SHELL MIDSTREAM PARTNERS L P : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-K)

Management's Discussion and Analysis of Financial Condition and Results of
Operations are the analysis of our financial performance, financial condition
and significant trends that may affect future performance. It should be read in
conjunction with the consolidated financial statements and notes thereto
included in Part II, Item 8 of this report. It should also be read together with
"Risk factors" and "Cautionary Statement Regarding Forward-Looking Statements"
in this report.

On January 1, 2019, we adopted Topic 842, Leases ("the new lease standard") by
applying the modified retrospective approach. Results for reporting periods
beginning after January 1, 2019 and balances at December 31, 2019 are presented
in accordance with the new lease standard, while prior period amounts are not
adjusted and continue to be reported in accordance with our historical
accounting under previous generally accepted accounting principles in the United
States ("GAAP"). See Note 9 - Leases in the Notes to Consolidated Financial
Statements included in Part II, Item 8.

On January 1, 2018, we adopted Topic 606, Revenue from Contracts with Customers,
and all related ASUs to this Topic (collectively, "the revenue standard") by
applying the modified retrospective method to all contracts that were not
completed on January 1, 2018. Results for reporting periods beginning after
January 1, 2018 are presented in accordance with the revenue standard, while
prior period amounts are not adjusted and continue to be reported in accordance
with our historic accounting under previous GAAP. See Note 12 - Revenue
Recognition in the Notes to Consolidated Financial Statements included in Part
II, Item 8.
Partnership Overview
We own, operate, develop and acquire pipelines and other midstream assets. As of
December 31, 2019, our assets include interests in entities that own crude oil
and refined products pipelines and terminals that serve as key infrastructure to
(i) transport onshore and offshore crude oil production to Gulf Coast and
Midwest refining markets and (ii) deliver refined products from those markets to
major demand centers. Our assets also include interests in entities that own
natural gas and refinery gas pipelines which 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, please see Part I, Item 1 - Business and
Properties of this report.
2019 developments include:

•June 2019 Acquisition. In May 2019, we entered into a Contribution Agreement
(the "May 2019 Contribution Agreement") with SPLC to acquire SPLC's remaining
25.97% ownership interest in Explorer and 10.125% ownership interest in Colonial
for consideration valued at $800 million (the "June 2019 Acquisition"). The June
2019 Acquisition increased the Partnership's ownership interest in Explorer to
38.59% and in Colonial to 16.125%. We funded the June 2019 Acquisition with $600
million in cash consideration from borrowings under our Ten Year Fixed Facility
(as defined below) with Shell Treasury Center (West) Inc. ("STCW") and non-cash
equity consideration valued at $200 million from the issuance
of 9,477,756 common units to Shell Midstream LP Holdings LLC, an indirect
subsidiary of Shell, and 193,424 general partner units to the general partner in
order to maintain its 2% general partner interest in us.

•Borrowings. In June 2019, we entered into a ten-year fixed rate credit facility
with STCW with a borrowing capacity of $600 million (the "Ten Year Fixed
Facility"). The Ten Year Fixed Facility was fully drawn to partially fund the
June 2019 Acquisition.
We generate revenue from the transportation, terminaling and storage of crude
oil and refined products through our pipelines and storage tanks, and we
generate income from our equity and other investments. 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.

Notable 2019 and certain anticipated 2020 impacts to net income and cash available for distribution include:

•Hurricane Barry. As a result of Hurricane Barry, we incurred an impact of
approximately $10 million to net income and cash available for distribution in
the third quarter of 2019. Certain producers in the Gulf of Mexico elected to
shut-
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in and evacuate as a safety precaution, while others were forced to shut-in or
curtail production due to onshore closures. There was no material impact to our
people, assets or the environment as a result of the storm.

•Planned Turnarounds. Certain connected producers had planned turnarounds during
2019. The impact to net income and cash available for distribution was
approximately $10 million for the year ended December 31, 2019. As a result of
certain offshore planned producer turnarounds, we anticipate a similar impact in
2020 to both net income and cash available for distribution.

•Storage Revenue Reimbursement from SPLC. We received approximately $9 million
in the fourth quarter of 2019 from SPLC related to a storage revenue
reimbursement provision contained in the Purchase and Sale Agreement entered
into in 2016 under which we acquired an additional 20% interest in Mars.
Pursuant to the Purchase and Sale Agreement, SPLC agreed to pay us up to $10
million if Mars inventory management fees do not meet certain levels for the
calendar years 2017 through 2021. Refer to Note 5 - Equity Method Investments in
the Notes to the Consolidated Financial Statements included in Part II, Item 8
for additional information.

The broader market environment for our customers was challenging in 2019, and we
expect it to remain so in 2020. The MLP market also changed significantly in
2019, as capital for high growth fueled by dropdown activity was constrained. We
are fortunate to have the support of our sponsor, 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, in 2020 we
anticipate moderating inorganic growth in our asset base and focusing on the
sustainable operation of our core assets and organic growth of our business.

Executive Overview
Net income was $546 million and net income attributable to the Partnership
was $528 million in 2019. We generated cash from operations of $597 million and
increased our borrowing capacity by $600 million. Cash generated was primarily
used to pay down debt with STCW. In addition, we completed the June 2019
Acquisition for $800 million. As of December 31, 2019, we had cash and cash
equivalents of $290 million, total debt of $2,692 million, and unused capacity
under our revolving credit facilities of $896 million.
Our 2019 operations and strategic initiatives demonstrated our continuing focus
on our business strategies:

•Maintain operational excellence through prioritization of safety, reliability
and efficiency;
•Growth through strategic acquisitions in key geographies to achieve integrated
value;
•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) Cash Available for Distribution.
Contracted Capacity and Throughput
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.
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The commitments under our transportation, terminaling and storage services
agreements with shippers and the volumes which 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. 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 management seeks to maximize our profitability by effectively managing
operations and maintenance expenses. These expenses are comprised 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) and repairs and maintenance expenses. Utility
costs fluctuate based on throughput volumes and the grades of crude oil and
types of refined products we handle. Our property and business interruption
coverage is provided by a wholly owned subsidiary of Shell, which results in
cost savings and improved coverage. Our other operations and maintenance
expenses generally remain stable across broad ranges of throughput and storage
volumes, but can fluctuate from period to period depending on the mix of
activities, particularly maintenance activities, performed during a period. At
times, the fluctuation in operations and maintenance expenses may materially
increase due to the performance of planned maintenance, such as turnaround work
and asset integrity work, and unplanned maintenance, such as repair of damage
caused by a natural disaster.
Adjusted EBITDA and Cash Available for Distribution
Adjusted EBITDA and cash available for distribution 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 cash available for distribution in isolation or as a
substitute for analysis of our results as reported under GAAP. Additionally,
because Adjusted EBITDA and cash available for distribution may be defined
differently by other companies in our industry, our definition of Adjusted
EBITDA and cash available for distribution 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 cash available
for distribution are net income and net cash provided by operating activities.
Adjusted EBITDA and cash available for distribution 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 reconciliation of GAAP measures net income and cash provided by
operating activities to non-GAAP measures Adjusted EBITDA and cash available for
distribution.

We define Adjusted EBITDA as net income before income taxes, net interest
expense, gain or loss from dispositions of fixed assets, allowance oil reduction
to net realizable value, loss from revision of asset retirement obligation, 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 method
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 cash available for distribution as Adjusted EBITDA attributable to the
Partnership less maintenance capital expenditures attributable to the
Partnership, net interest paid, cash reserves and income taxes paid, plus net
adjustments from volume deficiency payments attributable to the Partnership,
reimbursements from Parent included in partners' capital and certain one-time
payments received. Cash available for distribution will not reflect changes in
working capital balances.
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. We present these financial
measures
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because we believe replacing our proportionate share of our equity method
investments' net income with the cash received from such equity method
investments more accurately reflects the cash flow from our business, which is
meaningful to our investors.
Adjusted EBITDA and cash available for distribution 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 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. 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 and 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. 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, and we anticipate bringing that project online in 2021. We
believe this strategy will allow our offshore business to grow profitably
throughout demand cycles.
Changes in Customer Contracting
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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, 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.

Two of our long-term transportation services agreements on the Zydeco system
expired at the end of 2018, and another expired in the second quarter of 2019.
These contracts represented approximately 30% of our revenues for both the years
ended December 31, 2018 and 2017. As a result of the open season conducted in
the second quarter of 2019, Zydeco was able to re-contract the expired volumes
under throughput and deficiency agreements ("T&D agreements"). Although we have
replaced the volumes from the expired contracts, the rates under the new T&D
agreements are lower than those previously contracted, and therefore net income
and cash available for distribution are lower. Further, two of these T&D
agreements will expire in the fourth quarter of 2020; however, the shippers have
the ability to extend the contracts for an additional six months. The ability to
re-contract those T&D agreements could further impact net income and cash
available for distribution.

The market environment dictated the rates, terms and duration of these T&D
agreements. Increases or decreases in available crude supply in the Houston
market can affect demand for transportation to other markets, especially the
Louisiana refining market. A number of factors could impact this, including
increased production in fields with Houston connectivity and increased export
capabilities at Texas Gulf Coast ports. Shippers may also choose alternate
routes on which to ship. Alternatively, Louisiana refineries' availability and
crude slates, as well as potential crude options at Louisiana Gulf Coast ports,
can impact Louisiana demand for crude types available in the Houston market.
Additionally, crude prices and basis differentials directly impact the price our
customers are willing to pay to transport. Despite these challenges, we believe
that 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.

Revenue we generate from spot shipments typically has a corresponding positive
impact on cash available for distribution. However, in the first half of 2019,
previously committed shippers whose contracts expired at the end of 2018 had the
ability to ship on credits earned related to under-shipments prior to the
expiration of their contracts. As such, revenue is recognized for the usage of
those credits, but cash is not received. For the contract that expired during
the second quarter of 2019, the shipper had the ability to ship on previously
earned credits into the fourth quarter of 2019. These credits were not material.

The cumulative effect of the foregoing circumstances and challenges on Zydeco
has had, and may continue to have, a material impact on our financial results.
The impact on our net income and cash available for distribution in the first
half of 2019, prior to re-contracting, was approximately $55 million.
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. At the start of 2019,
prices increased from fourth quarter 2018 levels and remained relatively
consistent throughout the remainder of the year. However, 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 affecting the exploration, production and
refining industries.
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, we could see a reduction in our transportation
volumes if production coming into our systems is deferred and our
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associated allowance oil sales decrease. Our customers may also experience
liquidity and credit problems, which could cause them to defer development or
repair projects, avoid our contracts in bankruptcy 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.
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. We
are currently experiencing relatively high demand for our pipeline systems that
service refineries.
Other Changes in Customers' Volumes
Onshore crude transportation volumes were higher in 2019 versus 2018 primarily
due to declaring Force Majeure in 2018 related to hydro-testing the Zydeco
pipeline that resulted in 49 days of downtime, as well as from overall higher
receipts from connecting offshore pipelines.

Offshore crude transportation volumes were higher in 2019 versus 2018 primarily
due to increased production at certain platforms and from several large fields
in the central Gulf of Mexico, as well as an increase in receipt volume from a
connecting pipeline system. Additionally, certain production was shut-in during
2018 for unplanned maintenance and returned to normal levels during 2019.
Partially offsetting this increase was the impact of planned turnarounds and
unplanned maintenance in 2019, as well as the impact of Hurricane Barry.

Offshore storage volumes were lower in 2019 versus 2018 due to the increase in
demand for exports reducing the need for storage.
Major Maintenance Projects
On the Zydeco pipeline system, we have finalized a directional drill project 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 project, of which $11 million was in 2019. In
connection with the acquisitions of additional interests in Zydeco, SPLC agreed
to reimburse us against our proportionate share of certain costs and expenses
with respect to this project. During 2019, we filed claims for reimbursement
from SPLC of $10 million, which were treated as capital contributions from our
Parent. Although the project is fully operational, we expect that there will be
approximately $4 million of expense incurred in the future related to final
close out activities, for which our share will be reimbursed.

For expected capital expenditures in 2020, refer to Capital Resources and
Liquidity - Capital Expenditures.
Major Expansion Projects
In June 2017, Zydeco began construction on a tank expansion project in Houma to
address future capacity shortfalls during tank maintenance which will allow us
to service additional capacity, as well as allow for existing tanks to come out
of service for regularly scheduled inspection and maintenance. The scope
included interconnecting piping, dike expansion and associated facility work.
The tanks were completed during the first quarter of 2019 and are operational.
We built two 250,000 barrel working tanks at the existing Houma facility and
have incurred growth capital expenditures of $47 million since inception, of
which $7 million was incurred in 2019.

On Mars, we announced a solicitation of interest for a potential expansion of
the system in the latter part of 2019. The solicitation was intended to gauge
producer interest in an expansion of capacity in order to transport volumes to
market and would offer priority service on any new incremental capacity.
Substantial interest was received from producers, and we are now scoping to
accommodate expected additional demand and working to reach final investment
decision in the first half of 2020. It is expected that the project would be
fully operational in 2021.
Customers
We transport and store crude oil, refined products, natural gas, and refinery
gas for a broad mix of customers, including shippers, 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
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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. Refer
to Note 14 - Transactions with Major Customers and Concentration of Credit Risk
in the Notes to the Consolidated Financial Statements included in Part II, Item
8 for additional information.
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, which could reduce the demand for our services, in the market areas we
serve, and could lead to the reduction of the rates that we receive for our
services. While we do see some variation from quarter-to-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. However, two of our long-term
transportation services agreements on the Zydeco system expired at the end of
2018, and another expired in the second quarter of 2019. These contracts
represented approximately 30% of our revenues for both the years ended December
31, 2018 and 2017. As a result of the open season conducted in the second
quarter of 2019, Zydeco was able to re-contract the expired volumes under T&D
agreements. Although we have replaced the volumes from the expired contracts,
the rates under the new T&D agreements are lower than those previously
contracted, and therefore net income and cash available for distribution will be
lower. Further, two of these contracts will expire in the fourth quarter of
2020; however, the shippers have the ability to extend the contracts for an
additional six months. See "Changes in Customer Contracting" for additional
information.
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 economic regulation by various federal, state and/or
local agencies. For example, our interstate common carrier pipeline systems are
subject to economic regulation by FERC.
In May 2019, Zydeco, Mars, LOCAP and Colonial filed with FERC to increase rates
subject to FERC's indexing adjustment methodology by approximately 4.3% starting
on July 1, 2019.

On March 21, 2019, FERC issued a Notice of Inquiry ("NOI") in Docket No.
PL19-4-000 seeking comments on whether it should modify its policies concerning
the determination of return on equity ("ROE") for utilities, and on whether any
policy changes concerning utility ROEs should be applied to oil and natural gas
pipelines. The NOI includes a discussion on: FERC's use of the discounted cash
flow ("DCF") methodology for utilities and pipelines; other financial models
that can be used to determine ROE; and the decisions on use of DCF in the
utility sector that led to issuance of the NOI. The NOI seeks comments on eight
topics and on several technical sub-issues within each topic, including on
whether to apply a single ROE policy across oil pipelines, natural gas pipelines
and utilities. Initial comments were filed on June 26, 2019, and reply comments
were filed July 26, 2019. We will continue to monitor developments in this area.

On July 18, 2018, FERC issued Order No. 849, which adopts procedures to address
the impact of the TCJA and its 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 Order on Rehearing in Docket No.
PL17-1-000, which affirms FERC's position
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in the Revised Policy Statement that eliminated the recovery of an income tax
allowance by master limited partnership ("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 also have sought judicial review of the Revised Policy
Statement, and that challenge, initially filed in March 2019, is pending in the
U.S. Court of Appeals for the D.C. Circuit.

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 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.

We believe that FERC's recent decisions, 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, 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 regarding changes to the oil pipeline rate index
methodology and data reporting on Page 700 of FERC's Form No. 6. In an effort to
improve FERC's ability to ensure that oil pipeline rates are just and reasonable
under the ICA, FERC is considering making the following changes to their current
indexing methodologies for oil pipelines:
1) Deny index increases for any pipeline whose Form No. 6, Page 700 revenues
exceed costs by 15% for both of the prior two years;
2) Deny index increases that exceed by 5% the cost changes reported on Page 700;
and
3) Apply the new criteria to costs more closely associated with the pipeline's
proposed rates than with total company-wide costs and revenues now reported on
Page 700.
Initial comments were filed on January 19, 2017, and reply comments were filed
on March 17, 2017, and, on February 14, 2020, FERC issued a meeting notice
indicating that it intends to act on the proposed rulemaking during a meeting
currently scheduled for February 20, 2020. We will continue to monitor
developments in this area.

Acquisition Opportunities
We plan to continue to pursue acquisitions of complementary assets from Shell,
as well as from third parties. Since our initial public offering, we have
acquired approximately $5,700 million of assets from Shell and its affiliates.
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 will 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 capital markets.
However, we
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believe our balance sheet offers us flexibility, providing us other financing
options such as hybrid securities, purchases of common units by our sponsor and
debt.

Results of Operations
                                                      2019                 2018                2017
Revenue (1)                                       $      503          $       525          $      470
Costs and expenses
Operations and maintenance (1)                           124                  162                 150
Cost of product sold (1)                                  36                   32                   -
Loss (gain) from revision of ARO and disposition
of fixed assets                                            2                   (3)                  -
General and administrative                                60                   60                  58
Depreciation, amortization and accretion                  49                   46                  45
Property and other taxes                                  17                   16                  17
Total costs and expenses (1)                             288                  313                 270
Operating income                                         215                  212                 200
Income from equity method investments                    373                  235                 187
Dividend income from other investments                    14                   67                  37
Other income                                              36                   31                   -
Investment, dividend and other income                    423                  333                 224
Interest expense, net                                     92                   62                  32
Income before income taxes                               546                  483                 392
Income tax expense                                         -                    1                   -
Net income                                               546                  482                 392
Less: Net income attributable to the Parent                -                    -                  77
Less: Net income attributable to noncontrolling
interests                                                 18                   18                  20

Net income attributable to the Partnership $ 528 $

   464          $      295
General partner's interest in net income
attributable to the Partnership                   $      147          $       134          $       64
Limited Partners' interest in net income
attributable to the Partnership                   $      381          $       330          $      231
Adjusted EBITDA attributable to the Partnership
(2)                                               $      730          $       616          $      380
Cash available for distribution attributable to
the Partnership (2)                               $      619          $     

536 $ 360

(1) As a result of the adoption of the revenue standard effective January 1,
2018, amounts prior to adoption have not been adjusted under the modified
retrospective method and continue to be reported in accordance with our historic
accounting under previous GAAP.
(2) For a reconciliation of Adjusted EBITDA and Cash available for distribution
attributable to the Partnership to their most comparable GAAP measures, please
read "-Reconciliation of Non-GAAP Measures."




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Pipeline throughput (thousands of barrels per day) (1)     2019         2018         2017
Zydeco - Mainlines                                          657          623          611
Zydeco - Other segments                                     267          249          359
Zydeco total system                                         924          872          970
Amberjack total system                                      362          324          256
Mars total system                                           546          516          469
Bengal total system                                         511          539          581
Poseidon total system                                       265          235          254
Auger total system                                           77           58           60
Delta total system                                          258          228          219
Na Kika total system                                         39           42           39
Odyssey total system                                        145          115          116
Colonial total system                                     2,617        2,616        2,536
Explorer total system                                       650          649          612
LOCAP total system                                        1,172        1,228        1,228
Other systems                                               348          344          322

Terminals (2) (3) Lockport terminaling throughput and storage volumes 228 226 181

Revenue per barrel ($ per barrel)
Zydeco total system (4)                                  $ 0.52       $ 0.74       $ 0.66
Amberjack total system (4)                                 2.37         2.50         2.43
Mars total system (4)                                      1.31         1.19         1.41
Bengal total system (4)                                    0.41         0.34         0.34
Auger total system (4)                                     1.43         1.34         1.12
Delta total system (4)                                     0.58         0.57         0.54
Na Kika total system (4)                                   0.80         0.79         0.72
Odyssey total system (4)                                   0.92         0.88         0.90
Lockport total system (5)                                  0.22         0.21            0.25


(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.
(2) Terminaling throughput is defined as the volume of delivered barrels and
storage is defined as the volume of stored barrels.
(3) 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 throughput.
(4) 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.
(5) 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.


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Reconciliation of Non-GAAP Measures
The following tables present a reconciliation of Adjusted EBITDA and cash
available for distribution 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.

                                                            2019               2018                2017

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income Net income

$     546          $      482          $     392
Add:
Loss (gain) from revision of ARO and disposition of
fixed assets                                                    2                  (3)                 -
Allowance oil reduction to net realizable value                 1                   5                  -
Depreciation, amortization and accretion                       49                  46                 45
Interest expense, net                                          92                  62                 32
Income tax expense                                              -                   1                  -
Cash distribution received from equity method
investments                                                   466                 301                199

Less:

Equity method distributions included in other income           33                  24                  -
Income from equity method investments                         373                 235                187
Adjusted EBITDA                                               750                 635                481

Less:

Adjusted EBITDA attributable to Parent                          -                   -                 80
Adjusted EBITDA attributable to noncontrolling
interests                                                      20                  19                 21
Adjusted EBITDA attributable to the Partnership               730                 616                380

Less:

Net interest paid attributable to the Partnership (1) 92

        62                 32
Income taxes paid attributable to the Partnership               -                   -                  -

Maintenance capex attributable to the Partnership (2) 28

        25                 28

Add:

Net adjustments from volume deficiency payments
attributable to the Partnership                               (10)                 (4)                 5
Reimbursements from Parent included in partners'
capital                                                        19                  11                 16

April 2017 divestiture attributable to the Partnership -

         -                 19

Cash available for distribution attributable to the Partnership

$     619

$ 536 $ 360

(1) Amount represents both paid and accrued interest attributable to the period.
(2) Effective April 1, 2017, the amount is inclusive of cash paid during the
period, as well as accruals incurred for work performed during the period.












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                                                             2019               2018               2017
Reconciliation of Adjusted EBITDA and Cash Available for
Distribution to Net Cash Provided by Operating
Activities
Net cash provided by operating activities                $     597          $     507          $     432
Add:
Interest expense, net                                           92                 62                 32
Income tax expense                                               -                  1                  -
Return of investment                                            66                 48                 18
Less:
Change in deferred revenue and other unearned income           (11)                (4)                 6
 Non-cash interest expense                                       1                  1                  -
Allowance oil reduction to net realizable value                  1                  5                  -
Change in other assets and liabilities                          14                (19)                (5)
Adjusted EBITDA                                                750                635                481

Less:

Adjusted EBITDA attributable to Parent                           -                  -                 80

Adjusted EBITDA attributable to noncontrolling interests 20

        19                 21
Adjusted EBITDA attributable to the Partnership                730                616                380

Less:

Net interest paid attributable to the Partnership (1)           92                 62                 32
Income taxes paid attributable to the Partnership                -                  -                  -
Maintenance capex attributable to the Partnership (2)           28                 25                 28

Add:

Net adjustments from volume deficiency payments
attributable to the Partnership                                (10)                (4)                 5

Reimbursements from Parent included in partners' capital 19

        11                 16
April 2017 divestiture attributable to the Partnership           -                  -                 19

Cash available for distribution attributable to the Partnership

$     619

$ 536 $ 360

(1) Amount represents both paid and accrued interest attributable to the period.
(2) Effective April 1, 2017, the amount is inclusive of cash paid during the
period, as well as accruals incurred for work performed during the period.
























                                       62

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The following discussion includes a comparison of our Results of Operations and
Capital Resources and Liquidity - Cash Flows from Our Operations for 2019 and
2018. A discussion of changes in our Results of Operations and Capital Resources
and Liquidity - Cash Flows from Our Operations from 2017 to 2018 has been
omitted from the Form 10-K, but may be found in Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations of our Form 10-K
for the year ended December 31, 2018, filed with the SEC on February 21, 2019.

2019 Compared to 2018

Revenues
Total revenue decreased by $22 million in 2019 as compared to 2018, comprised of
$31 million attributable to transportation, terminaling and storage services
revenue, partially offset by an increase of $9 million attributable to product
revenue.

Transportation services revenue decreased primarily due to certain committed
contracts that expired either at the end of 2018 or during 2019, as well as
planned turnaround activity and the impact of Hurricane Barry. The decrease in
revenue was partially offset by lower revenues in 2018 due to the impact of
Zydeco being out of service for 49 days as a result of hydro-testing in 2018.
Further, revenue increased related to improved volumes at certain connected
production facilities in 2019, primarily those that were negatively impacted in
2018 as a result of unplanned maintenance.

Terminaling services revenue, as well as the portion of transportation services
revenue related to the non-lease service component of certain of our
transportation services agreements, was relatively flat. Storage revenue and
lease revenue were also relatively consistent in 2019 and 2018.

Product revenue increased in 2019 versus 2018 and relates to sales of allowance oil for certain of our onshore and offshore crude pipelines.

Costs and Expenses
Total costs and expenses decreased $25 million in 2019 primarily due to $38
million in lower operations and maintenance expenses. This decrease was
partially offset by $4 million of higher cost of product sold due to more
allowance oil sales in 2019 and a net realizable value adjustment on allowance
oil inventory, a $5 million higher loss on revision of asset retirement
obligation, $3 million of additional depreciation expense and $1 million in
higher property taxes due to changes in property tax appraisal estimates.

Operations and maintenance expenses decreased primarily due to the impact in
2018 of Zydeco being out of service for 49 days as a result of hydro-testing, as
well as a larger gain on pipeline operations in 2019. This decrease was
partially offset by an increase in insurance expense.

General and administrative expenses were flat.

Investment, Dividend and Other Income
Investment, dividend and other income increased $90 million in 2019 as compared
to 2018. Income from equity method investments increased by $138 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 Amberjack in May 2018. Additionally, there was higher income from
Mars and Amberjack as a result of increased production from several fields in
the Gulf of Mexico. Other income increased by $5 million primarily related to
distributions from Poseidon, partially offset by higher business continuity
insurance proceeds received in 2018 than in 2019 in connection with the fire at
the Enchilada platform impacting Auger. These increases were partially offset by
a decrease in dividend income from other investments of $53 million due to the
change in accounting for Explorer and Colonial as equity method investments
rather than other investments following the acquisition of additional interests
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.

Interest Expense Interest expense increased by $30 million due to additional borrowings outstanding under our credit facilities during 2019 versus 2018.

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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. Our liquidity as of December 31, 2019 was $1,186
million consisting of $290 million cash on hand and $896 million available
capacity under our revolving credit facilities.

On August 1, 2019, Zydeco entered into a senior unsecured revolving loan
facility agreement with STCW, effective August 6, 2019 (the "2019 Zydeco
Revolver"). The 2019 Zydeco Revolver has a borrowing capacity of $30 million and
matures on August 6, 2024. Borrowings under the credit facility bear interest at
the three-month LIBOR rate plus a margin or, in certain instances, including if
LIBOR is discontinued, STCW may specify another benchmark rate generally
accepted in the loan market to apply in relation to the advances in place of
LIBOR. No issuance fee was incurred in connection with the 2019 Zydeco Revolver.

On June 4, 2019, we entered into the Ten Year Fixed Facility, which bears an
interest rate of 4.18% per annum and matures on June 4, 2029. No issuance fee
was incurred in connection with the Ten Year Fixed Facility. The Ten Year Fixed
Facility contains customary representations, warranties, covenants and events of
default, the occurrence of which would permit the lender to accelerate the
maturity date of amounts borrowed under the Ten Year Fixed Facility. The Ten
Year Fixed Facility was fully drawn on June 6, 2019 to partially fund the June
2019 Acquisition.

On December 21, 2018, we and our general partner executed the Second Amendment
to the Partnership's First Amended and Restated Agreement of Limited Partnership
dated November 3, 2014. Under the Second Amendment, our sponsor agreed to waive
$50 million of distributions in 2019 by agreeing to reduce distributions to
holders of the incentive distribution rights 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.

During 2018, we negotiated with STCW to increase our borrowing capacity by $600
million through the addition of the Seven Year Fixed Facility effective July 31,
2018. The Seven Year Fixed Facility was fully drawn on August 1, 2018 and the
borrowings were used to partially repay borrowings under the Five Year Revolver
due December 2022.

Additionally, on August 1, 2018, we amended and restated the Five Year Revolver
due October 2019 such that the facility will now mature on July 31, 2023 and is
now referred to as the Five Year Revolver due July 2023.

Credit Facility Agreements
As of December 31, 2019, we have entered into the following credit facilities:

                                                                   Current Interest
                                         Total Capacity                 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                       2.93  %                  July 31, 2023
Five Year Revolver due December                                                                      December 1, 2022
2022                                               1,000                       2.94  %
Five Year Fixed Facility                             600                       3.23  %                  March 1, 2022
2019 Zydeco Revolver (1)                              30                       2.59  %                 August 6, 2024

(1) Effective August 6, 2019, the Zydeco Revolver expired. In its place, Zydeco entered into the 2019 Zydeco Revolver. See above for additional information.

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, other interest rate alternatives as described in each respective
revolver. Our weighted average interest rate for 2019 and 2018 was 3.8% and
3.5%, 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
                                       64
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interest rate on the total variable rate debt of $894 million as of December 31,
2019 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.

As of December 31, 2019 and 2018, we were in compliance with the covenants contained in our credit facilities, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.

For definitions and additional information on our credit facilities, refer to
Note 8 - Related Party Debt in the Notes to Consolidated Financial Statements
included in Part II, Item 8 of this report.
Equity Issuances
On June 6, 2019, in connection with the June 2019 Acquisition, we issued
9,477,756 common units to Shell Midstream LP Holdings LLC, an indirect
subsidiary of Shell. In connection with the issuance of the common units, we
issued 193,424 general partner units to the general partner in order to maintain
its 2% general partner interest in us. The non-cash equity consideration from
this issuance was valued at $200 million pursuant to the May 2019 Contribution
Agreement and was used to partially fund the June 2019 Acquisition.

On February 6, 2018, we completed the sale of 25,000,000 common units in a
registered public offering for approximately $673 million net proceeds.
Additionally, we completed the sale of 11,029,412 common units in a private
placement with Shell Midstream LP Holdings LLC, an indirect subsidiary of Shell,
for an aggregate purchase price of $300 million. See Note 11 - (Deficit) Equity
in the Notes to Consolidated Financial Statements included in Part II, Item 8
for additional information.

Cash Flows from Our Operations
Operating Activities. We generated $597 million in cash flow from operating
activities in 2019 compared to $507 million in 2018. The increase in cash flows
was primarily driven by an increase in equity investment income related to the
acquisition of Amberjack in May 2018 and the acquisition of additional interests
in Explorer and Colonial in June 2019, as well as the timing of receipt of
receivables and payment of accruals in 2019.

Investing Activities. Our cash flow used in investing activities was $87 million
in 2019 compared to $511 million in 2018. The decrease in cash flow used in
investing activities was primarily due to a smaller acquisition from Parent in
2019 than 2018, as well as lower capital expenditures, lower contributions to
Permian Basin and a higher return of investment in 2019.

Financing Activities. Our cash flow used in financing activities was $428
million in 2019 compared to cash flow provided by financing activities of $74
million in 2018. The decrease in cash flow provided by financing activities was
primarily due to lower borrowings under credit facilities, increased
distributions paid to the unitholders and our general partner, lower
contributions from our general partner and the lack of net proceeds from equity
offerings in 2019. The decrease in cash flow provided by financing activities
was partially offset by the lack of repayments of credit facilities in 2019, as
well as lower capital distributions to our general partner.

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 $35 million, $51 million and $58 million for
2019, 2018 and 2017, respectively. The decrease in capital expenditures from
2018 to 2019 is primarily due to lower spend on the Houma tank expansion project
for Zydeco, coupled with slightly lower capital contributions to Permian Basin
in 2019.

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

                                                        2019       2018     

2017

Expansion capital expenditures                         $ 10       $ 25       $ 18
Maintenance capital expenditures                         28         24      

40

Total capital expenditures paid                          38         49      

58

(Decrease) increase in accrued capital expenditures (3) 2

-

Total capital expenditures incurred                    $ 35       $ 51       $ 58
Contributions to investment                            $ 25       $ 28       $  -

We expect total capital expenditures to be approximately $46 million for 2020, a summary of which is shown in table below:

Actual Capital

Expenditures Expected Capital Expenditures

                                                                2019                                   2020
Expansion capital expenditures
Zydeco                                             $                     7               $                      2

Total expansion capital expenditures incurred                            7                                      2
Maintenance capital expenditures
Zydeco                                                                  19                                     25
Pecten                                                                   3                                      2
Triton                                                                   6                                      4
Sand Dollar                                                              -                                      2
Odyssey                                                                  -                                      1
Total maintenance capital expenditures incurred                         28                                     34
Contributions to investment                                             25                                     10
Total capital expenditures and investments         $                    60               $                     46

Total expansion capital expenditures in 2019 are related to the Houma tank expansion project on Zydeco, and in 2020 are related to meter upgrades on Zydeco. Additionally, in both 2019 and 2020 there are capital contributions to Permian Basin to fund expansion capital and other expenditures.

Zydeco's maintenance capital expenditures for 2019 were $19 million, primarily
for the directional drill project. In connection with the acquisition of
additional interests in Zydeco, SPLC agreed to reimburse us for our
proportionate share of certain costs and expenses incurred by Zydeco with
respect to the directional drill project. During 2019, we filed claims for
reimbursement from SPLC of $10 million. We expect Zydeco's maintenance capital
expenditures to be approximately $25 million for 2020, of which $16 million is
for a pipeline exposure requiring replacement and $4 million is related to an
upgrade of the motor control center at Houma. The remaining spend is related to
routine maintenance.

Pecten's maintenance capital expenditures for 2019 were $3 million, and we
expect Pecten's maintenance capital expenditures to be approximately $2 million
in 2020. These expenditures relate to electrical improvements at the Lockport
terminal and various improvements on Delta.

Triton's maintenance capital expenditures for 2019 were $6 million. This
includes vapor recovery improvements at the Des Plaines terminal and tank and
facility work at Colex and Des Plaines terminals. We expect Triton's maintenance
capital expenditures to be approximately $4 million in 2020 related to routine
maintenance at the various terminals.

We expect Sand Dollar's maintenance capital expenditures to be approximately $2
million in 2020 related to a hurricane
protection project. We expect Odyssey's maintenance capital expenditures to be
approximately $1 million in 2020 related to routine maintenance.

We anticipate that both maintenance and expansion capital expenditures for 2020 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 for $50 million
consideration and initial capital contributions, we will make capital
contributions for our pro rata interest in Permian Basin to fund capital and
other expenditures, as approved by supermajority (75%) vote of the members. We
have made capital contributions of $25 million in 2019, and expect to make
capital contributions of approximately $10 million in 2020.

Contractual Obligations
A summary of our contractual obligations, as of December 31, 2019, is shown in
the table below (in millions):

                                          Total           Less than 1 year          Years 1 to 3         Years 3 to 5         More than 5 years
Operating leases for land and platform
space                                   $     8          $            -            $         1          $        1           $              6
Finance leases (1)                           61                       5                     10                  10                         36
Other agreements (2)                         41                       6                     12                  12                         11
Debt obligation (3)                       2,694                       -                  1,000                 494                      1,200
Interest payments on debt (4)               506                      97                    176                 108                        125
  Total                                 $ 3,310          $          108            $     1,199          $      625           $          1,378


(1) Finance leases include Port Neches storage tanks and Garden Banks 128 "A"
platform. Finance leases include $27 million in interest, $25 million in
principal and $9 million in executory costs.
(2) Includes a joint tariff agreement and Odyssey tie-in agreement.
(3) See Note 8 - Related Party Debt in the Notes to Consolidated Financial
Statements included in Part II, Item 8 for additional information.
(4) Interest payments were calculated based on rates in effect at December 31,
2019 for variable rate borrowings.
Odyssey entered into an operating lease dated May 12, 1999 with a third party
for usage of offshore platform space at Main Pass 289C. Additionally, Odyssey
entered into a tie-in agreement effective January 2012 with a third party, which
allowed producers to install the tie-in connection facilities and tying into the
system. The agreements will continue to be in effect until the continued
operation of the platform is uneconomic.
On December 1, 2014, we entered into a terminal services agreement with a
related party in which we were to take possession of certain storage tanks
located in Port Neches, Texas, effective December 1, 2015. On October 26, 2015,
the terminal services agreement was amended to provide for an interim in-service
period for the purposes of commissioning the tanks in which we paid a nominal
monthly fee. Our capitalized costs and related capital lease obligation
commenced effective December 1, 2015, and the storage tanks were placed
in-service on September 1, 2016. Under this agreement, in the eighteenth month
after the in-service date, actual fixed and variable costs could be compared to
premised costs. If the actual and premised operating costs differ by more than
5.0%, the lease would be adjusted accordingly and this adjustment will be
effective for the remainder of the lease. No adjustment has been made to date.
The imputed interest rate on the capital portion of the lease is 15.0%.

On September 1, 2016, which is the in-service date of the capital lease for the
Port Neches storage tanks, a joint tariff agreement with a third party became
effective. The tariff will be reviewed annually and the rate updated based on
FERC's indexing adjustment to rates effective July 1 of each year. Effective
July 1, 2019 there was an approximately 4.3% increase to this rate based on
FERC's indexing adjustment. The initial term of the agreement is ten years with
automatic one-year renewal terms with the option to cancel prior to each renewal
period.

Off-Balance Sheet Arrangements
We have not entered into any transactions, agreements or other contractual
arrangements that would result in off-balance sheet liabilities.
Critical Accounting Policies and Estimates
Critical accounting policies are those that are important to our financial
condition and require management's most difficult, subjective or complex
judgments. Different amounts would be reported under different operating
conditions or under alternative assumptions.

We apply those accounting policies that we believe best reflect the underlying
business and economic events, consistent with GAAP. Our more critical accounting
policies include those related to long-lived assets, equity method investments
and revenue
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recognition. Inherent in such policies are certain key assumptions and
estimates. We periodically update the estimates used in the preparation of the
financial statements based on our latest assessment of the current and projected
business and general economic environment. Our significant accounting policies
are summarized in Note 2 - Summary of Significant Accounting Policies in the
Notes to Consolidated Financial Statements included in Part II, Item 8 of this
report. We believe the following to be our most critical accounting policies
applied in the preparation of our financial statements.
Long-Lived Assets
Key estimates related to long-lived assets include useful lives, recoverability
of carrying values and existence of any retirement obligations. Such estimates
could be significantly modified. The carrying values of long-lived assets could
be impaired by significant changes or projected changes in supply and demand
fundamentals of oil, natural gas, refinery gas or refined products (which could
have a negative impact on operating rates or margins), new technological
developments, new competitors, adverse changes associated with the United States
and global economies and with governmental actions. We evaluate long-lived
assets for potential impairment indicators whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable, including when negative conditions such as significant current or
projected operating losses exist. Our judgments regarding the existence of
impairment indicators are based on legal factors, market conditions and the
operational performance of our businesses. Actual impairment losses incurred
could vary significantly from amounts estimated. Long-lived assets assessed for
impairment are grouped at the lowest level for which identifiable cash flows are
largely independent of the cash flows of other assets and liabilities.
Additionally, future events could cause us to conclude that impairment
indicators exist and that associated long-lived assets of our businesses are
impaired. Any resulting impairment loss could have a material adverse impact on
our financial condition and results of operations.

The estimated useful lives of long-lived assets range from five to 40 years.
Depreciation of these assets under the straight-line method over their estimated
useful lives totaled $49 million and $46 million for 2019 and 2018,
respectively. If the useful lives of the assets were found to be shorter than
originally estimated, depreciation charges would be accelerated. Additional
information concerning long-lived assets and related depreciation and
amortization appears in Note 6 - Property, Plant and Equipment in the Notes to
Consolidated Financial Statements included in Part II, Item 8 of this report.
Equity Method Investments
We account for investments where we have the ability to exercise significant
influence, but not control, under the equity method of accounting. Income from
equity method investments represents our proportionate share of net income
generated by the equity method investees. Differences in the basis of the
investments and the separate net asset value of the investees, if any, are
amortized into net income over the remaining useful lives of the underlying
assets. Equity method investments are assessed for impairment whenever changes
in the facts and circumstances indicate a loss in value has occurred, if the
loss is deemed to be other than temporary. When the loss is deemed to be other
than temporary, the carrying value of the equity method investment is written
down to fair value.
Revenue Recognition
We adopted the revenue standard on January 1, 2018. See Note 12 - Revenue
Recognition in the Notes to Consolidated Financial Statements included in Part
II, Item 8 of this report for additional information.

We recognize revenue when we transfer promised goods or services to customers in
an amount that reflects the consideration to which we expect to be entitled in
exchange for those goods or services. We recognize revenue through the
application of a five-step model, which includes: identification of the
contract; identification of the performance obligations; determination of the
transaction price; allocation of the transaction price to the performance
obligations; and recognition of revenue as the entity satisfies the performance
obligations. We generate a portion of our revenue under long-term agreements by
charging fees for the transportation, terminaling and storage of crude oil and
refined products and for the transportation of refinery gas through our assets.
Contract obligations are billed monthly. Transportation revenue is billed as
services are rendered, and we accrue revenue based on nominations for that
accounting month. We estimate this revenue based on contract data, regulatory
information and preliminary throughput and allocation measurements, among other
items. Additionally, we refer to our transportation services agreements and
throughput and deficiency agreements as "ship-or-pay" contracts.

As a result of FERC regulations, revenues we collect may be subject to refund.
We establish reserves for these potential refunds based on actual expected
refund amounts on the specific facts and circumstances. We had no reserves for
potential refunds as of December 31, 2019 and 2018.

The majority of our long-term transportation agreements and tariffs for crude
oil transportation include PLA. PLA is an allowance for volume losses due to
measurement differences set forth in crude oil transportation agreements. PLA is
intended
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to assure proper measurement of the crude oil despite solids, water, evaporation
and variable crude types that can cause mismeasurement. PLA provides additional
revenue for us if product losses on our pipelines are within the allowed levels,
and we are required to compensate our customers for any product losses that
exceed the allowed levels. We take title to any excess loss allowance when
product losses are within the allowed levels, and we sell that product several
times per year at prevailing market prices.

Certain transportation and terminaling services agreements with related parties
are considered operating leases under GAAP. Revenues from these agreements are
recorded within "Lease revenue-related parties" in the accompanying consolidated
statement of income. See Note 12 - Revenue Recognition in the Notes to
Consolidated Financial Statements included in Part II, Item 8 of this report.

Recent Accounting Pronouncements Please read Note 2 - Summary of Significant Accounting Policies - Recent Accounting Pronouncements included in Part II, Item 8 of this report. Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and
prices. With the exception of buy/sell arrangements on some of our offshore
pipelines and our allowance oil retained, we do not take ownership of the crude
oil or refined products that we transport and store for our customers, and we do
not engage in the trading of any commodities. We therefore have limited direct
exposure to risks associated with fluctuating commodity prices.
Our long-term transportation agreements and tariffs for crude oil shipments
include PLA. The PLA provides additional revenue for us at a stated factor per
barrel. If product losses on our pipelines are within the allowed levels we
retain the benefit, otherwise we are required to compensate our customers for
any product losses that exceed the allowed levels. We take title to any excess
product that we transport when product losses are within allowed level, and we
sell that product several times per year at prevailing market prices. This
allowance oil revenue, which accounted for approximately 6% of our total revenue
in each of 2019 and 2018, is subject to more volatility than transportation
revenue, as it is directly dependent on our measurement capability and commodity
prices. As a result, the income we realize under our loss allowance provisions
will increase or decrease as a result of changes in the mix of product
transported, measurement accuracy and underlying commodity prices. We do not
intend to enter into any hedging agreements to mitigate our exposure to
decreases in commodity prices through our loss allowances.
We may also have risk associated with changes in policy or other actions taken
by FERC. Please see Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Factors Affecting our Business and Outlook
- Regulation" for additional information.



Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result
of variable rate borrowings under our revolving credit facilities. To the extent
that interest rates increase, interest expense for these revolvers will also
increase. As of both December 31, 2019 and December 31, 2018, the Partnership
had $894 million in outstanding variable rate borrowings under these revolving
credit facilities. A hypothetical change of 12.5 basis points in the interest
rate of our variable rate debt would impact the Partnership's annual interest
expense by approximately $1 million for both the years ended 2019 and 2018. We
do not currently intend to enter into any interest rate hedging agreements, but
will continue to monitor interest rate exposure.

Our fixed rate debt does not expose us to fluctuations in our results of
operations or liquidity from changes in market interest rates. Changes in
interest rates do affect the fair value of our fixed rate debt. See Note 8 -
Related Party Debt in the accompanying Notes to Consolidated Financial
Statements included in Part II, Item 8 of this report for further discussion of
our borrowings and fair value measurements.

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