nine
months ended September 30, 2020 were not material.

During 2020, we incurred costs related to the Bessie Heights project ("Bessie
Heights"), which is a directional drill project on the Zydeco pipeline system to
replace an exposed and suspended 22-inch diameter pipe in the low-lying marsh
area between Bird Island and Bridge City, Texas, as well as to replace lap
welded pipe below the Neches River. Zydeco is expected to incur approximately
$16 million in maintenance capital expenditures related to the project. Since
inception in early 2020, Zydeco has incurred $13 million in maintenance capital
expenditures related to Bessie Heights, of which $9 million was incurred in the
Current Quarter.

For expected capital expenditures in 2020, refer to Capital Resources and Liquidity - Capital Expenditures and Investments.

Major Expansion Projects



On Mars, we announced in the latter part of 2019 a solicitation of interest for
a potential expansion of the system. Letters of intent are in place, and we are
now progressing definitive agreements with producers and expect to complete them
before the end of 2020. SPLC has elected to fund the installation of the
equipment necessary to enable greater throughput volumes on the system, but the
revenue associated with increased throughput volumes will benefit Mars. It is
expected that the project would be fully operational in late 2021, with
incremental growth volumes beginning to arrive into the Mars system in 2022.

Customers



We transport and store crude oil, refined products, natural gas and refinery gas
for a broad mix of customers, including producers, refiners, marketers and
traders, and are connected to other crude oil and refined products pipelines. In
addition to serving directly-connected U.S. Gulf Coast markets, our crude oil
and refined products pipelines have access to customers in various regions of
the United States through interconnections with other major pipelines. Our
customers use our transportation and storage services for a variety of reasons.
Refiners typically require a secure and reliable supply of crude oil over a
prolonged period of time to meet the needs of their specified refining diet and
frequently enter into long-term firm transportation agreements to ensure a ready
supply of crude oil, rate surety and sometimes sufficient transportation
capacity over the life of the contract. Similarly, chemical sites require a
secure and reliable supply of refinery gas to crackers and enter into long-term
firm transportation agreements to ensure steady supply. Producers of crude oil
and natural gas require the ability to deliver their product to market and
frequently enter into firm transportation contracts to ensure that they will
have sufficient capacity available to deliver their product to delivery points
with greater market liquidity. Marketers and traders generate income from buying
and selling crude oil and refined products to capitalize on price differentials
over time or between markets. Our customer mix can vary over time and largely
depends on the crude oil and refined products supply and demand dynamics in our
markets.

Competition

Our pipeline systems compete primarily with other interstate and intrastate
pipelines and with marine and rail transportation. Some of our competitors may
expand or construct transportation systems that would create additional
competition for the services we provide to our customers. For example, newly
constructed transportation systems in the onshore Gulf of Mexico region may
increase competition in the markets where our pipelines operate. In addition,
future pipeline transportation capacity could be constructed in excess of actual
demand in the market areas we serve, which could reduce the demand for our
services, and could lead to the reduction of the rates that we receive for our
services. While we do see some variation from quarter-to
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quarter resulting from changes in our customers' demand for transportation, this
risk has historically been mitigated by the long-term, fixed rate basis upon
which we have contracted a substantial portion of our capacity.

Our storage terminal competes with surrounding providers of storage tank
services. Some of our competitors have expanded terminals and built new pipeline
connections, and third parties may construct pipelines that bypass our location.
These, or similar events, could have a material adverse impact on our
operations.

Our refined products terminals generally compete with other terminals that serve
the same markets. These terminals may be owned by major integrated oil and gas
companies or by independent terminaling companies. While fees for terminal
storage and throughput services are not regulated, they are subject to
competition from other terminals serving the same markets. However, our
contracts provide for stable, long-term revenue, which is not impacted by market
competitive forces.

Regulation

Our assets are subject to regulation by various federal, state and local agencies; for example, our interstate common carrier pipeline systems are subject to economic regulation by the Federal Energy Regulatory Commission ("FERC"). Intrastate pipeline systems are regulated by the appropriate state agency.



In May 2020, Zydeco, Mars, LOCAP and Colonial filed with FERC to increase rates
subject to FERC's indexing adjustment methodology by approximately 2.01%
starting on July 1, 2020. Rate complaints are currently pending at FERC in
Docket Nos. OR18-7-000, et al. challenging Colonial's tariff rates, its market
power and its practices and charges related to transmix and product volume loss.
While certain procedural deadlines have been extended as a result of the impact
of the COVID-19 pandemic, an initial decision by the administrative law judge in
this proceeding is anticipated by May 31, 2021, with briefs on and opposing
exceptions to follow through July 2021.

On May 21, 2020, FERC issued a Policy Statement resolving the Notice of Inquiry
("NOI") in Docket No. PL19-4-000. The Policy Statement revises FERC's
methodology for calculating the return on equity ("ROE") component of
cost-of-service -based rates to include the Capital Asset Pricing Model
("CAPM"). FERC's use of the discounted cash flow ("DCF") methodology will
continue to be used, but in equal weighting with CAPM. In the Policy Statement,
FERC also clarified certain aspects of its requirements regarding proxy group
composition and treatment of outliers. Finally, FERC encouraged carriers refile
their 2019 FERC Form No. 6 to either revise their ROE to include the CAPM model
or state that they used the DCF model.

On July 18, 2018, FERC issued Order No. 849, which adopts procedures to address
the impact of the federal legislation passed on December 22, 2017 known as the
"Tax Cuts and Jobs Act" ("TCJA") and FERC's Revised Policy Statement on
Treatment of Income Taxes in Docket No. PL17-1-000, issued on March 15, 2018
(the "Revised Policy Statement"). FERC contemporaneously issued the Order on
Rehearing in Docket No. PL17-1-000, which affirms FERC's position in the Revised
Policy Statement that eliminated the recovery of an income tax allowance by MLP
oil and gas pipelines in cost-of-service-based rates. In Order No. 849, however,
FERC has clarified its general disallowance of MLP income tax allowance recovery
by providing that an MLP will not be precluded in a future proceeding from
making a claim that it is entitled to an income tax allowance. FERC will permit
an MLP to demonstrate that its recovery of an income tax allowance does not
result in a "double-recovery of investors' income tax costs." FERC affirmed
Order No. 849 on rehearing on April 18, 2019. Parties sought judicial review of
the Revised Policy Statement, and that challenge, initially filed in March 2019,
was denied by the U.S. Court of Appeals for the D.C. Circuit on August 14, 2020.
No further petitions are outstanding on this matter.

As was the case with the Revised Policy Statement, FERC did not propose any
industry-wide action regarding review of rates for crude oil and liquids
pipelines in its July 2018 issuances. MLP owned crude oil and liquids pipelines
are required to report Page 700 information in their FERC Form No. 6 annual
reports. FERC intends to address the impact of the elimination of the income tax
allowance, as well as the corporate income tax reduction enacted as part of the
TCJA, in its five-year review of the oil pipeline rate index level in 2020. FERC
will also implement the elimination of the income tax allowance in proceedings
involving review of initial cost-of-service rates, rate changes and rate
complaints. For crude oil and liquids pipelines owned by non-MLP partnerships
and other pass-through businesses, FERC will address such issues as they arise
in subsequent proceedings.

On June 18, 2020, FERC issued a NOI as Docket No. RM20-14-000 regarding the
five-year review of the oil pipeline rate index formula. FERC proposed a new
formula of Producer Price Index for Finished Goods ("PPI-FG") plus 0.09% based
on its review of industry data provided in the annual FERC Form 6 reports from
2014 through 2019. The NOI proposal, which would take effect in July 2021, would
change the current five-year formula from PPI-FG plus 1.23%. FERC invited
comments regarding its proposal and any alternative methodologies for
calculating the index level, including issues such as different data
                                       42
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trimming methodologies and whether it should reflect the effects of any
cost-of-service policy changes in the calculation of the index level. Comments
on the NOI were filed by multiple parties by August 17, 2020, and reply comments
were filed by September 11, 2020. A final ruling is expected around year end.

We believe that the recent issuances from FERC, including the Revised Policy
Statement and issuances in July 2018, will not have a material impact on our
operations and financial performance. Since FERC only maintains jurisdiction
over interstate crude oil and liquids pipelines, the recent decisions are not
expected to have an impact on rates charged through our offshore operations.
FERC also does not maintain jurisdiction over certain of the onshore assets in
which we have interests. Rates related to these assets should not be impacted by
FERC's decision. For our FERC-regulated rates charged through our interstate
crude oil and liquids pipelines, the rates are based on either a negotiated or
market-based rate and are not set through cost-of-service ratemaking subject to
FERC's approval, which are below the cost-of-service rates established by FERC.
As such, neither our negotiated nor market-based rate revenue for our
FERC-regulated assets would be subject to the income tax recovery disallowance.
Additionally, we have evaluated the impact of FERC's recent policy changes on
our non-operated joint ventures. Due to the nature of their assets, operations
and/or their entity form, we do not believe there will be any material impact to
their operations and earnings.

On October 20, 2016, FERC issued an Advance Notice of Proposed Rulemaking in
Docket No. RM17-1-000 (the "ANOPR") regarding changes to the oil pipeline rate
index methodology and data reporting on Page 700 of FERC's Form No. 6. On
February 21, 2020, FERC withdrew the ANOPR and denied additional shipper
requests seeking changes to Page 700 reporting requirements as the ANOPR's
proposed changes were not consistent with FERC's simplified and streamlined
indexing regime. No further updates are expected on this matter.

On October 1, 2019, the Pipeline and Hazardous Materials Safety Administration
("PHMSA") issued three new final rules. One rule establishes procedures to
implement the expanded emergency order enforcement authority set forth in an
October 2016 interim final rule. Among other things, this rule allows PHMSA to
issue an emergency order without advance notice or opportunity for a hearing.
The other two rules impose several new requirements on operators of onshore gas
transmission systems and hazardous liquids pipelines. The rule concerning gas
transmission extends the requirement to conduct integrity assessments beyond
High Consequence Areas ("HCAs") to pipelines in Moderate Consequence Areas
("MCAs"). It also includes requirements to reconfirm maximum allowable operating
pressure ("MAOP"), report MAOP exceedances, consider seismicity as a risk factor
in integrity management and use certain safety features on in-line inspection
equipment. The rule concerning hazardous liquids extends the required use of
leak detection systems beyond HCAs to all regulated non-gathering hazardous
liquid pipelines, requires reporting for gravity fed lines and unregulated
gathering lines, requires periodic inspection of all lines not in HCAs, calls
for inspections of lines after extreme weather events and adds a requirement to
make all onshore lines in or affecting HCAs capable of accommodating in-line
inspection tools over the next 20 years. There are new MCAs on some of our gas
transmission lines; however, these lines are already fully inspected due to HCAs
on the lines, so these new areas do not impact inspection or maintenance
programs on the lines. On the liquid side, all onshore lines have leak detection
and are currently inspected under the Integrity Management Program, so there are
no new inspections required. Some of our product lines may need to be made
piggable; however, the full evaluations of those lines have not been completed
to understand potential cost implications.

For more information on federal, state and local regulations affecting our business, please read Part I, Items 1 and 2, Business and Properties in our 2019 Annual Report.


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Acquisition Opportunities



We plan to continue to pursue acquisitions of complementary assets from Shell,
as well as from third parties. We also may pursue acquisitions jointly with
Shell. Given the size and scope of Shell's footprint and its significant
ownership interest in us, we expect acquisitions from Shell will be a growth
mechanism for the foreseeable future. However, Shell and its affiliates are
under no obligation to sell or offer to sell us additional assets or to pursue
acquisitions jointly with us, and we are under no obligation to buy any
additional assets from them or to pursue any joint acquisitions with them. We
will continue to focus our acquisition strategy on transportation and midstream
assets. We believe that we would be well positioned to acquire midstream assets
from Shell, as well as from third parties, should such opportunities arise.
Identifying and executing acquisitions is a key part of our strategy. However,
if we do not make acquisitions on economically acceptable terms or if we incur a
substantial amount of debt in connection with the acquisitions, our future
growth will be limited, and the acquisitions we do make may reduce, rather than
increase, our available cash. Our ability to obtain financing or access capital
markets may also directly impact our ability to continue to pursue strategic
acquisitions. The level of current market demand for equity issued by MLPs may
make it more challenging for us to fund our acquisitions with the issuance of
equity in the capital markets. However, we believe our balance sheet offers us
flexibility, providing us other financing options such as hybrid securities,
purchases of common units by RDS and debt. While we expect to retain this
flexibility, in 2021 we anticipate continuing to moderate inorganic growth in
our asset base and focusing on the sustainable operation of our core assets,
cash preservation and organic growth of our business.
                                       44
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Results of Operations



The following tables and discussion are a summary of our results of operations,
including a reconciliation of Adjusted EBITDA and CAFD to net income and net
cash provided by operating activities, the most directly comparable GAAP
financial measures, for each of the periods indicated.

                                                             Three Months Ended                   Nine Months Ended
                                                               September 30,                        September 30,
                                                           2020               2019              2020              2019
Revenue                                                $      110          $   125          $     351          $   377
Costs and expenses
Operations and maintenance                                     39               33                109               92
Cost of product sold                                            3               10                 20               26
Loss from revision of asset retirement
obligation                                                      -                -                  -                2
General and administrative                                     14               16                 47               45
Depreciation, amortization and accretion                       13               12                 39               36
Property and other taxes                                        6                5                 15               14
Total costs and expenses                                       75               76                230              215
Operating income                                               35               49                121              162
Income from equity method investments                         109              115                330              265
Dividend income from other investments                          -                -                  -               14
Other income                                                    7                8                 27               28
Investment, dividend and other income                         116              123                357              307
Interest income                                                 8                1                 16                2
Interest expense                                               22               27                 71               69
Income before income taxes                                    137              146                423              402
Income tax expense                                              -                -                  -                -
Net income                                                    137              146                423              402
Less: Net income attributable to noncontrolling
interests                                                       2                5                  9               14
Net income attributable to the Partnership                    135              141                414              388
Preferred unitholder's interest in net income
attributable to the Partnership                                12                -                 24                -
General partner's interest in net income
attributable to the Partnership                                 -               36                 55               93
Limited Partners' interest in net income
attributable to the Partnership's common
unitholders                                            $      123          $   105          $     335          $   295
Adjusted EBITDA attributable to the Partnership
(1)                                                    $      191          $   186          $     579          $   543
Cash available for distribution attributable to
the Partnership's common unitholders (1)               $      163

$ 153 $ 496 $ 455

(1) For a reconciliation of Adjusted EBITDA and CAFD attributable to the Partnership's common unitholders to their most comparable GAAP measures, please read "-Reconciliation of Non-GAAP Measures."







                                       45

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                                                          Three Months Ended                           Nine Months Ended
                                                            September 30,                                September 30,
Pipeline throughput (thousands of barrels
per day) (1)                                           2020                  2019                  2020                  2019
Zydeco - Mainlines                                     524                      667                 575                     643
Zydeco - Other segments                                128                      257                 152                     262
Zydeco total system                                    652                      924                 727                     905
Amberjack total system                                 295                      358                 334                     360
Mars total system                                      479                      519                 506                     548
Bengal total system                                    468                      522                 447                     516
Poseidon total system                                  274                      249                 269                     256
Auger total system                                      55                       69                  62                      78
Delta total system                                     151                      254                 216                     259
Na Kika total system                                    25                       26                  46                      35
Odyssey total system                                    85                      146                 117                     149
Colonial total system                                2,198                    2,653               2,403                   2,619
Explorer total system                                  463                      694                 484                     674
Mattox total system (2)                                 70                       57                  65                      34
LOCAP total system                                     955                    1,134               1,010                   1,186
Other systems                                          399                      381                 422                     315

Terminals (3) (4)
Lockport terminaling throughput and
storage volumes                                        208                      233                 221                     225

Revenue per barrel ($ per barrel)
Zydeco total system (5)                         $     0.47               $     0.50          $     0.48              $     0.54
Amberjack total system (5)                            2.33                     2.38                2.36                    2.38
Mars total system (5)                                 1.17                     1.36                1.31                    1.24
Bengal total system (5)                               0.43                     0.46                0.41                    0.41
Auger total system (5)                                1.06                     1.47                1.36                    1.40
Delta total system (5)                                0.58                     0.60                0.59                    0.58
Na Kika total system (5)                              1.02                     0.81                0.93                    0.77
Odyssey total system (5)                              0.92                     0.93                0.93                    0.91
Lockport total system (6)                             0.25                     0.22                0.23                    0.22
Mattox total system (7)                               1.52                     N/A (8)             1.52                    N/A (8)


(1) Pipeline throughput is defined as the volume of delivered barrels. For
additional information regarding our pipeline and terminal systems, refer to
Part I, Item I - Business and Properties - Our Assets and Operations in our 2019
Annual Report.
(2) The actual delivered barrels for Mattox are disclosed in the above table for
the comparative periods. However, Mattox is billed by monthly minimum quantity
per dedication and transportation agreements entered into in April 2020. Based
on the contracted volume determined in the agreements, the thousands of barrels
per day (for revenue calculation purposes) for Mattox are 168 and 163 thousands
of barrels per day for the three and nine months ended September 30, 2020,
respectively.
(3) Terminaling throughput is defined as the volume of delivered barrels and
storage is defined as the volume of stored barrels.
(4) Refinery Gas Pipeline and our refined products terminals are not included
above as they generate revenue under transportation and terminaling service
agreements, respectively, that provide for guaranteed minimum revenue and/or
throughput.
(5) Based on reported revenues from transportation and allowance oil divided by
delivered barrels over the same time period. Actual tariffs charged are based on
shipping points along the pipeline system, volume and length of contract.
(6) Based on reported revenues from transportation and storage divided by
delivered and stored barrels over the same time period. Actual rates are based
on contract volume and length.
(7) Mattox is billed at a fixed rate of $1.52 per barrel for the monthly minimum
quantity in accordance with the terms of dedication and transportation
agreements entered into in April 2020.
(8) Mattox is billed at a fixed rate (see note above) per dedication and
transportation agreements. The rates for 2019 are not applicable as we only
entered into these agreements in April 2020. These agreements do not apply to
2019.

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Reconciliation of Non-GAAP Measures

The following tables present a reconciliation of Adjusted EBITDA and CAFD to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated.



Please read "-Adjusted EBITDA and Cash Available for Distribution" for more
information.

                                                      Three Months Ended                    Nine Months Ended
                                                         September 30,                        September 30,
                                                    2020               2019               2020              2019
Reconciliation of Adjusted EBITDA and Cash
Available for Distribution to Net Income
Net income                                      $      137          $    146          $     423          $    402
Add:
Loss from revision of asset retirement
obligation                                               -                 -                  -                 2
Allowance oil reduction to net realizable value          -                 1                  8                 1
Depreciation, amortization and accretion                17                12                 47                36
Interest income                                         (8)               (1)               (16)               (2)
Interest expense                                        22                27                 71                69
Cash distributions received from equity method
investments                                            142               130                412               341

Less:


Equity method distributions included in other
income                                                   7                 8                 25                25
Income from equity method investments                  109               115                330               265
Adjusted EBITDA                                        194               192                590               559

Less:


  Adjusted EBITDA attributable to
noncontrolling interests                                 3                 6                 11                16
Adjusted EBITDA attributable to the Partnership        191               186                579               543

Less:


Series A Preferred Units distribution                   12                 -                 24                 -
Net interest paid by the Partnership (1)                22                26                 71                67
Maintenance capex attributable to the
Partnership                                             10                 7                 18                21

Add:


Principal and interest payments received on
financing receivables                                    8                 -                 14                 -
Net adjustments from volume deficiency payments
attributable to the Partnership                          8                 -                 16               (10)
Reimbursements from Parent included in
partners' capital                                        -                 -                  -                10
Cash available for distribution attributable to
the Partnership's common unitholders            $      163          $    

153 $ 496 $ 455

(1) Amount represents both paid and accrued interest attributable to the period.





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                                                                      Nine 

Months Ended September 30,


                                                                          2020                   2019

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities Net cash provided by operating activities

                         $             503          $      458
Add:
Interest income                                                                 (16)                 (2)
Interest expense                                                                 71                  69
Return of investment                                                             62                  56
Less:
Change in deferred revenue and other unearned income                             20                 (11)
Non-cash interest expense                                                         -                   1
Allowance oil reduction to net realizable value                                   8                   1
Change in other assets and liabilities                                            2                  31
Adjusted EBITDA                                                                 590                 559

Less:


 Adjusted EBITDA attributable to noncontrolling interests                        11                  16
Adjusted EBITDA attributable to the Partnership                                 579                 543

Less:


Series A Preferred Units distribution                                            24                   -
Net interest paid by the Partnership (1)                                         71                  67
Maintenance capex attributable to the Partnership                                18                  21

Add:

Principal and interest payments received on financing receivables

      14                   -

Net adjustments from volume deficiency payments attributable to the Partnership

                                                                  16                 (10)
Reimbursements from Parent included in partners' capital                          -                  10

Cash available for distribution attributable to the Partnership's common unit holders

                                               $         

496 $ 455

(1) Amount represents both paid and accrued interest attributable to the period.






                                       48
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Current Quarter compared to Comparable Quarter

Revenues



Total revenue decreased by $15 million in the Current Quarter as compared to the
Comparable Quarter, comprised of decreases of $25 million in transportation
services revenue, $5 million in allowance oil revenue and $5 million
attributable to product revenue, partially offset by increases of $19 million
attributable to terminaling services revenue and $1 million of lease revenue.

Transportation services revenue and allowance oil revenue decreased primarily
due to several storms that impacted the Gulf of Mexico during the Current
Quarter which caused several shut-ins of production, as well as downtime related
to planned turnaround activities. Further, the Current Quarter was impacted by
the ongoing effects of the COVID-19 pandemic on the crude and refined products
operating environment and related prices. Additionally, deficiency credits were
deferred in the Current Quarter as compared to deficiency credits being utilized
and recognized in revenue in the Comparable Quarter.

Terminaling services revenue increased primarily due to the recognition of revenue related to the service components of the new terminaling service agreements related to the Norco Assets acquired in April 2020.

Lease revenue was relatively consistent in the Current Quarter and Comparable Quarter.

Product revenue decreased by $5 million and relates to lower sales of allowance oil for certain of our onshore and offshore crude pipelines in the Current Quarter as compared to the Comparable Quarter.

Costs and Expenses



Total costs and expenses decreased $1 million in the Current Quarter as compared
to the Comparable Quarter primarily due to a decrease of $7 million of cost of
product sold and $2 million of general and administrative expenses. These
decreases were almost entirely offset by increases of $6 million of operations
and maintenance expenses, $1 million of depreciation expense, and $1 million of
property taxes.

Cost of product sold decreased as a result of lower sales of allowance oil coupled with the lower cost environment in the Current Quarter as compared to the Comparable Quarter.

General and administrative expenses were relatively flat for the Current Quarter versus the Comparable Quarter.

Operations and maintenance expenses increased mainly as a result of higher maintenance costs related to the Norco Assets in the Current Quarter as compared to the Comparable Quarter.

Property tax expense increased as a result of the acquisition of the Norco Assets in April 2020 and was partially offset by changes in property tax appraisal estimates.

Investment, Dividend and Other Income

Investment, dividend and other income decreased $7 million in the Current Quarter as compared to the Comparable Quarter. Income from equity method investments decreased by $6 million, primarily as a result of lower income from several of our investments in the Current Quarter, most notably Explorer, partially offset by the acquisition of an interest in Mattox in April 2020. Additionally, Other income decreased by $1 million related to lower distributions from Poseidon in the Current Quarter.

Interest Income and Expense



Interest income was $7 million higher in the Current Quarter as compared to the
Comparable Quarter mainly due to interest income related to the financing
receivables recorded in connection with the Norco Assets. Interest expense
decreased by $5 million due to lower interest rates in the Current Quarter
versus the Comparable Quarter resulting from the ongoing effects of the COVID-19
pandemic on market interest rates.


                                       49
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Current Period compared to Comparable Period

Revenues



Total revenue decreased by $26 million in the Current Period as compared to the
Comparable Period, comprised of decreases of $44 million in transportation
services revenue, $9 million in allowance oil revenue and $16 million
attributable to product revenue, partially offset by increases of $42 million
attributable to terminaling services revenue and $1 million of lease revenue.

Transportation services revenue and allowance oil revenue decreased primarily
due to the ongoing effects of the COVID-19 pandemic on the crude and refined
products operating environment and related prices in the Current Period, as well
as lower rates on the Zydeco committed contracts in the Current Period as
compared to the Comparable Period. Additionally, the impact from planned
turnaround activities, as well as the impact of storms and the related shut-ins
of production, was higher in the Current Period than the Comparable Period.
Additionally, deficiency credits were deferred in the Current Period as compared
to deficiency credits being utilized and recognized in revenue in the Comparable
Period. These decreases were partially offset by new volumes brought online at
Na Kika and Odyssey, as well as achieving regulatory approval for an increase in
tariffs on Delta in the Current Period.

Terminaling services revenue increased primarily due to the recognition of revenue related to the service components of the new terminaling service agreement related to the Norco Assets acquired in April 2020.

Lease revenue was relatively consistent in the Current Period and Comparable Period.

Product revenue decreased by $16 million and relates to lower sales of allowance oil for certain of our onshore and offshore crude pipelines in the Current Period as compared to the Comparable Period.

Costs and Expenses



Total costs and expenses increased $15 million in the Current Period primarily
due to the increases of $17 million in operations and maintenance expenses, $3
million of depreciation expense, $2 million in general and administrative
expenses and $1 million in property taxes. These increases were partially offset
by decreases of $6 million in cost of products sold and $2 million of loss from
the revision of asset retirement obligations and disposition of assets incurred
in the Comparable Period.

Operations and maintenance expenses increased mainly as a result of higher maintenance costs related to the Norco Assets in the Current Period as compared to the Comparable Period.

General and administrative expense increased primarily due to higher professional fees related to the April 2020 Transaction and higher severance costs in the Current Period compared to the Comparable Period.

Property tax expense increased as a result of the acquisition of the Norco Assets in April 2020 and was partially offset by changes in property tax appraisal estimates.



Cost of product sold decreased as a result of lower sales of allowance oil
coupled with the lower cost environment in the Current Period as compared to the
Comparable Period, which was partially offset by a higher net realizable value
adjustment on allowance oil inventory in the Current Period.

Investment, Dividend and Other Income



Investment, dividend and other income increased $50 million in the Current
Period as compared to the Comparable Period. Income from equity method
investments increased by $65 million, primarily as a result of the equity
earnings associated with the acquisition of additional interests in Explorer and
Colonial in June 2019, as well as the acquisition of an interest in Mattox in
April 2020. These increases were partially offset by a decrease in dividend
income from other investments of $14 million due to the change in accounting for
Explorer and Colonial as equity method investments in the
                                       50
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Current Period rather than other investments in the Comparable Period following
the acquisition of additional interests in these entities in June 2019. We were
entitled to distributions from Explorer and Colonial with respect to the period
beginning April 1, 2019, as these were paid after the acquisition date and were
no longer considered dividend income. Additionally, Other income decreased by $1
million related to lower distributions from Poseidon in the Current Period.

Interest Income and Expense



Interest income was $14 million higher mainly due to interest income related to
the financing receivables recorded in connection with the Norco Assets. Interest
expense increased by $2 million due to additional borrowings outstanding under
our credit facilities during the Current Period versus the Comparable Period,
which was partially offset by lower interest rates in the Current Period versus
the Comparable Period resulting from the ongoing effects of the COVID-19
pandemic on market interest rates.
                                       51
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Capital Resources and Liquidity



We expect our ongoing sources of liquidity to include cash generated from
operations, borrowings under our credit facilities and our ability to access the
capital markets. We believe this access to credit along with cash generated from
operations will be sufficient to meet our short-term working capital
requirements and long-term capital expenditure requirements, and to make
quarterly cash distributions. However, we cannot accurately predict the effects
of the continuing COVID-19 pandemic on our capital resources and liquidity due
to the current significant level of uncertainty. Our liquidity as of
September 30, 2020 was $1,225 million, consisting of $329 million cash and cash
equivalents and $896 million of available capacity under our credit facilities.

On April 1, 2020, we closed the transactions contemplated by the Partnership
Interests Restructuring Agreement, which included the elimination of all the
IDRs, the conversion of the economic general partner interest into a
non-economic general partner interest and the establishment of the rights and
preferences of the Series A Preferred Units in the Partnership's Second Amended
and Restated Agreement of Limited Partnership, effective as of April 1, 2020
(the "Second Amended and Restated Partnership Agreement"). Pursuant to the
Partnership Interests Restructuring Agreement, the general partner (or its
assignee) has agreed to waive a portion of the distributions that would
otherwise be payable on the common units issued to SPLC as part of the April
2020 Transaction, in an amount of $20 million per quarter for four consecutive
fiscal quarters, beginning with the distribution made with respect to the second
quarter of 2020. Refer to Note 2 - Acquisitions and Other Transactions in the
Notes to the Unaudited Consolidated Financial Statements for more details.

On December 21, 2018, we and our general partner executed Amendment No. 2 (the
"Second Amendment") to the Partnership's First Amended and Restated Agreement of
Limited Partnership dated November 3, 2014. Under the Second Amendment, our
general partner agreed to waive $50 million of distributions in 2019 by agreeing
to reduce distributions to holders of the IDRs by: (1) $17 million for the
quarter ended March 31, 2019, (2) $17 million for the quarter ended June 30,
2019 and (3) $16 million for the quarter ended September 30, 2019.

Credit Facility Agreements



As of September 30, 2020, we have entered into the following credit facilities:

                                         Total Capacity          Current Interest Rate                Maturity Date
Ten Year Fixed Facility                $           600                           4.18  %                      June 4, 2029
Seven Year Fixed Facility                          600                           4.06  %                     July 31, 2025
Five Year Revolver due July 2023                   760                           1.23  %                     July 31, 2023
Five Year Revolver due December
2022                                             1,000                           1.24  %                  December 1, 2022
Five Year Fixed Facility                           600                           3.23  %                     March 1, 2022
2019 Zydeco Revolver (1)                            30                           0.89  %                    August 6, 2024


(1) Effective August 6, 2019, the Zydeco Revolver expired. In its place, Zydeco
entered into the 2019 Zydeco Revolver. See Note 8 - Related Party Debt in the
Notes to the Consolidated Financial Statements included in Part II, Item 8 in
our 2019 Annual Report.

Borrowings under the Five Year Revolver due July 2023, the Five Year Revolver
due December 2022 and the 2019 Zydeco Revolver bear interest at the three-month
LIBOR rate plus a margin or, in certain instances (including if LIBOR is
discontinued) at an alternate interest rate as described in each respective
revolver. Effective December 31, 2021, LIBOR will be discontinued globally, and
as such, a new benchmark will take its place. We are in discussion with our
Parent to further clarify the reference rate(s) applicable to our revolving
credit facilities once LIBOR is discontinued, and we are evaluating any
potential impact on our facilities.

Our weighted average interest rate for the nine months ended September 30, 2020
and September 30, 2019 was 3.4% and 3.8%, respectively. The weighted average
interest rate includes drawn and undrawn interest fees, but does not consider
the amortization of debt issuance costs or capitalized interest. A 1/8
percentage point (12.5 basis points) increase in the interest rate on the total
variable rate debt of $894 million as of September 30, 2020 would increase our
consolidated annual interest expense by approximately $1 million.

We will need to rely on the willingness and ability of our related party lender
to secure additional debt, our ability to use cash from operations and/or obtain
new debt from other sources to repay/refinance such loans when they come due
and/or to secure additional debt as needed.
                                       52
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As of September 30, 2020, we were in compliance with the covenants contained in
our credit facilities, and Zydeco was in compliance with the covenants contained
in the 2019 Zydeco Revolver.

For definitions and additional information on our credit facilities, refer to
Note 7 - Related Party Debt in the Notes to the Unaudited Consolidated Financial
Statements in this report and Note 8 - Related Party Debt in the Notes to the
Consolidated Financial Statements included in Part II, Item 8 in our 2019 Annual
Report.

Equity Issuances

As consideration for the April 2020 Transaction, the Partnership issued 50,782,904 Series A Preferred Units to SPLC at a price of $23.63 per unit, plus 160,000,000 newly issued common units.

Cash Flows from Our Operations



Operating Activities. We generated $503 million in cash flow from operating
activities in the Current Period compared to $458 million in the Comparable
Period. The increase in cash flows was primarily driven by an increase in equity
investment income related to the acquisition of an interest in Mattox in April
2020 and additional interests in Explorer and Colonial in June 2019, as well as
an increase related to deferred revenue in 2020. These increases were partially
offset by the timing of receipt of receivables and payment of accruals in 2020.

Investing Activities. Our cash flow provided by investing activities was $45
million in the Current Period compared to $78 million used in investing
activities in the Comparable Period. The increase in cash flow provided by
investing activities was primarily due to no cash acquisition from Parent, no
contributions to investment, lower capital expenditures and higher return of
investment in the Current Period compared to the Comparable Period.

Financing Activities. Our cash flow used in financing activities was
$509 million in the Current Quarter compared to $294 million in the Comparable
Quarter. The increase in cash flow used in financing activities was primarily
due to increased distributions paid to the unitholders and our general partner,
no borrowings under credit facilities and lower other contributions from Parent
in the Current Period compared to the Comparable Period. These increases were
partially offset by there being no capital distributions to our general partner
in the Current Period.

Capital Expenditures and Investments



Our operations can be capital intensive, requiring investments to maintain,
expand, upgrade or enhance existing operations and to meet environmental and
operational regulations. Our capital requirements consist of maintenance capital
expenditures and expansion capital expenditures. Examples of maintenance capital
expenditures are those made to replace partially or fully depreciated assets, to
maintain the existing operating capacity of our assets and to extend their
useful lives, or other capital expenditures that are incurred in maintaining
existing system volumes and related cash flows. In contrast, expansion capital
expenditures are those made to acquire additional assets to grow our business,
to expand and upgrade our systems and facilities and to construct or acquire new
systems or facilities. We regularly explore opportunities to improve service to
our customers and maintain or increase our assets' capacity and revenue. We may
incur substantial amounts of capital expenditures in certain periods in
connection with large maintenance projects that are intended to only maintain
our assets' capacity or revenue.

We incurred capital expenditures of $20 million and $29 million for the Current
Period and the Comparable Period, respectively. The decrease in capital
expenditures is primarily due to completion of the Houma tank expansion projects
and directional drill projects for Zydeco, coupled with no capital contributions
to Permian Basin in the Current Period.

A summary of our capital expenditures and investments is shown in the table below:


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                                                  Three Months Ended                         Nine Months Ended
                                                    September 30,                              September 30,
                                              2020                  2019                 2020                 2019
Expansion capital expenditures           $          -          $         3          $          1          $       10
Maintenance capital expenditures                    8                    5                    16                  21
Total capital expenditures paid                     8                    8                    17                  31
Increase (decrease) in accrued
capital expenditures                                3                    -                     3                  (2)
Total capital expenditures
incurred                                 $         11          $         8          $         20          $       29
Contributions to investment              $          -          $         3          $          -          $       13

We expect total capital expenditures and investments to be approximately $25 million for 2020, a summary of which is shown in the table below:


                                                        Actual                                 Expected
                                                                                                         Total Expected
                                                  Nine Months Ended          Three Months Ending          2020 Capital
                                                  September 30, 2020          December 31, 2020           Expenditures

Expansion capital expenditures



Triton                                          $                 1          $              -          $             1
Total expansion capital expenditures
incurred                                                          1                         -                        1

Maintenance capital expenditures


  Zydeco                                        $                17          $              3          $            20
  Pecten                                                          1                         1                        2

  Triton                                                          1                         1                        2
Total maintenance capital expenditures
incurred                                                         19                         5                       24
Contributions to investment                                       -                         -                        -
Total capital expenditures and
investments                                     $                20          $              5          $            25



Contributions to investment are related to funding expansion capital and other
expenditures for Permian Basin. There have been no contributions to investment
through the third quarter of 2020, and none are expected for the remainder of
2020.

Zydeco's maintenance capital expenditures for the three and nine months ended
September 30, 2020 were $10 million and $17 million, respectively. Of the $17
million for the nine months ended September 30, 2020, $13 million was for Bessie
Heights, $1 million was for upgrade of the motor control center at Houma and $3
million was for various other maintenance projects. We expect Zydeco's
maintenance capital expenditures to be $3 million for the remainder of 2020, of
which approximately $1 million is for a pipeline exposure requiring replacement,
$1 million is related to an upgrade of the motor control center at Houma, and $1
million is for various other maintenance projects.

Pecten's maintenance capital expenditures for the three and nine months ended
September 30, 2020 were immaterial and $1 million, respectively, and we expect
Pecten's maintenance capital expenditures to be approximately $1 million for the
remainder of 2020. These expenditures relate to various improvements primarily
on Delta.

Triton's expansion capital expenditures for the three and nine months ended
September 30, 2020 were immaterial and $1 million, respectively, and we expect
no further expansion capital expenditures for Triton for the remainder of 2020.
Triton's maintenance capital expenditures for both the three and nine months
ended September 30, 2020 were $1 million, and we expect Triton's maintenance
capital expenditures to be approximately $1 million for the remainder of 2020.
These expenditures relate to maintenance at the various terminals.

We anticipate that both maintenance and expansion capital expenditures for the remainder of the year will be funded primarily with cash from operations.


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Capital Contribution



In accordance with the Member Interest Purchase Agreement dated October 16, 2017
pursuant to which we acquired a 50% interest in Permian Basin, we will make
capital contributions for our pro rata interest in Permian Basin to fund capital
and other expenditures, as approved by a supermajority (75%) vote of the
members. We have made no capital contributions in the three and nine months
ended September 30, 2020, and do not expect to make any capital contributions
for the remainder of 2020.

Contractual Obligations

A summary of our contractual obligations as of September 30, 2020 is shown in
the table below:

                                                         Less than 1             Years 1 to            Years 3 to        More than 5
                                         Total              year                   3                     5                  years
Operating leases for land and platform
space                                  $     7          $        -          $          1          $          1          $        5
Finance leases (1)                          57                   5                    10                    10                  32
Other agreements (2)                        37                   6                    12                    12                   7
Debt obligation (3)                      2,694                   -                 1,494                   600                 600
Interest payments on debt (4)              395                  82                   126                    95                  92
Total                                  $ 3,190          $       93          $      1,643          $        718          $      736


(1) Finance leases include Port Neches storage tanks and Garden Banks 128 "A"
platform. Finance leases include $24 million in interest, $25 million in
principal and $8 million in executory costs.
(2) Includes a joint tariff agreement and tie-in agreement.
(3) See Note 7 - Related Party Debt in the Notes to the Unaudited Consolidated
Financial Statements for additional information.
(4) Interest payments were calculated based on rates in effect at September 30,
2020 for variable rate borrowings.

As of September 30, 2020, our contractual obligations included long-term debt,
finance lease obligations, operating lease obligations and other contractual
obligations. There were no material changes to these obligations outside the
ordinary course of business since December 31, 2019.

Our Series A Preferred Units are contractually entitled to receive cumulative
quarterly distributions. For the three months ended September 30, 2020,
cumulative preferred distributions paid to our Series A Preferred Unitholders
were $12 million. However, subject to certain conditions, we or the holders of
the Series A Preferred Units may convert the Series A Preferred Units into
common units at certain anniversary dates after the issuance date. Due to the
uncertain timing of any potential conversion, distributions related to the
Series A Preferred Units were not included in the contractual obligations table
above.


Off-Balance Sheet Arrangements

We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.

Environmental Matters and Compliance Costs



Our operations are subject to extensive and frequently changing federal, state
and local laws, regulations and ordinances relating to the protection of the
environment. Among other things, these laws and regulations govern the emission
or discharge of pollutants into or onto the land, air and water, the handling
and disposal of solid and hazardous wastes and the remediation of contamination.
As with the industry in general, compliance with existing and anticipated
environmental laws and regulations increases our overall cost of business,
including our capital costs to construct, maintain, operate and upgrade
equipment and facilities. While these laws and regulations affect our
maintenance capital expenditures and net income, we believe they do not affect
our competitive position, as the operations of our competitors are similarly
affected. We believe our facilities are in substantial compliance with
applicable environmental laws and regulations. However, these laws and
regulations are subject to changes, or to changes in the interpretation of such
laws and regulations, by regulatory authorities, and continued and future
compliance with such laws and regulations may require us to incur significant
expenditures. Violation of environmental laws, regulations and permits can
result in the imposition of significant administrative, civil and criminal
penalties, injunctions limiting our operations, investigatory or remedial
liabilities or construction bans or delays in the construction of additional
facilities or equipment. Additionally, a release of hydrocarbons or hazardous
substances into the environment could, to the
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extent the event is not insured, subject us to substantial expenses, including
costs to comply with applicable laws and regulations and to resolve claims by
third parties for personal injury or property damage, or claims by the U.S.
federal government or state governments for damages to natural resources. These
impacts could directly and indirectly affect our business and have an adverse
impact on our financial position, results of operations and liquidity if we do
not recover these expenditures through the rates and fees we receive for our
services. We believe our competitors must comply with similar environmental laws
and regulations. However, the specific impact on each competitor may vary
depending on a number of factors, including, but not limited to, the type of
competitor and location of its operating facilities. For additional information,
refer to Environmental Matters, Items 1 and 2, Business and Properties in our
2019 Annual Report.

We accrue for environmental remediation activities when the responsibility to
remediate is probable and the amount of associated costs can be reasonably
estimated. As environmental remediation matters proceed toward ultimate
resolution or as additional remediation obligations arise, charges in excess of
those previously accrued may be required. New or expanded environmental
requirements, which could increase our environmental costs, may arise in the
future. We believe we substantially comply with all legal requirements regarding
the environment; however, as not all of the costs are fixed or presently
determinable (even under existing legislation) and may be affected by future
legislation or regulations, it is not possible to predict all of the ultimate
costs of compliance, including remediation costs that may be incurred and
penalties that may be imposed.


Critical Accounting Policies and Estimates



Our critical accounting policies and estimates are set forth in Part II, Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operation - Critical Accounting Policies and Estimates in our 2019 Annual
Report. As of September 30, 2020, there have been no significant changes to our
critical accounting policies and estimates since our 2019 Annual Report was
filed other than those noted below.

April 2020 Transaction Fair Value



In connection with the April 2020 Transaction, we utilized the services of
independent valuation specialists to assist in the fair value appraisals to
determine the fair value of the total consideration, as well as the fair values
of the Mattox Transaction, the Norco Transaction, and the GP/IDR Restructuring
as of April 1, 2020. Because the components of the April 2020 Transaction were
entered in contemplation of each other and were transactions among entities
under common control, the fair values of the April 2020 Transaction were used
solely for the purpose of allocating a portion of the total consideration on a
relative fair value basis to the Norco Transaction. The Partnership issued
50,782,904 Series A Preferred Units and 160,000,000 newly issued common units to
SPLC as consideration for the April 2020 Transaction. See Note 2 - Acquisitions
and Other Transactions for additional details.

As further described in Note 2-Acquisitions and Other Transactions, we acquired
the Mattox equity interests from SGOM as a part of the Mattox Transaction. The
acquisition was accounted for as a transaction among entities under common
control on a prospective basis as an asset acquisition. As a part of the Norco
Transaction, SOPUS and Shell Chemical transferred certain logistics assets at
the Shell Norco Manufacturing Complex to Triton, as designee of the Partnership.
The transfer of the Norco Assets combined with the terminaling service
agreements was accounted for as a failed sale leaseback under the lease
standard, as control of the assets did not transfer to the Partnership. As a
result, the transaction was treated as financing arrangement.

The amount of contract assets recognized was dependent on the allocated fair
value of the consideration to the Norco Transaction, which was determined using
the fair values of the consideration transferred and the fair values of the
three components of the April 2020 Transaction. The common units were valued
using a market approach based on the market opening price of the Partnership's
common units as of April 1, 2020 less a discount for the distribution waiver and
marketability. The Series A Preferred Units were valued using an income approach
based on a trinomial lattice model. Further, the fair values of the three
components of the April 2020 Transaction were determined using an income
approach of discounted cash flows at an average discount rate for each of the
Mattox Transaction, the Norco Transaction, and the GP/IDR Restructuring
components of 14%, 11% and 20%, respectively.

We believe both the estimates and assumptions utilized in the fair value
appraisals of the April 2020 Transaction are individually and in the aggregate
reasonable; however, our estimates and assumptions are highly judgmental in
nature. Further, there are inherent uncertainties related to these estimates and
assumptions, and our judgment in applying them, to determine the fair values.
While we believe we have made reasonable estimates and assumptions to calculate
the fair values, changes in any
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one of the estimates, assumptions or a combination of estimates and assumptions,
could result in changes to the estimated fair values utilized to determine the
relative stand-alone fair value of the Norco Transaction.

Fair value of consideration

The following table summarized the fair valuation approaches and key assumptions underlying those approaches to value the different components of the consideration of the April 2020 Transaction:


                                              Valuation Technique                              Key assumptions
                                                                                  Discount for lack of marketability; waiver
Common Units                                    Market Approach                                    discount
                                                                                  Volatility rate; expected term; yield and
Series A Preferred Units                        Income Approach                                conversion price



Fair value of business enterprise value

The following table summarizes the fair valuation approaches and key assumptions underlying those approaches to obtain the business enterprise value of the different components of the April 2020 Transaction:


                                           Valuation Technique                              Key assumptions
                                                                            Discount rates; revenue growth rates; terminal
Mattox Transaction                           Income Approach                

growth rates; cash flow projections


                                                                            Discount rates; revenue growth rates; terminal
Norco Transaction                            Income Approach                

growth rates; cash flow projections

Discount rates; revenue growth rates; terminal


                                                                              growth rates; projected cash available for
GP/IDR Restructuring                         Income Approach                                 distribution



Relative Stand -Alone Selling Price



We allocate the arrangement consideration between the components based on the
relative stand-alone selling price ("SASP") of each component in accordance with
ASC Topic 606, Revenue from Contracts with Customers. The Partnership
established the stand-alone selling price for the financing components based off
an expected return on the assets being financed. The Partnership established the
SASP for the service components using an expected cost-plus margin approach
based on the Partnership's forecasted costs of satisfying the performance
obligations plus an appropriate margin for the service. The SASP is used to
allocate the annual terminaling service agreement payments between the principal
payments and interest income on the financing receivables (financing components)
and terminaling service revenue (service components). The key assumptions
include forecasts of the future operation and maintenance costs and major
maintenance costs and the expected return.

Recent Accounting Pronouncements



Please refer to Note 1- Description of Business and Basis of Presentation in the
Notes to the Unaudited Consolidated Financial Statements for a discussion of
recently adopted accounting pronouncements and new accounting pronouncements.
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           CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements. You can identify our
forward-looking statements by the words "anticipate," "estimate," "believe,"
"budget," "continue," "could," "intend," "may," "plan," "potential," "predict,"
"seek," "should," "would," "expect," "objective," "projection," "forecast,"
"goal," "guidance," "outlook," "effort," "target" and similar expressions.

We based the forward-looking statements on our current expectations, estimates
and projections about us and the industries in which we operate in general. We
caution you these statements are not guarantees of future performance as they
involve assumptions that, while made in good faith, may prove to be incorrect,
and involve risks and uncertainties we cannot predict. In addition, we based
many of these forward-looking statements on assumptions about future events that
may prove to be inaccurate. Accordingly, our actual outcomes and results may
differ materially from what we have expressed in the forward-looking statements.
Any differences could result from a variety of factors, including the following:

•The continued ability of Shell and our non-affiliate customers to satisfy their
obligations under our commercial and other agreements and the impact of lower
market prices for crude oil, refined petroleum products and refinery gas.
•The volume of crude oil, refined petroleum products and refinery gas we
transport or store and the prices that we can charge our customers.
•The tariff rates with respect to volumes that we transport through our
regulated assets, which rates are subject to review and possible adjustment
imposed by federal and state regulators.
•Changes in revenue we realize under the loss allowance provisions of our fees
and tariffs resulting from changes in underlying commodity prices.
•Our ability to renew or replace our third-party contract portfolio on
comparable terms.
•Fluctuations in the prices for crude oil, refined petroleum products and
refinery gas, including fluctuations due to political or economic measures taken
by various countries.
•The level of production of refinery gas by refineries and demand by chemical
sites.
•The level of onshore and offshore (including deepwater) production and demand
for crude oil by U.S. refiners.
•Changes in global economic conditions and the effects of a global economic
downturn on the business of Shell and the business of its suppliers, customers,
business partners and credit lenders.
•The COVID-19 pandemic and related governmental regulations and travel
restrictions, and the resulting sustained reduction in the global demand for oil
and natural gas.
•Availability of acquisitions and financing for acquisitions on our expected
timing and acceptable terms.
•Changes in, and availability to us, of the equity and debt capital markets.
•Liabilities associated with the risks and operational hazards inherent in
transporting and/or storing crude oil, refined petroleum products and refinery
gas.
•Curtailment of operations or expansion projects due to unexpected leaks,
spills, or severe weather disruption; riots, strikes, lockouts or other
industrial disturbances; or failure of information technology systems due to
various causes, including unauthorized access or attack.
•Costs or liabilities associated with federal, state and local laws and
regulations relating to environmental protection and safety, including spills,
releases and pipeline integrity.
•Costs associated with compliance with evolving environmental laws and
regulations on climate change.
•Costs associated with compliance with safety regulations and system maintenance
programs, including pipeline integrity management program testing and related
repairs.
•Changes in tax status or applicable tax laws.
•Changes in the cost or availability of third-party vessels, pipelines, rail
cars and other means of delivering and transporting crude oil, refined petroleum
products and refinery gas.
•Direct or indirect effects on our business resulting from actual or threatened
terrorist incidents or acts of war.
•Our adoption of the new enterprise resource planning system.
•The factors generally described in Part I, Item 1A. Risk Factors in our 2019
Annual Report, in Part II, Item 1A. Risk Factors in our Quarterly Report on Form
10-Q for the quarter ended March 31, 2020 and in Part II, Item 1A. Risk Factors
in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 and in
Part II, Item 1A. Risk Factors of this report.


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