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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________________

FORM 10-K
________________________________________________________________
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                     
Commission file number: 001-36710
______________________________________________________________

Shell Midstream Partners, L.P.
(Exact name of registrant as specified in its charter)  
________________________________________________________________
Delaware46-5223743
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
150 N. Dairy Ashford, Houston, Texas 77079
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (832) 337-2034
Securities registered pursuant to Section 12(b) of the Act:

Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Units, Representing Limited Partner InterestsSHLXNew York Stock Exchange
________________________________________________________________
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x  Yes    ¨  No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨  Yes    x  No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x  Yes    ¨  No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). x  Yes    ¨  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerx  Accelerated filer ¨
Non-accelerated filer¨  Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).      Yes    x  No
The aggregate market value of the registrant’s common units held by non-affiliates of the registrant as of June 30, 2020, was $1,518 million, based on the closing price of such units of $12.27 as reported on the New York Stock Exchange on such date. The registrant had 393,289,537 common units and no subordinated units outstanding as of February 22, 2021.
Documents incorporated by reference:
None




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 ongoing 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, including those that may be implemented by the new U.S. presidential administration, 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 of this report.




GLOSSARY OF TERMS
Barrel or bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.
BOEM: Bureau of Ocean Energy Management.
BSEE: Bureau of Safety and Environmental Enforcement.
Capacity: Nameplate capacity.
Common carrier pipeline: A pipeline engaged in the transportation of crude oil, refined products or natural gas liquids as a common carrier for hire.
Crude oil: A mixture of raw hydrocarbons that exists in liquid phase in underground reservoirs.
DOT: Department of Transportation.
EPAct: Energy Policy Act of 1992.
Expansion capital expenditures: Expansion capital expenditures are cash expenditures (including transaction expenses) for capital improvements. Expansion capital expenditures do not include maintenance capital expenditures or investment capital expenditures. Expansion capital expenditures do include interest payments (including periodic net payments under related interest rate swap agreements) and related fees paid during the construction period on construction debt. Where cash expenditures are made in part for expansion capital expenditures and in part for other purposes, our general partner determines the allocation between the amounts paid for each.
FERC: Federal Energy Regulatory Commission.
GAAP: United States generally accepted accounting principles.
HCAs: High Consequence Areas.
ICA: Interstate Commerce Act of 1887, as modified by the Elkins Act.
kbpd: Thousand barrels per day.
kbls: Thousand barrels.
klbs/d: Thousand pounds per day.
Life-of-lease transportation agreement: A contract in which the producer dedicates shipments of all current and future reserves pertaining to a specific lease or area to a specific carrier.
LNG: Liquefied natural gas.
LPSC: Louisiana Public Service Commission.
LTIP: Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan.
Maintenance capital expenditures: Maintenance capital expenditures are 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.
mscf/d: Million standard cubic feet per day.
Partnership Agreement: Second Amended and Restated Agreement of Limited Partnership of Shell Midstream Partners, L.P., dated as of April 1, 2020.
PHMSA: Pipeline and Hazardous Materials Safety Administration.
Pipeline loss allowance or PLA: An allowance for volume losses due to measurement difference set forth in crude oil product transportation agreements, including long-term transportation agreements and tariffs for crude oil shipments.
Refined products: Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residual fuel that are produced by a refinery.
Refinery gas: Non-condensable gas obtained during distillation of crude oil or treatment of oil products in refineries.
Ship-or-pay contract: A contract requiring payment for the transportation of crude oil or refined products even if the crude oil or refined products are not transported.
Throughput: The volume of crude oil, refined products or natural gas transported or passing through a refinery, pipeline, terminal or other facility during a particular period.
TRRC: Texas Railroad Commission.







































SHELL MIDSTREAM PARTNERS, L.P.
TABLE OF CONTENTS
 
ItemPage
 



 PART I
 
 
Unless the context otherwise requires, references in this report to “Shell Midstream Partners,” “the Partnership,” “us,” “our,” “we,” “SHLX” or similar expressions refer to Shell Midstream Partners, L.P. and its subsidiaries. References to “our general partner” refer to Shell Midstream Partners GP LLC, a wholly owned subsidiary of Shell Pipeline Company LP (“SPLC”). 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.

Part I should be read in conjunction with Part II, Item 7 and with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.

Items 1 and 2. BUSINESS AND PROPERTIES
Overview

Shell Midstream Partners, L.P. is a Delaware limited partnership formed by Shell on March 19, 2014 to own and operate pipeline and other midstream assets, including certain assets acquired from SPLC and its affiliates. We conduct our operations either through our wholly owned subsidiary Shell Midstream Operating LLC (“Operating Company”) or through direct ownership. Our general partner is Shell Midstream Partners GP LLC (our “general partner”).

Until April 1, 2020, our general partner owned an approximate 2% general partner economic interest in the Partnership, including the incentive distribution rights (“IDRs”). On April 1, 2020, we closed the transactions contemplated by the Partnership Interests Restructuring Agreement with our general partner dated February 27, 2020 (the “Partnership Interests Restructuring Agreement”), pursuant to which the IDRs were eliminated and the 2% general partner economic interest was converted into a non-economic general partner interest in the Partnership. As of December 31, 2020, our general partner holds a non-economic general partner interest in the Partnership, and affiliates of SPLC own a 68.5% limited partner interest (269,457,304 common units) and 50,782,904 Series A perpetual convertible preferred units (the “Series A Preferred Units”) in the Partnership. These common units and preferred units, on an as-converted basis, represent a 72% interest in the Partnership.

We own, operate, develop and acquire pipelines and other midstream and logistics assets. As of December 31, 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. The Partnership’s 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.

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 certain logistics assets. Our operations consist of one reportable segment. See Note 1 — Description of the Business and Basis of Presentation in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.

















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The following table reflects our ownership interests as of December 31, 2020:

SHLX Ownership
Pecten Midstream LLC (“Pecten”)100.0 %
Sand Dollar Pipeline LLC (“Sand Dollar”)100.0 %
Triton West LLC (“Triton”)100.0 %
Zydeco Pipeline Company LLC (“Zydeco”) (1)
92.5 %
Mattox Pipeline Company LLC (“Mattox”)79.0 %
Amberjack Pipeline Company LLC (“Amberjack”) – Series A/Series B75.0% / 50.0%
Mars Oil Pipeline Company LLC (“Mars”)71.5 %
Odyssey Pipeline L.L.C. (“Odyssey”)71.0 %
Bengal Pipeline Company LLC (“Bengal”)50.0 %
Crestwood Permian Basin LLC (“Permian Basin”)50.0 %
LOCAP LLC (“LOCAP”)41.48 %
Explorer Pipeline Company (“Explorer”)38.59 %
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)36.0 %
Colonial Enterprises, Inc. (“Colonial”)16.125 %
Proteus Oil Pipeline Company, LLC (“Proteus”)10.0 %
Endymion Oil Pipeline Company, LLC (“Endymion”)10.0 %
Cleopatra Gas Gathering Company, LLC (“Cleopatra”)1.0 %
(1) SPLC owns the remaining 7.5% ownership interest in Zydeco.

Acquisitions
April 2020 Transaction

On April 1, 2020, we closed the following transactions (together referred to as the “April 2020 Transaction”):

Pursuant to a Purchase and Sale Agreement dated as of February 27, 2020 (the “Purchase and Sale Agreement”) between the Partnership and 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”), we acquired 79% of the issued and outstanding membership interests in Mattox from SGOM (the “Mattox Transaction”), and 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 (such assets, the “Norco Assets,” and such transaction, the “Norco Transaction”); and
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 pursuant to which we eliminated all of the IDRs and converted the 2% economic general partner interest in the Partnership into a non-economic general partner interest (the “GP/IDR Restructuring”). Our 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 each of four consecutive fiscal quarters, beginning with the distribution made with respect to the second quarter of 2020.

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.

See Note 3 — Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements in Part II, Item 8 of this report for additional information.
Organizational Structure
The following simplified diagram depicts our organizational structure as of December 31, 2020:
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shlx-20201231_g1.jpg

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Our Assets and Operations
Our assets consist of the following systems:

shlx-20201231_g2.jpg
Onshore Crude Pipelines

Our onshore crude pipelines transport various grades of crude oil across more than 500 miles. Our onshore crude pipelines serve varying purposes including transporting crude oil between major onshore demand centers, as well as aggregating volume from multiple offshore pipelines and connecting this offshore production to key onshore markets, including refineries and tankage space. These pipelines are regulated by PHMSA for safety and integrity, and the FERC, LPSC and TRRC for tariff regulations.

Our onshore crude pipelines transport volumes on a spot basis, as well as under transportation services and throughput and deficiency agreements (“T&D agreements”). In compliance with FERC indexing adjustments, our rates may be indexed annually.

Our FERC-approved transportation services agreements entitle the customer to a specified amount of guaranteed capacity on the pipeline. This capacity cannot be pro-rated even if the pipeline is oversubscribed. In exchange, the customer makes a specified monthly payment regardless of the volume transported. If the customer does not ship its full guaranteed volume in a given month, it makes the full monthly cash payment, and it may ship the unused volume in a later month for no additional cash payment for up to 12 months, subject to availability on the pipeline. The cash payment received is recognized as deferred revenue, and therefore not included in revenue or net income until the earlier of the actual or estimated shipment of the unused volumes or the expiration of the 12-month period, as provided for in the applicable contract. If there is insufficient capacity on the pipeline to allow the unused volume to be shipped, the customer forfeits its right to ship such unused volume. We do not refund any cash payments relating to unused volumes.

T&D agreements, similar to transportation services agreements, require shippers to commit to a minimum volume for a fixed term. If the shipper falls below the minimum volume for the specified term, it is required to make a payment for the volume deficiency at the agreed transportation rate. Because this payment is due at the end of the specified payment term, the timing of
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cash flows may be affected. Unlike transportation services agreements, T&D agreements do not offer shippers firm space on the pipeline in question, and, if a segment of the pipeline system is oversubscribed, space is prorated in accordance with applicable regulations.

See “— Factors Affecting our Business and Outlook — Changes in Customer Contracting” for additional information on our transportation services and T&D agreements.

Offshore Crude Pipelines

The offshore crude pipelines in which we own interests span across approximately 1,500 miles, and are regulated primarily by PHMSA, BSEE or BOEM, and in some cases by FERC or LPSC. Our offshore crude pipelines provide transportation for major oil producers and from multiple production fields in the Gulf of Mexico, offering delivery options into various pipelines, in which we may also own interests. Through the pipeline connectivity options, these pipelines provide access to desirable onshore destinations, including trading hubs and refinery complexes.

Our offshore crude pipelines generate revenue under several types of long-term transportation agreements: life-of-lease transportation agreements, life-of-lease transportation agreements with a guaranteed return, T&D agreements, debottleneck surcharge agreements and buy/sell agreements. Some crude oil also moves on our offshore pipelines under posted tariffs, which may be indexed annually. Inventory management fees are also charged in some cases.

Our life-of-lease transportation agreements have a term equal to the life of the applicable mineral lease and require producers to transport all production from the specified fields connected to the pipeline for the entire life of the lease. This means that the dedicated production cannot be transported by any other means, such as barges or another pipeline. Some of these agreements can also include provisions to guarantee a return to the pipeline, enabling the pipeline to recover its investment in the initial years despite the uncertainty in production volumes, by providing for an annual transportation rate adjustment over a fixed period of time to achieve a fixed rate of return. The calculation for the fixed rate of return is usually based on actual project costs and operating costs. At the end of the fixed period, some rates will be locked in at the last calculated rate and adjusted thereafter based on FERC’s index.

Our offshore T&D agreements require shippers to dedicate production from specific fields for a fixed term, generally for life of the facility or lease. In addition, some T&D agreements require a minimum volume to be delivered for a fixed term. If the producer falls below the minimum volume for the specified term, they are required to make a payment for the volume deficiency at the agreed transportation rate. T&D agreements may, but typically do not, offer firm space on the pipeline in question. If a segment of the pipeline system is oversubscribed, space is prorated in accordance with the then-published rules and regulations of the pipeline.

Certain offshore systems provide for the transportation of crude oil through the use of buy/sell arrangements where crude is purchased at the receipt location into the pipeline and sold back to the counterparty at the destination at that price plus a transportation differential. Other systems provide for the transportation of crude oil via private Oil Transportation Agreements (“OTAs”). These OTAs are a mix of term and life-of-lease transportation agreements.

Refined Products Pipelines

We own interests in several refined products pipeline systems across approximately 7,400 miles spanning from the Gulf Coast to both the Midwest and the East Coast. These pipeline systems are regulated primarily by PHMSA and FERC and transport refined products with many different specifications and for numerous shippers. The refined products pipelines connect refineries to both long-haul transportation pipelines and marketing terminals. These pipelines serve a diverse set of customers, including refiners, marketers, airports and airlines.

These refined products pipeline systems generate revenue under various types of rates and contracts, including ship-or-pay contracts that are renewable at the election of the shipper and may be indexed annually, joint tariff division agreements, FERC-approved rates subject to annual indexing and market-based rates. Additionally, there is an auction program on one system for certain excess capacity when the pipeline is fully subscribed.

Terminals and Storage
We own an interest in certain logistics assets in Louisiana, as well as interests in refined products and crude terminals located in Washington, Texas, Illinois and Oregon.
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Our logistics assets are comprised of crude, chemicals, intermediate and finished product pipelines, storage tanks, docks, truck and rail racks and supporting infrastructure. We generate revenue on these assets pursuant to terminaling services agreements with related parties, which are treated as a failed sale leaseback for accounting purposes.

Our refined products terminals receive refined products from pipelines and, in certain cases, barges, ships or railroads, and distribute them to third parties, who in turn deliver them to end-users and retail outlets. These terminals play a key role in moving products to the end-user market by providing efficient product receipt, storage and distribution capabilities, inventory management, ethanol and biodiesel blending, and other ancillary services that include the injection of various additives. For each of these terminals, revenue, based on throughput, is generated via a single, long-term, terminaling services agreement with a related party, which is treated as an operating lease for accounting purposes. Each agreement provides for a guaranteed minimum throughput. The contracts initially expire on November 30, 2027 with an option to extend the agreement for ten additional one-year terms.

Our crude terminal feeds regional refineries and offers strategic trading opportunities by providing storage services for several customers and supplying refineries. Our storage tanks are 100% utilized via four terminal services agreements with remaining terms ranging from one to four years.

Other Midstream Assets

We have interests in certain other midstream assets. We own an interest in a network of gas pipelines connecting multiple refineries and plants operated along the Gulf Coast to Shell chemical sites. The pipelines transport refinery gas which is a mix of methane, natural gas liquids and olefins. This system generates revenue under transportation services agreements that include minimum revenue commitments and are treated as operating leases for accounting purposes. The contracts require a specified monthly payment regardless of volume shipped, and shippers do not receive a credit for unused volume in a given month to use in future months.

We also own interests in gas gathering systems that provide gathering and transportation for multiple gas producers and third-party gas shippers.

Additionally, our interest in a pipeline that connects the LOOP Clovelly Salt Dome storage facility to the active trading hub of St. James, Louisiana allows for crude oil arriving at the terminal to be dispatched to several local refineries or to other pipeline systems.

Pipeline and Terminal Systems Capacity

The following table sets forth certain information regarding our pipeline and terminal systems as of December 31, 2020:
 
Pipeline System/Terminal System
Approximate Capacity
(kbpd) (2)
Approximate Tank Storage Capacity
(kbls)
Onshore Crude Oil Pipelines
Zydeco crude oil system - Mainlines
Houston to Port Neches250
Port Neches to Houma375
Houma to Clovelly425
Houma to St James270
Delta crude oil system420
Offshore Crude Oil Pipelines
Amberjack crude oil system
Jack St. Malo200
Tahiti300
ADP 24”300
Jackalope200
Genesis50
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Ewing Banks 91020
Auger crude oil system
Enchilada Platform to Eugene Island 31535
Enchilada Platform to Ship Shoal 28P200
14/16" Auger export line150
Na Kika crude oil system160
Mars crude oil system (1)
Mars TLP to West Delta 143100
Olympus TLP to West Delta 143100
West Delta 143 to Fourchon400
Fourchon to Clovelly600
Poseidon crude oil system350
Odyssey crude oil system220
Mattox crude oil system300
Proteus crude oil system
Thunder Horse TLP to South Pass 89E425
Endymion crude oil system
South Pass 89E to Clovelly425
Refined Products Pipelines
Bengal product system
Norco to Baton Rouge tank farm305
Colonial product system2,500
Explorer product system660
Terminals and Storage
Triton refined products terminals (2)
Anacortes
Colex2,585
Des Plaines1,060
Portland405
Seattle520
Norco Assets (3)
10,800
Lockport terminal system2,000
Other Midstream Assets
Refinery Gas Pipelines (4)
Houston Ship Channel3,960
Texas City5,280
Garyville - Norco3,720
Convent to Garyville (5)
3,840
Norco - Paraffinic3,720
Permian Basin gas gathering system (4)
240
LOCAP pipeline system and storage facility1,7003,200
Cleopatra gas gathering system (4)
Atlantis TLP to Ship Shoal 332A500
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(1) In addition to the pipeline capacity above, Mars also has storage capacity leases of storage caverns with a related party.
(2) The Anacortes, Des Plaines, Portland and Seattle refined products terminals have truck racks that are not included in the above table. The Anacortes refined products terminal does not have tank storage.
(3) The capacity for the Norco Assets shown above is comprised of 104 tanks. The Norco Assets also include associated pipelines, docks, trucks and rail racks that are not included in the above table.
(4) The approximate capacity information presented is in kbpd with the exception of the approximate capacity related to Cleopatra gas
gathering system and Permian Basin, which are presented in mscf/d, and Refinery Gas Pipeline, which is presented in klbs/d.
(5) This capacity may change as a result of the recent shutdown of the Convent refinery.

Our Relationship with Shell
Shell is one of the world’s largest independent energy companies in terms of market capitalization and operating cash flow, and Shell and its joint ventures are a leading producer and transporter of onshore and offshore hydrocarbons, as well as a major refiner in the United States. As one of the largest producers in the Gulf of Mexico, Shell is currently developing several deepwater prospects and associated infrastructure. In addition to its offshore production, Shell has significant onshore exploration and production interests and produces crude oil and natural gas throughout North America. Shell’s downstream portfolio includes interests in refineries and chemical processing plants throughout the United States. Shell’s portfolio of midstream assets provides key infrastructure required to transport and store crude oil and refined products for Shell and third parties. Shell’s ownership interests in transportation and midstream assets include crude oil and refined products pipelines, crude oil and refined products terminals, chemicals pipelines, natural gas pipelines and processing plants and LNG infrastructure assets. Shell or its affiliates are customers of most of our businesses.
SPLC is Shell’s principal midstream subsidiary in the United States. As of December 31, 2020, SPLC owned our general partner, a 68.5% limited partner interest in us and all of our Series A Preferred Units.
Customers
See Note 14 — Transactions with Major Customers and Concentration of Credit Risk in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.
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-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 contracted our capacity.
Competition among onshore common carrier crude oil pipelines is based primarily on posted tariffs, quality of customer service and connectivity to sources of supply and demand. We believe that our position along the Gulf Coast provides a unique level of service to our customers. Our pipelines and terminals face competition from a variety of alternative transportation methods including rail, water borne movements (including barging, shipping and imports) and other pipelines that service the same origins or destinations as our pipelines.
Our offshore crude oil pipelines are primarily supported by life-of-lease transportation agreements or direct connected production, which bears high switching costs in the form of capital investment or volume dedications. However, our offshore pipelines will compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation rates and access to preferred onshore markets. The principal competition for our offshore pipelines include other crude oil pipeline systems, as well as producers who may elect to build or utilize their own production handling facilities. In addition, the ability of our offshore pipelines to access future oil and gas reserves will be subject to our ability, or the producers’ ability, to fund the capital expenditures required to connect to the new production. In general, our offshore pipelines are not subject to regulatory rate-making authority, and the rates our offshore pipeline charges for services are dependent on market conditions.
Competition for refined product transportation in any particular area is affected significantly by the end market demand for the volume of products produced by refineries in that area, the availability of products in that area and the cost of transportation to
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that area from distant refineries. In light of current market conditions, we expect greater competition in the markets in which we provide refined product transportation.
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.
See “Management's Discussion and Analysis of Financial Condition and Results of Operations — Factors Affecting Our Business and Outlook” for additional information.
FERC and State Common Carrier Regulations
Our interstate common carrier and intrastate pipeline systems are subject to economic regulation by various federal, state and/or local agencies.
FERC regulates interstate transportation on our common carrier pipeline systems under the ICA, the EPAct and the rules and regulations promulgated under those laws. FERC regulations require that rates and terms and conditions of service for interstate service pipelines that transport crude oil and refined products (collectively referred to as “petroleum pipelines”) and certain other liquids be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC’s regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.

Under the ICA, FERC or interested persons may challenge existing or proposed new or changed rates, services or terms and conditions of service. FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. Under certain circumstances, FERC could limit a common carrier pipeline’s ability to charge rates until completion of an investigation during which FERC could find that the new or changed rate is unlawful. In contrast, FERC has clarified that initial rates and terms of service agreed upon with non-affiliated committed shippers in a transportation services agreement are not subject to protest or a cost-of-service analysis where the pipeline held an open season offering all potential shippers service on the same terms. In the case where there are only affiliated committed shippers, rates need to be justified on a cost-of-service basis.
A successful rate challenge could result in a common carrier pipeline paying refunds of revenue collected in excess of the just and reasonable rate, together with interest for the period the rate was in effect, if any. FERC may also order a pipeline to reduce its rates prospectively, and may require a common carrier pipeline to pay shippers reparations retroactively for rate overages for a period of up to two years prior to the filing of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust or unreasonable or unduly discriminatory or preferential.

From November 2017 through 2020, twelve separate, nearly identical complaints were filed with FERC against Colonial challenging Colonial’s tariff rates, its market power, its practices and charges related to transmix and product volume loss. These complaints have been consolidated by FERC in Docket Nos. OR18-7-002, et al. and were set for hearing and settlement judge procedures. FERC also severed the review of Colonial’s market-based rates into a separate, concurrent hearing. On May 2, 2019, the Chief Administrative Law Judge terminated settlement judge procedures and established a procedural schedule for a hearing before an administrative law judge. The hearing took place in the latter part of 2020 and an initial decision from the administrative law judge is currently scheduled for August 2021, with a FERC decision anticipated by spring 2022. Since the consolidated complaint proceedings are ongoing, FERC has not taken any final action on the complaints, and the outcome is not known at this time.
Additionally, EPAct deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA. These rates are commonly referred to as “grandfathered rates.” For example, Colonial’s rates in effect at the time of the passage of EPAct for interstate transportation service were deemed just and reasonable and therefore are grandfathered. New rates have since been established after EPAct for certain grandfathered pipeline systems such as Zydeco. FERC may change grandfathered rates upon complaint only after it is shown that:

a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate;
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the complainant was contractually barred from challenging the rate prior to enactment of EPAct and filed the complaint within 30 days of the expiration of the contractual bar; or
a provision of the tariff is unduly discriminatory or preferential.

EPAct required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the U.S. Producer Price Index for Finished Goods (“PPI-FG”). The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. FERC’s indexing methodology is subject to review every five years. As a result of its prior five-year review, FERC revised its indexing methodology and determined that, during the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG plus 1.23%. In May 2020, Zydeco, Mars, LOCAP and Colonial filed with FERC to increase rates subject to FERC’s indexing adjustment methodology by approximately 2.0% starting on July 1, 2020. FERC commenced the current five-year review of its indexing methodology in June 2020. FERC reviewed the pipeline cost changes over the past five years to set an adjustment to PPI-FG so that it reflects changes to costs industry-wide. After receiving comments and reply comments on its proposed order, FERC issued an order on December 17, 2020 setting the new methodology to PPI-FG plus 0.78%, effective July 1, 2021. FERC’s order is subject to rehearing and possible judicial review.
We cannot predict whether or to what extent the index factor may change in the future. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so; however, a pipeline must reduce its indexed rates to the extent they exceed the index ceiling when a negative index applies. Some indexed rates on our systems were reduced in 2016 in response to the negative index lowering the ceiling, such as certain spot rates on Zydeco. Rate increases made under the index methodology are presumed to be just and reasonable and require a protesting party to demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Despite these procedural limits on challenging the indexing of rates, the overall rates are not entitled to any specific protection against rate challenges. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.
While common carrier pipelines often use the indexing methodology to change their rates, common carrier pipelines may elect to support proposed rates by using other methodologies such as cost-of-service rate making, market-based rates and settlement rates. A common carrier pipeline can propose a cost-of-service approach when seeking to increase its rates above the rate ceiling (or when seeking to avoid lowering rates to the reduced rate ceiling), but must establish that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. A common carrier can charge market-based rates if it establishes that it lacks significant market power in the affected markets. A common carrier can establish rates under settlement if agreed upon by all current shippers. Rates for a new service on a common carrier pipeline can be established through a negotiated rate with an unaffiliated shipper or via a cost-of-service approach.
The rates shown in our FERC tariffs have been established using the indexing methodology, by settlement or by negotiation. If we used cost-of-service rate making to establish or support our rates on our different pipeline systems, the issue of the proper allowance for federal and state income taxes could arise. In 2005, FERC issued a policy statement stating that it would permit common carrier pipelines, among others, to include an income tax allowance in cost-of-service rates to reflect the tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. Whether a pipeline’s owners have such income tax liability is subject to review by FERC on a case-by-case basis. Although this policy is generally favorable for common carrier pipelines that are organized as pass-through entities, it still entails rate risk due to FERC’s case-by-case review approach and recent changes to FERC’s policy following litigation in the U.S. Court of Appeals for the D.C. Circuit, as described below. The application of this policy, as well as any decision by FERC regarding our cost of service, is also subject to review in the courts.

Under its current policy, FERC permits regulated interstate oil and gas pipelines to include an income tax allowance in their cost of service used to calculate cost-based transportation rates. The allowance is intended to reflect the tax liability attributable to the regulated entity’s operating income, regardless of the form of ownership. On July 1, 2016, in United Airlines, Inc. v. FERC, the United States Court of Appeals for the D.C. Circuit vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned by a master limited partnership (“MLP”) to include an income tax allowance in its cost-of-service rates. The D.C. Circuit held that FERC had failed to demonstrate that the inclusion of an income tax allowance in the pipeline’s rates would not lead to an over-recovery of costs attributable to regulated service. The D.C. Circuit instructed FERC on remand to fashion a remedy to ensure that the pipeline’s rates do not allow it to over-recover its costs. Following the D.C. Circuit’s decision, FERC issued its Revised Policy Statement on Treatment of Income Taxes in
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Docket No. PL17-1-000 on March 15, 2018 (the “Revised Policy Statement”), which eliminates the recovery of an income tax allowance by MLP oil and gas pipelines in cost-of-service-based rates. FERC directed MLP oil pipelines to reflect the elimination of the income tax allowance in their Form No. 6, page 700 reporting, although FERC did not make an adjustment to pipeline industry costs to reflect the elimination of the income tax allowance in its December 17, 2020 order adopting a revised indexing adjustment for the five-year period starting July 1, 2021. FERC also stated that it would address income tax allowances for other “pass-through” entities that are not MLPs in future proceedings. On July 18, 2018, FERC clarified in Order No. 849, which was directed at gas pipelines, 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 based on a demonstration that its recovery of an income tax allowance does not result in a “double-recovery of investors’ income tax costs.” While FERC has not taken industry-wide action on oil pipeline rates, FERC could require oil pipelines to revise their rates in individual proceedings (including initial rate filing or complaint proceedings) or through other action. To the extent that we charge cost-of-service based rates, those rates could be affected by any changes in FERC’s income tax allowance policy to the extent our rates are subject to complaint or challenge by FERC acting on its own initiative, or to the extent that we propose new cost-of-service rates or changes to our existing rates.

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.

Intrastate services provided by certain of our pipeline systems are subject to regulation by state regulatory authorities, such as the TRRC, which currently regulates Zydeco and Colonial pipeline rates, and the LPSC, which currently regulates the Zydeco, Mars, Delta and Colonial pipeline rates. State agencies typically require intrastate petroleum pipelines to file their rates with the agencies and permit shippers to challenge existing rates and proposed rate increases. State agencies may also investigate rates, services and terms and conditions of service on their own initiative. State regulatory commissions could limit our ability to increase our rates or to set rates based on our costs or could order us to reduce our rates and require the payment of refunds to shippers.

Further, rate investigations by FERC or a state commission could result in an investigation of our costs, including the:

overall cost of service, including operating costs and overhead;
allocation of overhead and other administrative and general expenses to the regulated entity;
appropriate capital structure to be utilized in calculating rates;
appropriate rate of return on equity and interest rates on debt;
rate base, including the proper starting rate base;
throughput underlying the rate; and
proper allowance for federal and state income taxes.

Shippers can always file a complaint with FERC or a state agency challenging rates or conditions of services. If they were successful, FERC or a state agency could order reparations or service changes.
Certain pipelines, including Auger, Na Kika, Amberjack, Odyssey, Poseidon, Proteus, Endymion, Cleopatra and parts of Mars, are located offshore in the Outer Continental Shelf. As such, they are not subject to FERC or state rate regulation but are subject to the Outer Continental Shelf Lands Act (“OCSLA”). Under the OCSLA, we must provide open and nondiscriminatory access to both pipeline owner(s) and non-owner shippers and comply with other requirements.  

Pipeline and Terminal Safety
Our assets are subject to strict safety laws and regulations. Our transportation and storage of crude oil, refined products and dry gas involve risks that hazardous liquids or gas may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages, liability and/or reparations to land owners and significant business interruption. PHMSA of the DOT has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of most of our assets. In addition, some states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which most of our assets are located, Texas and Louisiana, are among the states that have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting hazardous liquids and gases. The few assets not covered by PHMSA are regulated by the U.S. Environmental Protection Agency (“EPA”) and various state agencies and are
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designed and maintained to industry accepted codes and standards. PHMSA regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and necessary maintenance or repairs. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and are included in a drug and alcohol testing program, and that pipeline operators develop comprehensive spill response plans.

We are subject to regulation by PHMSA under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”). The NGPSA delegated to PHMSA through DOT the authority to regulate gas pipelines. The HLPSA delegated to PHMSA through DOT the authority to develop, prescribe, and enforce federal safety standards for the transportation of hazardous liquids by pipeline. Every four years PHMSA is up for reauthorization by Congress and with that reauthorization comes changes to the legislative requirements that Congress sets forth for the oversight of natural gas and hazardous liquid pipelines. In 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (the “Pipes Act”) was enacted. The Pipes Act reauthorized PHMSA through 2023 and imposed a few new mandates on the agency. The law establishes a PHMSA technology pilot, authorizes a new idled pipe operating status, contains process protections for operators during PHMSA enforcement proceedings and directs PHMSA to adopt regulations to address methane leaks from pipelines. There are no self-enacting portions of this act that impact our assets. We will be engaged in the regulatory process as PHMSA issues Reports and Notices of Proposed Rulemakings to meet the requirements set out in the Pipes Act. We will continue to work with industry groups to provide comments and recommendations to PHMSA on proposed regulations to help ensure improved safety without causing undue burden to operators.

PHMSA administers compliance with these statutes and has promulgated comprehensive safety standards and regulations for the transportation of hazardous liquids by pipeline, including regulations for the design and construction of new pipeline systems or those that have been relocated, replaced or otherwise changed (Subparts C and D of 49 CFR § 195); pressure testing (Subpart E of 49 CFR § 195); operation and maintenance of pipeline systems, including inspecting and reburying pipelines in the Gulf of Mexico and its inlets, establishing programs for public awareness and damage prevention, managing the integrity of pipelines in HCAs, and managing the operation of pipeline control rooms (Subpart F of 49 CFR § 195); protecting steel pipelines from the adverse effects of internal and external corrosion (Subpart H of 49 CFR § 195); and integrity management requirements for pipelines in HCAs (49 CFR § 195.452). Gas pipelines have similar requirements (49 CFR § 192).

On July 1, 2020, two new final rules issued by PHMSA on October 1, 2019 became effective. The 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 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 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 our inspection or maintenance programs on the lines. On the liquid side, all onshore lines have leak detection and are currently inspected under our 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 fully understand potential cost implications.

We monitor the structural integrity of our pipelines through a program of periodic internal assessments using a variety of internal inspection tools, as well as hydrostatic testing that conforms to federal standards. We accompany these assessments with a comprehensive data integration effort and repair anomalies, as required, to ensure the integrity of the pipeline. We conduct a thorough review of risks to the pipelines and perform sophisticated calculations to establish an appropriate reassessment interval for each pipeline. We use external coatings and impressed current cathodic protection systems to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards and continually monitor, test and record the effectiveness of these corrosion inhibiting systems.  We have robust third-party damage prevention and public awareness programs to help protect our lines from the risk of excavation and other outside force damage threats. Our tanks are inspected on a routine basis in compliance with PHMSA and EPA regulations. Every tank periodically receives a full out of service, internal inspection per American Petroleum Institute standard 653 and is repaired as necessary.

Certain aspects of our offshore pipeline operations, such as new construction and modification, are also regulated by BOEM, BSEE and the U.S. Coast Guard. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order
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suspending new fossil fuel leasing and permitting on federal lands for 60 days, which may cover our offshore pipeline permits. In addition, on January 27, 2021, President Biden issued an Executive Order on climate directing the Department of the Interior to pause on entering into new oil and natural gas leases on public lands or offshore waters “to the extent possible” and launch a review of all existing leasing and permitting practices related to fossil fuel development on public lands and waters. If our customers are unable to secure leases, permits, sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our pipeline and terminal systems or reduced rates under renegotiated transportation or storage agreements. We are still evaluating the effects of the recent order on our operations and our customers’ operations, but our inability and our customers’ inability to secure required permits could adversely affect our business, financial condition, results of operation or cash flows, including our ability to make cash distributions to our unitholders.
Product Quality Standards
Refined products that we transport are generally sold by our customers for consumption by the public. Various federal, state and local agencies have the authority to prescribe product quality specifications for refined products. Changes in product quality specifications or blending requirements could reduce our throughput volumes, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets affect the fungibility of the refined products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenue, our cash flows and ability to pay cash distributions could be adversely affected. In addition, changes in the product quality of the refined products we receive on our refined product pipeline systems or at our tank farms could reduce or eliminate our ability to blend refined products.
Security
We are also subject to U.S. Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities, and to Transportation Security Administration Pipeline Security Guidelines. We have an internal program of inspection designed to monitor and enforce compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.
Information Technology and Cyber-security
Given our dependence on Information Technology (“IT”) systems for our operations and the increasing role of digital technologies across our business, cyber-security attacks could cause significant harm to our business, e.g., in the form of loss of productivity, loss of intellectual property, regulatory fines and/or reputational damage. Shell, like many other multinational company groups, is the target of attempts to gain unauthorized access to its IT systems and data through various channels, including more sophisticated and coordinated attempts, which are often referred to as advanced persistent threats. Our business operations rely on the IT systems of our Parent, as well as third-party suppliers of IT goods and services. The security of IT services, operated by external IT companies, is managed through contractual clauses and through formal supplier assurance reports for critical IT services. In addition, we continuously measure and, where required, further improve our cyber-security capabilities, working with affiliates and key suppliers to reduce the likelihood of successful cyber-attacks. Our IT landscape is protected by various detective and protective technologies in line with industry best practices. While the arrangements described above are in place, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on our operations.

Along with our own confidential data and information in the normal course of our business, we and our affiliates collect and retain significant volumes of personal data, some of which are subject to certain laws and regulations. The regulations regarding the transfer and use of this data both domestically and across international borders are becoming increasingly complex. This data is subject to governmental regulation at the federal, state, international, national, provincial and local levels in many areas of our business, including data privacy and security laws such as the European Union (“EU”) General Data Protection Regulation (“GDPR”), the California Consumer Privacy Act (“CCPA”) and new or emerging legislation in other jurisdictions in which our Parent or its affiliates operate, such as Turkey, Brazil, China and India. These laws may also expose us to significant liabilities and penalties if any company we acquire has violated or is not in compliance with applicable data protection laws.

The EU GDPR came into force in May 2018. The GDPR applies to personal data and activities that may be conducted by us, directly or indirectly through vendors and subcontractors, from an establishment in the EU. As interpretation and enforcement of the GDPR evolves, it creates a range of new compliance obligations, which could cause us to incur costs or require us to change our business practices in a manner adverse to our business. Failure to comply could result in significant penalties of up to a maximum of 4% of our global turnover, which could materially adversely affect our business, reputation, results of
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operations and cash flows. The GDPR also requires mandatory breach notification to the appropriate regulatory authority and impacted data owners.

The CCPA became effective on January 1, 2020 and gives California residents specific rights regarding their personal information, requires that companies take certain actions, including notifications of security incidents, and applies to activities regarding personal information that may be collected by us, directly or indirectly, from California residents. In addition, the CCPA grants California residents statutory private rights of action in the case of a data breach. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could cause us to change our business practices, with the possibility of significant financial penalties for noncompliance.

In 2010, RDS adopted its Binding Corporate Rules (“BCRs”), which require every Shell company to provide a minimum standard of data protection irrespective of its jurisdiction of formation or operations. The BCRs were revised in 2019 and formulated based on the requirements of the GDPR, which ensures that each Shell entity maintains a baseline of compliance with current, new or emerging legislation on top of which processes for compliance with any specific local legislation can be addressed. We cannot ensure that our current practices and policies in the area of personal data protection will be sufficient to comply with all new or emerging rules or regulations applicable to us nor that they mitigate all of the associated risks to our business.
Environmental Matters
General. 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. Additionally, 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 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 natural resources damages. 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.
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 associated 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.
Air Emissions and Climate Change. Our operations are subject to the Clean Air Act and its regulations and comparable state and local statutes and regulations in connection with air emissions from our operations. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. These permits may require controls on our air emission sources, and we may become subject to more stringent regulations requiring the installation of additional emission control technologies.
Future expenditures may be required to comply with the Clean Air Act and other federal, state and local requirements for our various sites, including our pipeline and storage facilities. The impact of future legislative and regulatory developments, if enacted or adopted, could result in increased compliance costs and additional operating restrictions on our business, all of which
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could have an adverse impact on our financial position, results of operations and liquidity.
In December 2007, the U.S. Congress passed the Energy Independence and Security Act that created a second Renewable Fuels Standard. This standard requires the total volume of renewable transportation fuels (including ethanol and advanced biofuels) sold or introduced annually in the United States to rise to 36 billion gallons by 2022. The requirements could reduce future demand for refined products and thereby have an indirect effect on certain aspects of our business.
Currently, several legislative and regulatory measures to address greenhouse gas (“GHG”) emissions (including carbon dioxide, methane and other gases) are in various phases of discussion or implementation in the United States. These measures include requirements effective in 2010 to report GHG emissions to the EPA on an annual basis and proposed federal legislation and regulation as well as state actions to develop statewide or regional programs, each of which require or could require reductions in our GHG emissions. President Biden has issued a series of Executive Orders seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden Administration’s climate policies. Requiring reductions in GHG emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any GHG emissions programs, including acquiring emission credits or allotments. New requirements to address GHG emissions and climate change may also significantly affect the oil and gas production, processing, transmission and storage industry, as well as domestic refinery operations and may have an indirect effect on our business, financial condition and results of operations.

In addition, the EPA has proposed and may adopt further regulations under the Clean Air Act addressing greenhouse gases, to which some of our facilities may become subject. For example, in May 2016, EPA finalized new rules for volatile organic compound and methane emissions from the oil and gas production, processing, transmission and storage industry. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of the rules applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Circuit Court for the D.C. Circuit. On January 20, 2021, President Biden issued an Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directing the EPA to consider rescinding or revising the 2020 rules and proposing new regulations to expand these rules for the oil and gas production, processing, transmission and storage industries. Congress continues to consider legislation on GHG emissions, which may include proposals to monitor and limit emissions of GHGs, although the ultimate adoption and form of any federal legislation cannot presently be predicted. In addition, in 2015 the U.S. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. In November 2019, the U.S. State Department formally informed the United Nations of the United States’ withdrawal from the Paris Agreement and withdrew from the Paris Agreement in November 2020. However, on January 20, 2021, President Biden signed an instrument that reverses this withdrawal, and the United States will formally re-join the Paris Agreement on February 19, 2021.

The impact of future regulatory and legislative developments, if adopted or enacted, could result in increased compliance costs, increased utility costs, additional operating restrictions on our business and an increase in the cost of products generally. Like Shell, we actively monitor and assess these potential developments and believe we are best able to manage them when local policies provide a stable and predictable regulatory foundation for our future investments. Although such costs may impact our business directly or indirectly by impacting our facilities or operations, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding the additional measures and how they will be implemented.

In addition to the regulatory efforts described above, there have also been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities, as well as pressuring lenders and other financial services companies to limit or curtail activities with fossil fuel companies. If these efforts were to continue, they could have a material adverse effect on the price of our securities and our ability to access equity capital markets. Members of the investment community have begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before investing in our common units. Our efforts to improve our sustainability practices, some of which are described below, may increase our costs, and we may be forced to implement uneconomic technologies in order to improve our sustainability performance and to meet specific requirements to perform services for certain customers.

RDS has publicly recognized that GHG emissions are contributing to the warming of the climate system and stated its support for the goals of the Paris Agreement. In 2017, Shell announced its “Net Carbon Footprint” ambition, and subsequently issued the Shell Energy Transition Report in 2018 and the Shell Sustainability Report in 2020, describing, among other things, Shell’s
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approach to the energy transition and its plans to lower its overall carbon footprint through various measures. Shell is seeking cost-effective ways to manage GHG emissions in line with its “Net Carbon Footprint” ambition and intends to enable customers to make lower-carbon-intensity choices by bringing lower-carbon-intensity products to the market aligned with demand. Shell also aims to reduce the GHG intensity of its portfolio while continuing to work on improving the energy efficiency of its existing operations. Moreover, Shell has a climate change risk management structure in place, which is supported by standards, policies and controls, and actively monitors the GHG emissions of all its assets, including us, as well as the lifecycle of its products, to quantify future regulatory costs related to GHG or other climate-related policies. As a member of the RDS group of companies, we participate in and support these various measures, policies and initiatives and, as such, are evaluating the appropriate integration of these practices and procedures into our own operating framework.
Waste Management and Related Liabilities. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed.
CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which is also known as Superfund, and comparable state laws impose liability, without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the former and present owner or operator of the site where the release occurred and the transporters and generators of the hazardous substances found at the site.
Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we generate waste that falls within CERCLA’s definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites.
RCRA. We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Any changes in the regulations could impact our maintenance capital expenditures and operating expenses. We continue to seek methods to minimize the generation of hazardous wastes in our operations.
Hydrocarbon Wastes. We currently own and lease, and SPLC has in the past owned and leased, properties where hydrocarbons are being or for many years have been handled. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or waste may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these hydrocarbons and wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and hydrocarbons and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent further contamination.
Environmental Indemnity. The terms of each acquisition will vary, and in some cases we may receive contractual indemnification from the prior owner or operator for some or all of the liabilities relating to such matters, and in other cases we may agree to accept some or all of such liabilities. We do not believe that the portion of any such liabilities that the Partnership may bear with respect to any such properties previously acquired by the Partnership will have a material adverse impact on our financial condition or results of operations. For example, in connection with certain of our acquisitions from Shell, Shell agreed to indemnify us for certain environmental liabilities arising before the closing date, subject to customary deductibles and caps.
SPLC’s indemnification of us for breaches of representations or warranties relating to environmental matters in connection with our Initial Public Offering (“IPO”) terminated and expired on November 3, 2017.
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Water. Our operations can result in the discharge of pollutants, including crude oil and refined products. Regulations under the Water Pollution Control Act of 1972 (“Clean Water Act”), Oil Pollution Act of 1990 (“OPA-90”) and state laws impose regulatory burdens on our operations. Spill prevention control and countermeasure requirements of federal laws and some state laws require containment to mitigate or prevent contamination of navigable waters in the event of an oil overflow, rupture or leak. For example, the Clean Water Act requires us to maintain Spill Prevention Control and Countermeasure (“SPCC”) plans at many of our facilities. We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the Clean Water Act and have implemented tracking systems to oversee our compliance efforts. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. We believe we are in substantial compliance with applicable storm water permitting requirements.
In addition, the transportation and storage of crude oil and refined products over and adjacent to water involves risk and subjects us to the provisions of OPA-90 and related state requirements. Among other requirements, OPA-90 requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or hazardous substances. Also, in case of any such release, OPA-90 requires the responsible company to pay resulting removal costs and damages. OPA-90 also provides for civil penalties and imposes criminal sanctions for violations of its provisions. We operate facilities at which releases of oil and hazardous substances could occur. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90, and we have established SPCC plans for facilities subject to Clean Water Act SPCC requirements.

Construction or maintenance of our pipelines, tank farms and storage facilities may impact wetlands, which are also regulated under the Clean Water Act by the EPA and the U.S. Army Corps of Engineers. Regulatory requirements governing wetlands (including associated mitigation projects) may result in the delay of our pipeline projects while we obtain necessary permits and may increase the cost of new projects and maintenance activities. In 2014, the EPA and the U.S. Army Corps of Engineers published proposed regulations that expand the surface waters that are regulated under the federal Clean Water Act and its various programs. While these regulations were finalized largely as proposed in 2015, the rule was stayed by the courts pending a substantive decision on the merits. In October 2019, the EPA and the U.S. Army Corps of Engineers issued a final rule that repealed the 2015 regulations and reinstated the agencies’ narrower pre-2015 scope of federal Clean Water Act jurisdiction. In April 2020, the EPA and the U.S. Army Corps of Engineers issued a new final “waters of the United States” (“WOTUS”) definition that continues to provide a narrower scope of federal Clean Water Act jurisdiction than contemplated under the 2015 WOTUS definition, while also providing for greater predictability and consistency of federal Clean Water Act jurisdiction. Judicial challenges to the EPA’s October 2019 and April 2020 final rules are currently before multiple federal district courts. If the rules are vacated and the 2015 rule is ultimately implemented, the expansion of Clean Water Act jurisdiction will result in additional costs of compliance, as well as increased monitoring, recordkeeping and recording for some of our facilities.

In an April 15, 2020 ruling, amended May 11, 2020, the U.S. District Court for the District of Montana issued an order invalidating the U.S. Army Corps of Engineers (the “Corps”) 2017 reissuance of Nationwide Permit 12 (“NWP 12”), the general permit governing dredge-and-fill activities for pipeline and other utility line construction projects, to the extent it was used to authorize construction of new oil and gas pipelines. Environmental groups had alleged that the Corps failed to consult with federal wildlife agencies as required by the Endangered Species Act. The court’s decision vacated NWP 12 until the Corps completes consultation with the applicable federal wildlife agencies. On July 6, 2020, the U.S. Supreme Court granted in part and denied in part the Corps’ request to stay the U.S. District Court’s decision. The Supreme Court’s decision allows the use of NWP 12 as to construction of new oil and gas pipelines, pending the outcome of the appeal to the U.S. Court of Appeals for the Ninth Circuit and any subsequent petition for review to the U.S. Supreme Court. In addition, in January 2021, the EPA and the Corps issued a final rule reissuing and restricting NWP 12 to oil and gas pipelines. However, the NWP rulemaking is among the agency actions listed for review in accordance with the January 20, 2021 Executive Order: “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.” Limitations on the use of NWP 12 may make it more difficult to permit our projects and could cause us to lose potential and current customers and limit our growth and revenue.
Workplace Safety. We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to workers, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.
Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered species or their habitats. While some of our facilities are in areas that may be designated as habitats for endangered species, we believe that we are in
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substantial compliance with the Endangered Species Act. If endangered species are located in areas of the underlying properties where we wish to conduct development activities, such work could be prohibited or delayed or expensive mitigation may be required. In addition, the designation of new endangered species could cause us to incur additional costs or become subject to operating or development restrictions or bans in the affected area.
Inflation
Inflation did not have a material impact on our results of operations in 2020.
Seasonality
The volume of crude oil and refined products transported and stored utilizing our assets is directly affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. Additionally, producer turnarounds are often planned for certain periods during the year based on optimal, and in some cases, required weather and working conditions.
Title to Properties and Permits
Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property and, in some instances, these rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines.
Future Financial Assurance
In July 2016, BOEM issued Notice to Lessees and Operators 2016 NOI (“NTL”) that augmented requirements above current levels for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to perform decommissioning obligations with respect to platforms, pipelines and other facilities. In June 2017, BOEM announced that it would extend the NTL implementation timeline beyond the initial June 30, 2017 deadline, except in circumstances where there is a substantial risk of non-performance of decommissioning obligations, citing that more time was needed to work with the industry and other interested parties. In February 2017, BOEM announced that it would withdraw the orders to allow time for the Trump Administration to review BOEM’s financial assurance program. In October 2020, BOEM published a proposed rulemaking to clarify and simplify its financial assurance requirements. The issuance of a final rule is uncertain under the Biden Administration.
Insurance
All assets in which we have an interest are insured for certain property damage, business interruption and third-party liabilities, inclusive of certain cyber events and pollution liabilities, in amounts which management believes are reasonable and appropriate. With the exception of Odyssey, our consolidated assets are insured at the entity level. For Odyssey, as well as our other non-consolidated interests in joint ventures, we carry commercial insurance for our pro rata interests.
Employees
We do not have any employees. We are managed and operated by the directors and officers of our general partner, who, along with RDS, guide human capital management initiatives. See Part III, Item 10. Directors, Executive Officers and Corporate Governance — Management of Shell Midstream Partners, L.P. in this report.
Control Center Operations
Zydeco, Mattox, Amberjack, Mars, Odyssey, Bengal’s pipeline, Auger, Lockport, Delta, Na Kika, Proteus, Endymion, Cleopatra, Refinery Gas Pipeline and our terminals are operated by SPLC or our general partner pursuant to operating and maintenance agreements. The pipeline, storage and terminal systems that are operated by SPLC are controlled from a central control room located in Houston, Texas. The Operating Company, on behalf of Triton, engaged SPLC to operate the Norco Assets pursuant to an operating agreement, and such assets are operated by SPLC through the provision of services by employees assigned by SOPUS and located at the facilities under the terms of an employee assignment and services level agreement between SOPUS and SPLC. Colonial Pipeline Company operates its pipeline system and Bengal’s tankage in a similar manner and has its own management team based in Alpharetta, Georgia. Explorer operates its pipeline system in a
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similar manner and has its own management team and control center operations in Tulsa, Oklahoma. Poseidon is operated by Manta Ray Gathering Company, LLC, LOCAP is operated by LOOP LLC and Permian Basin is operated by CPB Operator LLC.
Website  
Our Internet website address is http://www.shellmidstreampartners.com. Information contained on our Internet website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to these reports, filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the U.S. Securities and Exchange Commission. Alternatively, you may access these reports at the SEC’s website at http://www.sec.gov. We also post our beneficial ownership reports filed by officers, directors and principal security holders under Section 16(a) of the Exchange Act, corporate governance guidelines, audit committee charter, code of business ethics and conduct, code of ethics for senior financial officers and information on how to communicate directly with our board of directors on our website.  

Item 1A. RISK FACTORS
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations. In this event, we might not be able to pay distributions on our common units, and the trading price of our common units could decline.
Summary of Risk Factors
Our business involves certain risks and uncertainties. The following is a description of significant risks that might cause our future financial condition or results of operations to differ materially from those expected. In addition to the risks and uncertainties described below, we may face other risks and uncertainties, some of which may be unknown to us and some of which we may deem immaterial. If one or more of these risks or uncertainties occur, our business, financial condition or results of operations may be materially and adversely affected. A summary of our risk factors is as follows:

The COVID-19 pandemic, coupled with other current pressures on oil and gas prices, could adversely affect our business and results of operations.
If the changes in market conditions resulting from the COVID-19 pandemic and consequential decreases in demand for and prices of crude oil and refined products continue, such conditions could trigger impairments in our property, plant and equipment and equity method and other investments.
Our operations are subject to many risks and operational hazards. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our operations and financial results could be materially and adversely affected.
If third-party pipelines, production platforms, refineries, caverns and other facilities interconnected to our pipelines, Triton’s refined product terminal and Lockport’s terminal facilities become unavailable to transport, produce, refine or store crude oil, or produce or transport refined products, our net income and cash available for distribution (“CAFD”) could be adversely affected.
Any significant decrease in production of crude oil in areas in which we operate could reduce the volumes of crude oil we transport and store, which could adversely affect our net income and CAFD.
Any significant decrease in the demand for crude oil, refined products and refinery gas could reduce the volumes of crude oil, refined products and refinery gas that we transport, which could adversely affect our net income and CAFD.
We are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.
Compliance with and changes in environmental laws and regulations, including proposed climate change laws and regulations, could adversely affect our performance. Our customers are also subject to environmental laws and regulations, and any changes in these laws and regulations, including laws and regulations related to hydraulic fracturing, could result in significant added costs to comply with such requirements and delays or curtailment in pursuing production activities, which could reduce demand for our services.
We may not have sufficient CAFD following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay distributions to our unitholders.
We do not control certain of the entities that own our assets.
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If we are unable to make acquisitions on economically acceptable terms from Shell or third parties, our future growth would be limited, and any acquisitions we may make could reduce, rather than increase, our cash flows and ability to make distributions to unitholders.
Our pipeline loss allowance exposes us to commodity risk.
The lack of diversification of our assets and geographic locations could adversely affect our ability to make cash distributions to our unitholders.
Our ability to renew or replace our third-party contract portfolio on comparable terms could materially adversely affect our business, financial condition, results of operations and cash flows, including our ability to make distributions.
We are exposed to the credit risks, and certain other risks, of our customers, and any material nonpayment or nonperformance by our customers could reduce our ability to make distributions to our unitholders.
If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make or increase quarterly cash distributions may be diminished or our financial leverage could increase. Other than our credit facilities, we do not have any contractual commitments with any of our affiliates to provide any direct or indirect financial assistance to us.
We rely heavily on information technology systems for our operations, and a cyber-incident involving such systems could result in information theft, data corruption, operational disruption and/or financial loss.
Terrorist or cyber-attacks and threats, or escalation of military activity in response to these attacks, could have a material adverse effect on our business, financial condition or results of operations.
Our general partner and its affiliates, including Shell, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of Shell, and it is under no obligation to adopt a business strategy that favors us.
Our Partnership Agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
The fees and reimbursements due to our general partner and its affiliates, including SPLC, for services provided to us or on our behalf will reduce our CAFD. In certain cases, the amount and timing of such reimbursements will be determined by our general partner and its affiliates, including SPLC.
Our Partnership Agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our CAFD would be substantially reduced.
Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions from us.
Operational Risks
The COVID-19 pandemic, coupled with other current pressures on oil and gas prices, could adversely affect our business
and results of operations.
During December 2019, a novel strain of coronavirus referred to as COVID-19 was reported to have surfaced in Wuhan, China and quickly spread to Italy, Iran, South Korea, the United States and other countries during the first quarter of 2020. On March 11, 2020, COVID-19 was officially declared a pandemic by the World Health Organization. In an effort to halt the outbreak, governments worldwide have placed significant restrictions on both domestic and international travel and have taken action to restrict the movement of people and suspend some business operations, ranging from targeted restrictions to full national lockdowns. The pandemic and resulting governmental responses have caused a significant slowdown in the global economy and financial markets. Concerns regarding increasing infection rates as countries and states move forward with reopening their economies has resulted in renewed lockdowns and other restrictions being imposed or a general slowdown of the reopening process in some of the affected areas and could be imposed in or affect other areas, which could lead to further economic instability and decreased demand for crude oil, refined products or refinery gas. The extent to which the COVID-19 pandemic and resulting governmental response may continue to impact our business and results of operations will depend on future developments that are highly uncertain and cannot be accurately predicted, including new information that may emerge concerning the disease (including the discovery of strains that are more transmissible or virulent), the efficacy and distribution
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of available vaccines, evolving governmental and private sector actions to contain the pandemic or treat its health, economic and other impacts and factors.

For example, the COVID-19 pandemic could adversely impact our business operations or the health of our workforce by rendering employees or contractors unable to work or unable to access our facilities due to health or regulatory reasons. While the operations and maintenance of our facilities are not covered by stay-at-home and similar orders because they generally constitute essential business excepted from such orders, we continue to closely monitor developments. Most of our office-based employees continue to be subject to stay-at-home or similar orders or Shell worksite policies adopted in response to the COVID-19 pandemic, such that this part of our workforce is largely working from home globally. If the impact of the COVID-19 pandemic continues, we could see a reduction or delay in our operational spending and capital expenditures due to our inability to execute projects and workforce limitations.

Moreover, in March 2020, oil prices declined significantly due to potential increases in supply emanating from a disagreement on production cuts among members of the Organization of the Petroleum Exporting Countries (“OPEC”) and certain non- OPEC, oil-producing countries. On April 9, 2020, these countries announced supply cuts, which were extended through the end of July 2020, but such cuts have thus far been insufficient to counter all of the demand destruction in the oil and gas markets caused by the effects of COVID-19. After increasing supply through the summer of 2020, certain OPEC members announced production cuts in October 2020, potentially signaling continued pressure on demand. In January 2021, OPEC and certain other non-OPEC, oil-producing countries agreed to forgo any supply increases in February and March 2021 in response to continuing demand constraints in the oil and gas markets caused by renewed lockdowns and other global measures to curtail the rise of COVID-19 infections. The significant decline in worldwide demand for oil and gas resulting from the COVID-19 pandemic and its effects have resulted in dramatically decreased oil and gas prices, which could have substantial negative implications for our transportation revenue, allowance oil revenue and other sources of revenue related to or underpinned by commodity prices. As a result, these factors could have a material adverse effect on our results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders. At this point, we cannot accurately predict what effects current market conditions due to the COVID-19 pandemic will have on our business, which will depend on, among other factors, the duration of the continued outbreak and the effects of new viral strains, the extent of increased infection rates in
response to economic re-openings, the efficacy and timely distributions of available vaccines and the extent and overall economic effects of the continuing governmental response to the pandemic, including any lockdowns, other restrictions or a general slowdown of the reopening process in the affected areas.

If the changes in market conditions resulting from the COVID-19 pandemic and consequential decreases in demand for and
prices of crude oil and refined products continue, such conditions could trigger impairments in our property, plant and equipment and equity method and other investments.
During the first quarter of 2020 and continuing through the end of the year, the COVID-19 pandemic caused significant changes in the macroeconomic outlook, continued depression of commodity prices and a sustained decrease in the market price of our common units, which led us to evaluate our asset balances for impairment triggering events during the year ended December 31, 2020. We assess our equity method investments 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. We remeasure our other investments either upon the occurrence of an observable price change or upon identification of impairment.

We evaluate long-lived assets of identifiable business activities, including property, plant and equipment, for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. These events include significant changes or projected changes in the supply and demand fundamentals of oil, natural gas, refinery gas or refined products, new technological developments, new competitors, general materially adverse changes in the U.S. and global economies and major governmental actions. If any such event occurs, which is a determination that involves judgment, we perform an impairment assessment by comparing estimated undiscounted future cash flows associated with the asset to the asset’s net book value. If the net book value exceeds our estimate of undiscounted future cash flows, an impairment is calculated as the amount the net book value exceeds the estimated fair value associated with the asset. Based on these updated evaluations, we determined that there is no impairment in property, plant and equipment, and equity method and other investments for 2020. See Note 5 — Equity Method Investments and Note 6 — Property, Plant and Equipment in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for further discussion. However, if current market conditions persist for an extended period of time, we could incur impairment charges in the future.

Our operations are subject to many risks and operational hazards. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our operations and financial results could be materially and adversely affected.
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Our operations are subject to all of the risks and operational hazards inherent in transporting and storing crude oil and refined products, including:

damages to pipelines, facilities, offshore pipeline equipment and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes and acts of terrorism;
maintenance, repairs, mechanical or structural failures at our or SPLC’s facilities or at third-party facilities on which our customers’ or our operations are dependent, including electrical shortages, power disruptions, power grid failures and planned turnarounds;
damages to, loss of availability of and delays in gaining access to interconnecting third-party pipelines, terminals and other means of delivering crude oil, refined products and refinery gas;
costs and liabilities in responding to any soil and groundwater contamination that occurs on our terminal properties, even if the contamination was caused by prior owners and operators of our terminal system;
disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack of the central control room from which some of our pipelines are remotely controlled;
leaks of crude oil or refined products as a result of the malfunction or age of equipment or facilities;
unexpected business interruptions;
curtailments of operations due to severe seasonal weather;
temporary or extended reductions in the availability of our workforce due to the health or resulting regulatory effects of a pandemic or other health crises, such as the current COVID-19 pandemic; and
riots, strikes, lockouts or other industrial disturbances.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, as well as business interruptions or shutdowns of our facilities. Any such event or unplanned shutdown could have a material adverse effect on our business, financial condition and results of operations.

If third-party pipelines, production platforms, refineries, caverns and other facilities interconnected to our pipelines, Triton’s refined product terminal, Lockport’s terminal facilities or Triton's logistics assets at the Shell Norco Manufacturing Complex become unavailable to transport, produce, refine or store crude oil, or produce or transport refined products, our revenue and available cash could be adversely affected.
We depend upon third-party pipelines, production platforms, refineries, caverns and other facilities that provide delivery
options to and from our pipelines, terminal facilities and other assets. For example, Mars depends on a natural gas supply pipeline connecting to the West Delta 143 platform to power its equipment to deliver the volumes it transports to salt dome caverns in Clovelly, Louisiana. Similarly, shutdown or blockage of pipelines moving offshore gas can result in curtailment or shut-in of offshore crude production. Because we do not own these third-party pipelines, production platforms, refineries, caverns or facilities, their continuing operation is not within our control. For example, production platforms in the offshore Gulf of Mexico may be required to be shut-in by BSEE or BOEM of the U.S. Department of the Interior following incidents such as loss of well control. Additionally, due to continued macroenvironmental factors of depressed demand (due to the effects of the COVID-19 pandemic, resulting governmental response and other factors) and oversupply (due to sustained production cuts by OPEC and non-OPEC, oil-producing countries that have been insufficient to fully counter the demand destruction of COVID-19 and other factors), certain pipelines and storage facilities may approach or reach maximum capacity, causing producers to shut-in production. If these or any other pipeline or terminal connection were to become unavailable for current or future volumes of crude oil or refined products due to repairs, damage to the facility, lack of capacity, shut-in by regulators or any other reason, or if caverns to which we connect have cracks, leaks or leaching or require shut-in due to regulatory action or changes in law, our ability to operate efficiently and continue to store or ship crude oil and refined products to major demand centers could be restricted, thereby reducing revenue. Disruptions at refineries that use our pipelines, such as strikes or ship channel incidents, can also have an adverse impact on the volume of products we ship. Increases in the rates charged by the interconnected pipelines for transportation to and from our terminal facilities may reduce the utilization of our terminals. Our refined products terminals are limited to a 5% reduction in payments by the customer due to force majeure incidents. However, our customers and other counterparties may have other contractual defenses to performance available to them, including the doctrine of impossibility, impracticability of performance, frustration of performance and others, the use and success of which we cannot predict. Any temporary or permanent interruption at any key pipeline or terminal interconnect, at any key production platform or refinery, at caverns to which we deliver, termination of any connection agreement or adverse change in the terms and conditions of service, could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.

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During 2020, certain connected producers had planned turnarounds. The impact to net income and CAFD was approximately $15 million for the year ended December 31, 2020. Further, we anticipate an impact of approximately $10 million to net income and CAFD from planned turnaround activity in 2021.

Any significant decrease in production of crude oil in areas in which we operate could reduce the volumes of crude oil we transport and store, which could adversely affect our revenue and available cash.
Our crude oil pipelines and terminal system depend on the continued availability of crude oil production and reserves, particularly in the Gulf of Mexico. Low prices for crude oil could adversely affect development of additional reserves and continued production from existing reserves that are accessible by our assets.
Crude oil prices have fluctuated significantly over the past few years, often with drastic moves in relatively short periods of
time. During 2020, prices decreased significantly from 2019 levels due to the volatile negotiations among OPEC member and non-member countries regarding agreed production levels and the resulting production cuts agreed upon by such countries in April 2020 (and extended through the end of July 2020) have thus far been insufficient to counter the continuing effects of the COVID-19 pandemic. Moreover, certain OPEC members announced production cuts in October 2020, potentially signaling continued pressure on demand. In January 2021, OPEC and certain other non-OPEC, oil-producing countries agreed to forgo any supply increases in February and March 2021 in response to continuing demand constraints in the oil and gas markets caused by renewed lockdowns and other global measures to curtail the rise of COVID-19 infections. The continuing effects of the COVID-19 pandemic and the resulting governmental responses worldwide have led to unprecedented demand destruction in the crude and finished products markets. These ongoing events and other current global geopolitical and economic uncertainty may contribute to further future volatility in financial and commodity markets in the near to medium term. High, low and average daily prices for West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma during January 2021, 2020 and 2019 were as follows:
 
WTI Crude Oil Prices
HighAverageLow
January 2021$53.47 $52.01 $47.47 
202063.27 39.16 (36.98)
201966.24 56.98 46.31 

In general terms, the prices of crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors impacting crude oil prices include worldwide economic conditions (such as the continuing COVID-19 pandemic and its effects, including the response of various governments to the pandemic); weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported crude oil; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional basis differentials and premiums; actions by OPEC and other oil-producing nations; the price and availability of alternative energy, including alternative energy which may benefit from government subsidies; the effect of energy conservation measures; the strength of the U.S. dollar; the nature and extent of governmental regulation and taxation; and the anticipated future prices of crude oil and other commodities.
Lower crude oil prices, or expectations of declines in crude oil prices, such as the price signaling suggested by the production cuts by certain OPEC member countries in October 2020 and the agreement among OPEC and non-OPEC, oil-producing countries in January 2021 to hold production at steady levels for February and March 2021 have had and may continue to have a negative impact on exploration, development and production activity, particularly in the continental United States. If lower prices are sustained, it could lead to a material decrease in such activity both in the onshore continental United States and in the Gulf of Mexico. Sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our pipeline and terminal systems or reduced rates under renegotiated transportation or storage agreements. Our customers may also face liquidity and credit issues that could impair their ability to meet their payment obligations under our contracts or cause them to renegotiate existing contracts at lower rates or for shorter terms. These conditions may lead some of our customers, particularly customers that are facing financial difficulties, to seek to renegotiate existing contracts on terms that are less attractive to us. Any such reduction in demand or less attractive terms could have a material adverse effect on our results of operations, financial position and ability to make or increase cash distributions to our unitholders.
In addition, production from existing areas with access to our pipeline and terminal systems will naturally decline over time. The amount of crude oil reserves underlying wells in these areas may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the volume of crude oil transported, or throughput, on our pipelines, or stored in our terminal system, and cash flows associated with the
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transportation and storage of crude oil, our customers must continually obtain new supplies of crude oil. In addition, we will not generate revenue under our life-of-lease transportation agreements that do not include a guaranteed return to the extent that production in the area we serve declines or is shut-in.
If new supplies of crude oil are not obtained, including supplies to replace any decline in volumes from our existing areas of operations, the overall volume of crude oil transported or stored on our systems would decline, which could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.
Any significant decrease in the demand for crude oil, refined products and refinery gas could reduce the volumes of crude oil, refined products and refinery gas that we transport, which could adversely affect our revenue and available cash.
The volumes of crude oil, refined products and refinery gas that we transport depend on the supply of and demand for crude oil, gasoline, jet fuel, refinery gas and other refined products in our geographic areas. 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 price environment, increased competition and adverse economic factors affecting the exploration, production and refining industries. Further, crude oil, refined products and refinery gas compete with other forms of energy available to users, including electricity, coal, other fuels and alternative energy. Increased demand for such forms of energy at the expense of crude oil, refined products and refinery gas could lead to a reduction in demand for our services.

Beginning in March 2020, uncertainty resulting from the effects of the COVID-19 pandemic and resulting governmental responses and volatile negotiations regarding production levels among certain OPEC and non-OPEC, oil-producing countries led to a significant decline in demand for crude oil and refined products. Although these countries reached an agreement on supply cuts in April 2020 and October 2020, and agreed to maintain these cuts for February and March 2021, such response has been insufficient to compensate for all of the demand destruction resulting from the effects of COVID-19. Further, concerns regarding increasing infection rates as countries and states move forward with reopening their economies has resulted in renewed lockdowns and other restrictions being imposed or a general slowdown of the reopening process in some of the affected areas and could be imposed in other areas, which could lead to further economic instability and decreased demand for crude oil, refined products or refinery gas. If the demand for crude oil, refined products or refinery gas continues to significantly decrease, or if there were a material increase in the price of crude oil supplied to our customers’ refineries without an increase in the value of the products produced by those refineries, either temporary or permanent, it may cause our customers to reduce production of refined products at their refineries. If production of refined products declines, there would likely be a reduction in the volumes of crude oil and refined products that we transport. Moreover, if demand for oil and refined products further decreases substantially, certain of our pipelines and storage tanks may reach maximum capacity if these commodities and products cannot be sold into markets, which may result in a forced shut-in of certain producer sites. Any of the foregoing effects or events could have a material adverse effect on our results of operations, financial position and ability to make cash distributions to our unitholders.

Our insurance policies do not cover all losses, costs or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.
With the exception of Odyssey, our consolidated assets are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes pollution liabilities. For Odyssey, as well as our other non-consolidated interests in joint ventures, the current owners are required to carry insurance for their pro rata interest. We carry commercial insurance for our pro rata interests, which will increase our operation and maintenance expenses.

All of the insurance policies relating to our assets and operations are subject to policy limits. In addition, the waiting period under the business interruption insurance policies of the entities in which we own an interest is 60 days. We and the entities in which we own an interest do not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Over time, it has been more difficult and expensive to obtain certain types of coverage, especially as a result of increasing costs related to named storms and other natural disasters. The occurrence of an event that is not fully covered by insurance, or failure by our insurer to honor its coverage commitments for an insured event, could have a material adverse effect on our business, financial condition and results of operations. Insurance companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums or deductibles to cover our assets. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. There is no assurance that the insurers of the entities in which we own an interest will renew their insurance coverage on acceptable terms, if at all, or that the entities in which we own an interest will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which the entities in which we own an interest suffer
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significant losses could have a material adverse effect on our business, financial condition and results of operations, including our ability to make cash distributions to our unitholders.

Our expansion of existing assets and construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our operations and financial condition.
In order to optimize our existing asset base, we intend to expand our existing pipelines and terminals, such as by adding horsepower, pump stations, new connections or additional tank storage. We also intend to evaluate and capitalize on organic opportunities for expansion projects in order to increase revenue on our assets. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost.
These expansion projects involve numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. Moreover, we may not receive sufficient long-term contractual commitments or spot shipments from customers to provide the revenue needed to support projects, and we may be unable to negotiate acceptable interconnection agreements with third-party pipelines to provide destinations for increased throughput. Even if we receive such commitments or spot shipments or make such interconnections, we may not realize an increase in revenue for an extended period of time. As a result, new or expanded facilities may not be able to attract enough throughput to achieve our expected investment return, which could have a material adverse effect on our business, financial condition and results of operations, including our ability to make cash distributions to our unitholders.

We do not own all of the land on which our assets are located, which could result in disruptions to our operations.
We do not own all of the land on which our assets are located, and we are, therefore, subject to the possibility of more onerous terms and increased costs to retain necessary land use if we do not have valid leases or rights-of-way or if such leases or rights-of-way lapse or terminate. We obtain the rights to construct and operate our assets on land owned by third parties and governmental agencies, and some of our agreements may grant us those rights for only a specific period of time. Our loss of these or similar rights, through our inability to renew leases, right-of-way contracts or otherwise, or inability to obtain easements at reasonable costs could have a material adverse effect on our business, results of operations, financial condition and cash flows, including our ability to make cash distributions to our unitholders.

Subsidence and coastal erosion could damage our pipelines along the Gulf Coast and offshore and the facilities of our customers, which could adversely affect our operations and financial condition.
Our pipeline operations along the Gulf Coast and offshore could be impacted by subsidence and coastal erosion. Such processes could cause serious damage to our pipelines, which could affect our ability to provide transportation services. Additionally, such processes could impact our customers who operate along the Gulf Coast, and they may be unable to utilize our services. Subsidence and coastal erosion could also expose our operations to increased risks associated with severe weather conditions, such as hurricanes, flooding and rising sea levels. As a result, we may incur significant costs to repair and preserve our pipeline infrastructure. Such costs could adversely affect our business, financial condition, results of operation or cash flows, including our ability to make cash distributions to our unitholders.

Our assets were constructed over many decades, which may cause our inspection, maintenance or repair costs to increase in the future. In addition, there could be service interruptions due to unknown events or conditions or increased downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.
Our pipelines and storage terminals were constructed over many decades. Pipelines and storage terminals are generally long-lived assets, and construction and coating techniques have varied over time. Depending on the era of construction, some assets will require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.

Regulatory Risks

We are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.
Our interstate and offshore pipeline operations are subject to pipeline safety regulations administered by PHMSA of the DOT. These laws and regulations require us to comply with a significant set of requirements for the design, construction, operation, maintenance, inspection and management of our crude oil, refined products and refinery gas pipelines. Certain aspects of our offshore pipeline operations, such as new construction and modification, are also regulated by BOEM, BSEE and the U.S.
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Coast Guard. PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines, with enhanced measures required for pipelines located where a leak or rupture could harm an HCA. The regulations require operators to:

perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could affect an HCA;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate pipelines. For example, our intrastate pipelines in Louisiana are subject to pipeline safety regulations, including integrity management regulations administered by the Office of Conservation of the Louisiana Department of Natural Resources.

At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. In addition, our actual implementation costs may be affected by industry-wide demand for the associated contractors and service providers. Additionally, should any of our assets fail to comply with PHMSA regulations, they could be subject to shutdown, pressure reductions, penalties and fines. Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, on July 1, 2020, two new final PHMSA rules became effective. The rules impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. These rules and any new rule proposals could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis. Any of these tasks could result in incurring increased operating costs that could be significant and have a material adverse effect on our operations or financial position.

In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in shutdowns, capacity constraints or operational limitations to our pipelines. Should any of these risks materialize, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Compliance with and changes in environmental laws and regulations, including proposed climate change laws and regulations, could adversely affect our performance. Our customers are also subject to environmental laws and regulations, and any changes in these laws and regulations, including laws and regulations related to hydraulic fracturing, could result in significant added costs to comply with such requirements and delays or curtailment in pursuing production activities, which could reduce demand for our services.
The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water or groundwater. Our operations are subject to extensive environmental laws and regulations, including those relating to the discharge and remediation of materials in the environment, GHG emissions, waste management, species and habitat preservation, pollution prevention, pipeline integrity and other safety-related regulations and characteristics and composition of fuels. Certain of these laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities or third-party sites where we take wastes for disposal or where our wastes migrated, or could impose strict liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. Our offshore operations are also subject to laws and regulations protecting the marine environment administered by the U.S. Coast Guard and BOEM. Failure to comply with these laws and regulations could lead to administrative, civil or criminal penalties or liability and imposition of injunctions, operating restrictions or the loss of permits.
Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of expenditures required for environmental matters could increase in the future. Current and future legislative action and regulatory initiatives could result in changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we transport and decreased demand for products we handle that cannot be assessed with certainty at this time. We may be required to make expenditures to modify operations or install pollution control equipment or release prevention and containment systems that could materially and adversely affect our business, financial condition, results of operations and liquidity if these expenditures, as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services. For example, the EPA has, in recent years, adopted final rules making more stringent the National Ambient Air Quality Standards for ozone, sulfur dioxide
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and nitrogen dioxide. Emerging rules implementing these revised air quality standards may require us to obtain more stringent air permits and install more stringent controls at our operations, which may result in increased capital expenditures.
Climate change legislation and regulations to address GHG emissions are in various phases of discussion or implementation in the United States. The outcome of federal, state and regional actions to address climate change could result in a variety of regulatory programs including potential new regulations to control or restrict emissions, taxes or other charges to deter emissions of GHGs, energy efficiency requirements or alternative energy requirements to reduce demand, or other regulatory actions. These actions could result in increased compliance and operating costs or could adversely affect demand for the crude oil and refined products that we transport. Additionally, adoption of federal, state or regional requirements mandating a reduction in GHG emissions could have far-reaching impacts on the energy industry and the U.S. economy. We cannot predict the potential impact of such laws or regulations on our future consolidated financial condition, results of operations or cash flows. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.

Our customers are also subject to environmental laws and regulations that affect their businesses, and changes in these laws or regulations could materially adversely affect their businesses or prospects. Our crude oil pipelines serve customers who depend on production techniques, such as hydraulic fracturing, that are currently being scrutinized by federal, state and local authorities and that could be subjected to increased regulatory costs, delays or liabilities. Any changes in laws or regulations or administrative orders that impose significant costs or liabilities on our customers, or that result in delays, curtailments or cancellations of their projects, could reduce their demand for our services and materially adversely affect our business, results of operations, financial position or cash flows, including our ability to make cash distributions to our unitholders.

We may be unable to obtain or renew permits necessary for our operations or for growth and expansion projects, which could inhibit our ability to do business.
Our facilities operate under a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. In addition, we implement maintenance, growth and expansion projects as necessary to pursue business opportunities, and these projects often require similar permits, licenses and approvals. These permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to continue operations and on our business, financial condition, results of operations and cash flows, including our ability to make cash distributions to our unitholders. For example, on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order suspending new fossil fuel leasing and permitting on federal lands for 60 days, which may cover our offshore pipeline permits. Finally, our ability to secure required permits may be inhibited by increasingly stringent environmental, health and safety requirements, negative public perception or opposition from political activists through protests or other means, which could adversely affect our business, financial condition, results of operation or cash flows, including our ability to make cash distributions to our unitholders.

The tariff rates and rules and regulations for service of our regulated assets, as well as our business practices for our regulated assets, are subject to review, audit and possible adjustment by federal and state regulators, which could adversely affect our revenue and our ability to make distributions to our unitholders.
We provide both interstate and intrastate transportation services for refined products and crude oil. Our interstate and intrastate pipelines are common carriers and are required to provide service to any shipper similarly situated to an existing shipper that requests transportation services on our pipelines.

Zydeco, Bengal, Colonial, LOCAP, Explorer and portions of Mars provide interstate transportation services that are subject to regulation by FERC under the ICA. FERC uses prescribed rate methodologies for developing and changing regulated rates for interstate pipelines. Shippers may protest (and FERC may investigate) the lawfulness of new or changed tariff rates, or may file a complaint against existing tariff rates. FERC can suspend new or changed tariff rates, rules and regulations for up to seven months and can allow new rates to be implemented subject to refund of amounts collected in excess of the rate ultimately found to be just and reasonable. Shippers may also file complaints that existing rates are unjust and unreasonable. If FERC finds a rate to be unjust and unreasonable, it may order payment of reparations for up to two years prior to the filing of a complaint or investigation, and FERC may prescribe new rates prospectively.

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From November 2017 through 2020, twelve separate, nearly identical complaints were filed with FERC against Colonial challenging Colonial’s tariff rates, its market power, and its practices and charges related to transmix and product volume loss. These complaints have been consolidated by FERC in Docket Nos. OR18-7-002, et al. and were set for hearing and settlement judge procedures. FERC also severed the review of Colonial’s market-based rates into a separate, concurrent hearing. On May 2, 2019, the Chief Administrative Law Judge terminated settlement judge procedures and established a procedural schedule for a hearing before an administrative law judge. The hearing took place in the latter part of 2020 and an initial decision from the administrative law judge is currently scheduled for August 2021, with a FERC decision anticipated by spring 2022. Since the consolidated complaint proceedings are ongoing, FERC has not taken any final action on the complaints and the outcome is not known at this time. If Colonial is unable to recover its full cost-of-service as a result of the rates established in this proceeding, is no longer able to charge market-based rates or has its procedures and charges related to transmix and product volume loss modified in a way that is adverse to Colonial, it could adversely affect our financial position, results of operation and ability to make cash distributions to our unitholders.

On December 22, 2017, federal legislation known as the “Tax Cuts and Jobs Act” (the “TCJA”) was enacted, which made various changes to the U.S. tax laws, including reducing the highest marginal U.S. federal corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017, adjusting the individual income tax brackets and establishing limited deductions for certain income from “pass-through” entities. In the Revised Policy Statement, FERC states that it would address the effect of the tax changes on industry-wide oil pipeline costs in the five-year review of the oil pipeline index level, which commenced in 2020. As with the corporate income tax rate reduction, FERC also has announced that it would take the MLP income tax allowance elimination into account in the next five-year review of indexed rates in 2020. Both of these factors were considered as part of the order on the five-year review that was issued on December 17, 2020, although FERC declined in that order to incorporate the effect of the income tax allowance elimination in setting the new indexing adjustment. Separately, FERC also could require oil pipelines to revise their rates in individual proceedings (including initial rate filing or complaint proceedings) or through other action. Certain of our current tariff rates on file with FERC may reflect the federal income tax rate that was in effect at the time those tariff rates were established. As with any regulatory requirements promulgated by FERC, if FERC requires us to establish new tariff rates that reflect the current federal corporate income tax rate, it is possible the rates would be reduced, which could adversely affect our financial position, results of operation and ability to make cash distributions to our unitholders.

We may at any time also be required to respond to governmental requests for information, including compliance audits conducted by FERC. FERC’s Office of Enforcement concluded an audit of Colonial in Docket No. FA14-4-000 for the period from January 1, 2011 to December 31, 2014, and issued a letter order on June 17, 2015. FERC’s Office of Enforcement also concluded an audit of Explorer in Docket No. FA16-5-000 for the period from January 1, 2013 to December 31, 2016, and issued a letter order on January 12, 2018. In both cases, FERC adopted the audit’s findings and recommendations and required the submission of a compliance plan and quarterly compliance reports. Both Colonial and Explorer accepted the audit’s findings and recommendations, neither of which had a financial impact to us.

State agencies may regulate the rates, terms and conditions of service for our pipelines offering intrastate transportation services, and such agencies could limit our ability to increase our rates or order us to reduce our rates and pay refunds to shippers. State agencies can also regulate whether a service may be provided or cancelled. FERC and most state agencies support light-handed regulation of common carrier pipelines and have generally not investigated the rates, terms and conditions of service of pipelines in the absence of shipper protests or complaints, and generally resolve matters informally. The LPSC has a more stringent review of rate increases, though it does allow use of FERC’s index, and may prohibit or limit future rate increases for intrastate movements regulated by Louisiana.

Under our agreements with certain of our customers, we and the customer have agreed to base tariff rates for some of our pipelines, and our customers have agreed not to challenge the base tariff rates or changes to those rates during the term of the agreements, subject to certain exceptions. Some of these agreements and the underlying rates have been approved by FERC under a declaratory order. These agreements do not, however, prevent any other new or prospective shipper, FERC or a state agency from challenging our tariff rates or our terms and conditions of service on rates or services not covered by these agreements.

Further, rate investigations by FERC or a state commission could result in an investigation of our costs, including the:

overall cost of service, including operating costs and overhead;
allocation of overhead and other administrative and general expenses to the regulated entity;
appropriate capital structure to be utilized in calculating rates;
appropriate rate of return on equity and interest rates on debt;
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rate base, including the proper starting rate base;
throughput underlying the rate; and
proper allowance for federal and state income taxes.

Shippers can always file a complaint with FERC or a state agency challenging rates or conditions of services. If they were successful, FERC or the state agency could order reparations. A successful challenge of any of our rates, or any changes to FERC’s approved rate or index methodologies, could adversely affect our revenue and our ability to make distributions to our unitholders. Similarly, if state agencies in the states in which we offer intrastate transportation services change their policies or aggressively regulate our rates or terms and conditions of service, it could also adversely affect our revenues, including our ability to make cash distributions to our unitholders.

We may need to implement new internal controls or modify existing ones due to the COVID-19 pandemic, which could
impact the reliability and timeliness of our consolidated financial statements.
Effective internal control over financial processes and reporting are necessary for us to provide reliable financial reports that prevent fraud and operate successfully. Due to the COVID-19 pandemic, we may experience issues in our control processes associated with business or facility closures, or individuals may be unable to effectively perform certain control duties due to illness or absence, and as a result we may not be able to effectually complete our financial reporting process and prepare consolidated financial statements on a timely basis. Additionally, remote working arrangements may make the performance of certain control-related duties more difficult. If our existing controls cannot be performed in an effective or timely manner, we may need to identify alternative controls to compensate for or replace such controls to prevent any deficiencies in our internal controls environment.

Risks Related to the Structure of Our Business

We may not have sufficient CAFD following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay distributions to our unitholders.
We may not generate sufficient cash flows each quarter to enable us to pay distributions to our unitholders. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things, our throughput volumes, tariff rates and fees and prevailing economic conditions. In addition, the actual amount of cash flows we generate will also depend on other factors, some of which are beyond our control, including:

the amount of our operating expenses and general and administrative expenses, including reimbursements to SPLC with respect to those expenses;
the volume of crude oil, refined products and refinery gas that we transport and the ability of our customers to meet their obligations under our contracts;
actions by FERC or other regulatory bodies that reduce our rates or increase expenses;
the amount and timing of expansion capital expenditures and acquisitions we make;
the amount of maintenance capital expenditures we make;
our debt service requirements and other liabilities, and restrictions contained in our debt agreements;
fluctuations in our working capital needs;
the amount of cash distributed to us by the entities in which we own a noncontrolling interest;
the amount of cash reserves established by our general partner; and
changes in, and availability to us, of the equity and debt capital markets.

We do not control certain of the entities that own our assets.
We have no significant assets other than our ownership interests in entities that own crude oil, refined products and refinery gas pipelines and a crude tank storage and terminal system. As a result, our ability to make distributions to our unitholders depends on the performance of these entities and their ability to distribute funds to us. More specifically:

many of the entities in which we own interests are managed by their respective governing board. Our ability to influence decisions with respect to the operation of such entities varies depending on the amount of control we exercise under the applicable governing agreement;
we do not control the amount of cash distributed by several of the entities in which we own interests. We may influence the amount of cash distributed through our veto rights over the cash reserves made by certain of these entities;
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we may not have the ability to unilaterally require certain of the entities in which we own interests to make capital expenditures, and such entities may require us to make additional capital contributions to fund operating and maintenance expenditures, as well as to fund expansion capital expenditures, which would reduce the amount of cash otherwise available for distribution by us or require us to incur additional indebtedness;
the entities in which we own interests may incur additional indebtedness without our consent, which debt payments would reduce the amount of cash that might otherwise be available for distribution;
our assets are operated by entities that we do not control; and
the operator of the assets held by each joint venture and the identity of our joint venture partners could change, in some cases without our consent.

For more information on the agreements governing the management and operation of the entities in which we own an interest, see Part III, Item 13. Certain Relationships and Related Party Transactions, and Director Independence — Agreements with Shell and Part I, Items 1 and 2. Business and Properties — Our Assets and Operations in this report.

If we are unable to make acquisitions on economically acceptable terms from Shell or third parties, our future growth would be limited, and any acquisitions we may make could reduce, rather than increase, our cash flows and ability to make distributions to unitholders.
Our strategy to grow our business and increase distributions to unitholders is dependent in part on our ability to make acquisitions that result in an increase in CAFD per unit. The consummation and timing of any future acquisitions will depend upon, among other things, whether we are able to:

identify attractive acquisition candidates;
negotiate acceptable purchase agreements;
obtain financing for these acquisitions on economically acceptable terms, which may be more difficult at times when the capital markets are less accessible; and
outbid any competing bidders.

We can offer no assurance that we will be able to successfully consummate any future acquisitions, whether from Shell or any third parties. If we are unable to make future acquisitions, our future growth and ability to increase distributions will be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in CAFD per unit as a result of incorrect assumptions in our evaluation of such acquisitions, unforeseen consequences or other external events beyond our control. We may incur difficulties and additional costs in connection with integrating an acquired asset or entity. Acquisitions involve numerous risks, inefficiencies and unexpected costs and liabilities.

Our pipeline loss allowance exposes us to commodity risk.
Our long-term transportation agreements and tariffs for crude oil shipments include a pipeline loss allowance. We collect pipeline loss allowance to reduce our exposure to differences in crude oil measurement between origin and destination meters, which can fluctuate widely. This arrangement exposes us to risk of financial loss in some circumstances, including when the crude oil is received from a ship or connecting carrier using different measurement techniques, or resulting from solids and water produced from the crude oil. It is not always possible for us to completely mitigate the measurement differential. If the measurement differential exceeds the loss allowance, the pipeline must make the customer whole for the difference in measured crude oil. Additionally, we take title to any excess product that we transport when product losses are within the allowed levels, and we sell that product several times per year at prevailing market prices. This allowance oil revenue is subject to more volatility than transportation revenue, as it is directly dependent on our measurement capability and prevailing commodity prices.

The lack of diversification of our assets and geographic locations could adversely affect our ability to make cash distributions to our unitholders.
A significant amount of our revenue is generated from assets located in Texas and the Louisiana Gulf Coast and offshore Louisiana. Due to our lack of diversification in assets and geographic location, an adverse development in our businesses or areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for crude oil and refined products, could have a significantly greater impact on our results of operations and CAFD to our common unitholders than if we maintained more diverse assets and locations.

If we are deemed an “investment company” under the Investment Company Act of 1940, it could have a material adverse effect on our business and the price of our common units.
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In some cases, our assets include partial ownership interests in joint ventures. If a sufficient amount of our assets, or other assets acquired in the future, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, we may have to register as an investment company under the Investment Company Act, claim an exemption, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.

Risks Related to Our Customers and Counterparties

Our ability to renew or replace our third-party contract portfolio on comparable terms could materially adversely affect our business, financial condition, results of operations and cash flows, including our ability to make distributions.
As portions of our third-party contract portfolio come up for replacement or renewal, and capacity becomes available, adverse market conditions may prevent us from replacing or renewing the contracts on comparable terms. For example, two of our transportation services agreements on the Zydeco system expired in the fourth quarter of 2020, and have not been replaced.

Our ability to achieve favorable terms when replacing these or other expiring contracts could be affected by many factors, including:

prolonged lower commodity prices;
a decrease in demand for our services in the markets we serve;
increased competition for our services in the markets we serve; and
actions by FERC or other regulatory bodies that impact our rates or costs.

If we replace expiring agreements with short-term or spot transportation or storage services, our revenues could be more volatile than they would be under long-term arrangements. If we are unable to replace expiring agreements or renew the expiring agreements on comparable terms, it could materially adversely affect our business, financial condition, results of operations and cash flows, including our ability to make cash distributions to our unitholders.

We are exposed to the credit risks, and certain other risks, of our customers, and any material nonpayment or nonperformance by our customers could reduce our ability to make distributions to our unitholders.
We are subject to the risks of loss resulting from nonpayment or nonperformance by our customers. If any of our most significant customers default on their obligations to us, our financial results could be adversely affected. Our customers may be highly leveraged and subject to their own operating and regulatory risks. If any of our customers were to seek protection under the U.S. Bankruptcy Code or other insolvency laws, the court could void the customer’s contracts with us or allow our customer to reject such contracts. Similarly, if, due to effects of the COVID-19 pandemic or for any other reason, any of our customers or other counterparties were to seek to assert any force majeure or similar provision in its contract with us or other contractual defenses to performance available to them, including the doctrine of impossibility, impracticability of performance, frustration of performance and others, a court could excuse some or all of such customer’s or counterparty’s performance under its contract with us. For certain of our pipelines, we may have a limited pool of potential customers and may be unable to replace any customers who default on their obligations to us. Therefore, any material deterioration in the creditworthiness of our customers or any material nonpayment or nonperformance by our customers could have a material adverse effect on our business, financial condition and results of operations, including our ability to make cash distributions to our unitholders.

In addition, we are subject to political and economic risks that impact our customers. For example, the U.S. has gradually expanded sanctions that have impacted Petroleos de Venezuela, S.A. (“PdVSA”) and its subsidiaries as well as the Government of Venezuela. On January 28, 2019, the Trump Administration designated PdVSA on the Specifically Designated Nationals and Blocked Persons List administered by the U.S. Treasury Department’s Office of Foreign Asset Control (“OFAC”). As a result, U.S. persons are generally prohibited from engaging in transactions with PdVSA and its majority-owned subsidiaries. Certain of our customers are subsidiaries of PdVSA and, as a result, we and certain of our customers may be impacted if the General Licenses allowing for the temporary continuation of operations or engagements with PdVSA and its majority-owned subsidiaries expire in the future. Therefore, absent further action by the U.S. government and OFAC, the loss of customers as a result of the sanctions could have a material adverse effect on our business, financial condition and results of operations, including our ability to make cash distributions to our unitholders.
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Risks Related to Financing Our Business

If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make or increase quarterly cash distributions may be diminished or our financial leverage could increase. Other than our credit facilities, we do not have any contractual commitments with any of our affiliates to provide any direct or indirect financial assistance to us.
We will be required to do one of the following: use cash from our operations, incur borrowings or access the capital markets in order to fund our capital expenditures. If we do not make sufficient or effective capital expenditures, we may be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. The entities in which we own an interest may also incur borrowings or access the capital markets to fund capital expenditures and may require that we fund our proportionate share of such expenditures. Our and their ability to obtain financing or access the capital markets may be limited by our financial condition at such time as well as the covenants in our debt agreements, general economic conditions and contingencies, or other uncertainties that are beyond our control. Furthermore, market demand for equity issued by MLPs has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures and to fund acquisitions with the issuance of equity in the capital markets. Any further decline in the debt and equity capital markets may increase the cost of financing and the risks of refinancing maturing debt. In addition, lenders are facing increasing pressure to curtail their lending activities to companies in the oil and natural gas industry. There can be no assurance that the capital markets or borrowings will be available to us on acceptable terms or at all. The terms of any financing or the availability of cash on hand could limit our ability to pay distributions to our common unitholders. Incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.
Restrictions in our credit facilities could adversely affect our business, financial condition, results of operations, ability to make cash distributions to our unitholders and the value of our units.
We will be dependent upon the earnings and cash flows generated by our operations in order to meet any debt service obligations and to allow us to make cash distributions to our unitholders. We have entered into two revolving credit facilities and three fixed rate facilities, and Zydeco has entered into a senior unsecured revolving credit facility with an affiliate of Shell with a total capacity of $3,590 million, under which a total of $2,694 million was drawn as of December 31, 2020. Borrowings under our credit facilities were used to fund in part our acquisitions in 2019 and 2018. Restrictions in our credit facilities and any future financing agreements could restrict our ability to finance our future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders.
The restrictions in our credit facilities could affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our credit facilities could result in an event of default which would enable our lenders to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If the payment of our debt is accelerated, defaults under our other debt instruments, if any, may be triggered, and our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Credit Facilities in this report for additional information about our credit facilities.
Increases in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Interest rates on current and future credit facilities and debt offerings could increase above current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
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IT/Cyber-security/Data Privacy/Terrorism Risks

We rely heavily on information technology systems for our operations, and a cyber-incident could result in information theft, data corruption, operational disruption and/or financial loss.
Our business is increasingly dependent on electronic and digital technologies to conduct day-to-day operations, including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines.

We depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, some of which are owned or operated by third-party vendors, to process and record financial and operating data and to communicate with our employees and business partners. We use our Parent’s IT systems, which are dependent on key contractors supporting the delivery of IT services. Our business partners, including vendors, service providers and financial institutions, are also dependent on digital technology. The technologies needed to conduct midstream activities make certain information the target of theft, sabotage or misappropriation.

Shell continuously strives to further improve its cyber-security capabilities to reduce the likelihood of successful cyber-attacks. Shell’s IT landscape is protected by various detective and protective technologies in line with industry best practices. Although these cybersecurity programs and protocols are in place, our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information or other disruption of our business operations. In addition, certain cyber-incidents, such as those related to advanced persistent threats, may be difficult to detect or may remain undetected for an extended period.

A cyber-incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:

a cyber-attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;
a cyber-attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;
a cyber-attack on a communications network or power grid could cause operational disruption, resulting in loss of revenues;
a deliberate corruption of our financial or operational data could result in events of non-compliance, which could lead to regulatory fines or penalties; and
business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units.

Our implementation of various controls and processes, including incorporating a risk-based cyber security framework, to monitor and mitigate the potential impacts of security threats and vulnerabilities to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures, or measures taken by our third-party vendors, will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities or to repair or replace IT equipment or systems.

Terrorist or cyber-attacks and threats, or escalation of military activity in response to these attacks, could have a material adverse effect on our business, financial condition or results of operations.
Terrorist attacks and threats, cyber-attacks or escalation of military activity in response to these attacks may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the United States. For example, in 2020, the U.S. Government issued an alert to asset owner-operators across all sectors after a ransomware attack on a U.S. pipeline operator caused the operator to shut down operations for two days. Due to increased technology advances, we have become more reliant on technology to increase efficiency in our business. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, results of operations, financial condition or cash
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flows, including our ability to make cash distributions to our unitholders. Our insurance may not protect us against such occurrences, or, if coverage is available, we cannot ensure that it will fully cover all potential losses.

Our adoption of a new enterprise resource planning system could impact our internal controls over financial reporting and
related processes, which in turn could impact the timeliness and reliability of our consolidated financial statements.
During the second quarter of 2020, we implemented a new enterprise resource planning (“ERP”) system. In connection with this implementation, we have updated our processes related to internal control over financial reporting, as necessary, to accommodate applicable changes in our business processes. While we believe that the ERP system and related changes to internal controls will ultimately strengthen our internal control over financial reporting, there are inherent challenges in implementing a new ERP system and undertaking a transition from the legacy ERP system to the new ERP system, including the need for personnel to learn a new system, the ongoing detection and remediation of any compatibility or other issues as we utilize the new system, the use of manual processes to bridge any interim gaps within the new system and the ongoing development of testing for these control changes. Disruptions in these processes could impact our ability to provide important information to our management, send invoices and track payments, fulfill contractual obligations, accurately maintain books and records, provide accurate, timely and reliable reports on our financial and operating results or otherwise operate our business. In addition, we may experience periodic or prolonged disruption of our financial functions arising out of the implementation and conversion, general use of the ERP system, other periodic upgrades or updates or other external factors that are outside of our control. If any of these risks occur and have a material adverse effect on our internal control over financial reporting, we may not be able to effectively complete our financial reporting process and prepare consolidated financial statements on a timely basis, and we may need to revise our controls or adopt new controls to prevent any deficiencies in our internal controls environment.

Violations of data protection laws carry fines and expose us to criminal sanctions and civil suits.
Along with our own confidential data and information in the normal course of our business, we and our affiliates collect and retain significant volumes of data, some of which are subject to certain laws and regulations. The regulations regarding the transfer and use of this data both domestically and across international borders are becoming increasingly complex. This data is subject to governmental regulation at the federal, state, international, national, provincial and local levels in many areas of our business, including data privacy and security laws, such as the EU GDPR, the CCPA and new or emerging legislation in other jurisdictions in which our Parent or affiliates operate, such as Turkey, Brazil, China and India. These laws may also expose us to significant liabilities and penalties if any company we acquire has violated or is not in compliance with applicable data protection laws.

The EU GDPR came into force in May 2018. The GDPR applies to personal data and activities that may be conducted by us, directly or indirectly through vendors and subcontractors, from an establishment in the EU. As interpretation and enforcement of the GDPR evolves, it creates a range of new compliance obligations, which could cause us to incur costs or require us to change our business practices in a manner adverse to our business. Failure to comply could result in significant penalties of up to a maximum of 4% of our global turnover, which could materially adversely affect our business, reputation, results of operations, and cash flows. The GDPR also requires mandatory breach notification to the appropriate regulatory authority and impacted data owners.

The CCPA became effective on January 1, 2020 and gives California residents specific rights regarding their personal information, requires that companies take certain actions, including notifications of security incidents, and applies to activities regarding personal information that may be collected by us, directly or indirectly, from California residents. In addition, the CCPA grants California residents statutory private rights of action in the case of a data breach. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could cause us to change our business practices, with the possibility of significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations and cash flows.

In addition to imposing fines, regulators may also issue orders to stop processing personal data, which could disrupt operations. We or our Parent could also be subject to litigation from persons or corporations allegedly affected by data protection violations. Violation of data protection laws is a criminal offense in some countries, and individuals can be imprisoned or fined. We cannot ensure that our current practices and policies in the area of personal data protection will be sufficient to comply with all current, new or emerging rules or regulations applicable to us nor that they mitigate all of the associated risks to our business. Any violation of these laws or resulting harm to our reputation could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.

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Risks Inherent in an Investment in Us
Our general partner and its affiliates, including Shell, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of Shell, and it is under no obligation to adopt a business strategy that favors us.
As of December 31, 2020, SPLC owned a 68.5% limited partner interest in us and owned and controlled our general partner. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of us and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is not adverse to the best interests of its owner, SPLC. Conflicts of interest may arise between SPLC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates, including SPLC, over the interests of our common unitholders. These conflicts include, among others, the following situations:

neither our Partnership Agreement nor any other agreement requires SPLC to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by SPLC to undertake acquisition opportunities for itself;
SPLC’s directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of SPLC, which may be contrary to our interests; in addition, many of the officers and directors of our general partner are also officers and/or directors of SPLC and will owe fiduciary duties to SPLC and its owners;
SPLC may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
disputes may arise under agreements pursuant to which SPLC and its affiliates are our customers;
our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
our general partner will determine the amount and timing of many of our capital expenditures;
our general partner will determine which costs incurred by it are reimbursable by us;
our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
our general partner intends to limit its liability regarding our contractual and other obligations;
our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 75% of the common units;
our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including under the Omnibus Agreement effective February 1, 2019 by and among us, our general partner, SPLC and the Operating Company (the “2019 Omnibus Agreement”) and our other agreements with SPLC and its affiliates; and
our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Under the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

Our Partnership Agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon our cash reserves and external financing sources, including borrowings under our credit facilities and the issuance of debt and equity securities, to
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fund future acquisitions and other expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, the requirement in our Partnership Agreement to distribute all of our available cash and our current cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations.
Our credit facilities restrict our ability to incur additional debt including the issuance of debt securities, except for incurring bank loans or loans from affiliates up to other certain levels. To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our Partnership Agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt (under our revolving credit facilities or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders.
The fees and reimbursements due to our general partner and its affiliates, including SPLC, for services provided to us or on our behalf will reduce our CAFD. In certain cases, the amount and timing of such reimbursements will be determined by our general partner and its affiliates, including SPLC.
Pursuant to our Partnership Agreement, we reimburse our general partner and its affiliates, including SPLC, for costs and expenses they incur and payments they make on our behalf. Pursuant to the 2019 Omnibus Agreement and our Zydeco operating and management agreement, we pay an annual fee, currently approximately $11 million and $9 million, respectively, to SPLC for general and administrative services. In addition, pursuant to the 2019 Omnibus Agreement, we reimburse our general partner for payments to SPLC for other expenses incurred by SPLC on our behalf to the extent the fees relating to such services are not included in the general and administrative services fee. We also reimburse our general partner and SPLC, as applicable, for certain services provided under our operating agreements related to Pecten, Sand Dollar and Triton. For the year ended December 31, 2020, we reimbursed our general partner and SPLC $16 million and $13 million, respectively, under these operating agreements. Each of these payments will be made prior to making any distributions on our common units. The reimbursement of expenses and payment of fees to our general partner and its affiliates will reduce our CAFD. There is no limit on the fee and expense reimbursements that we may be required to pay to our general partner and its affiliates.

Our Partnership Agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our Partnership Agreement contains provisions that replace fiduciary duties applicable to a corporation with contractual duties and restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement provides that:

whenever our general partner (acting in its capacity as our general partner), the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was not adverse to our best interests, and, except as specifically provided by our Partnership Agreement, will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or equitable principle;
our general partner may make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the Partnership Agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include: how to allocate corporate opportunities among us and its other affiliates, whether to exercise its limited call right, whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner, and how to exercise its voting rights with respect to the units it owns;
our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of
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competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
our general partner will not be in breach of its obligations under the Partnership Agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub-bullet points above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights
of, holders of our common units.
Our Series A Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for common unitholders to sell our common units in the future.

In addition, until the conversion of our Series A Preferred Units into our common units or their redemption in connection with a change of control, holders of our Series A Preferred Units will receive cumulative quarterly distributions at a rate of $0.2363 per Series A Preferred Unit per quarter. We are not permitted to pay any distributions on any junior securities, including on any of our common units, prior to paying the quarterly distribution payable on the Series A Preferred Units, including any previously accrued and unpaid distributions.

Our obligation to pay distributions on our Series A Preferred Units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, distributions on junior securities, including on our common units, and other general partnership purposes. Our obligations to the holders of our Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

Units held by ineligible holders may be subject to redemption.
We have adopted certain requirements regarding those investors who may own our common units. Eligible taxable holders are limited partners whose, or whose owners’, federal income tax status does not have or is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or a similar regulatory body, as determined by our general partner with the advice of counsel. Ineligible holders are limited partners (a) who are not an eligible taxable holder or (b) whose nationality, citizenship or other related status would create a substantial risk of cancellation or forfeiture of any property in which we have an interest, as determined by our general partner with the advice of counsel. In certain circumstances set forth in our Partnership Agreement, units held by an ineligible holder may be redeemed by us at the then-current market price, which is the average of the daily closing prices for the 20 consecutive trading days immediately prior to the redemption date. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

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Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by a provision of our Partnership Agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be used to vote on any matter.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the member of our general partner, which is a wholly owned subsidiary of SPLC. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot remove our general partner without its consent.
Unitholders will be unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove our general partner.

Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our Partnership Agreement does not restrict the ability of SPLC to transfer all or a portion of its general partner interest or its ownership interest in our general partner to a third party. Our general partner, or the new owner of our general partner, would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

We may issue additional units without unitholder approval, which would dilute unitholder interests.
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, there are no limitations in our Partnership Agreement on our ability to issue equity securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

our existing unitholders’ proportionate ownership interest in us will decrease;
the amount of cash we have available to distribute on each unit may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of our common units may decline.
SPLC may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of December 31, 2020, SPLC held 269,457,304 common units. Additionally, we have agreed to provide SPLC with certain registration rights under applicable securities laws. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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Our general partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.
Our Partnership Agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.
Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 75% of our then-outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price, as calculated pursuant to the terms of our Partnership Agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. As of December 31, 2020, our general partner and its affiliates owned approximately 68.5% of our common units.

Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our Partnership Agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. We are organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if a unitholder were a general partner if a court or government agency were to determine that (i) we were conducting business in a state but had not complied with that particular state’s partnership statute; or (ii) a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.

Unitholders may have to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that, for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable both for the obligations of the transferor to make contributions to us that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our Partnership Agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

The NYSE does not require a publicly-traded partnership like us to comply with certain of its corporate governance requirements.
Because we are a publicly-traded partnership, the New York Stock Exchange (the “NYSE”) does not require us to have, and we do not intend to have, a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. See Part III, Item 10. Directors, Executive Officers and Corporate Governance in this report.

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Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our CAFD would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our CAFD would be substantially reduced. In addition, several states are evaluating changes to current law which could subject us to additional entity-level taxation and further reduce the CAFD to unitholders.

The present federal income tax treatment of publicly-traded partnerships or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly-traded partnerships. If successful, such a proposal could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted or will materially change interpretations of the current law, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes would have a material adverse effect on our financial condition, cash flows, ability to make cash distributions to our unitholders and the value of an investment in our common units.

Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions from us. A unitholders share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law and may be substantially different from any estimate we make in connection with a unit offering.
A unitholders’ allocable share of our taxable income will be taxable to it, which may require the unitholder to pay federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distribution at all.

A unitholders’ share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt. A unitholders’ ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, our net interest rate deductions under the TCJA are limited to 30% of our “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a unitholders’ taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.
From time to time, in connection with an offering of our units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of units purchased in the offering to which the estimate relates, the estimate may be incorrect, due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.

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If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our CAFD.
Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which our common units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our CAFD.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the TCJA, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization or depletion. For our 2020 taxable year, the Coronavirus Aid, Relief, and Economic Security Act increases the 30% adjusted taxable income limitation to 50%, unless we elect not to apply such increase, and for purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute our 2020 adjusted taxable income with our 2019 adjusted taxable income.

Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, the unitholders will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income (“UBTI”) and will be taxable to them. Under the TCJA, an exempt organization is required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and applicable state tax returns and pay tax on their share of our taxable income.

Under the TCJA, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the U.S. Department of the Treasury and the IRS have suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units, that occur before January 1, 2022. Under recently finalized Treasury Regulations, such withholding will be required on open market transactions, but in the case of a transfer made through a broker, a partner’s share of liabilities will be excluded from the amount realized. In addition, the obligation to withhold will be imposed on the broker instead of the transferee (and we will generally not be required to withhold from the transferee amounts that should have been withheld by the transferee but were not withheld). These withholding obligations will apply to transfers of our common units occurring on or after January 1, 2022.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
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We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly simplifying convention but do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

If the IRS makes audit adjustments to our income tax returns, it (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our CAFD to our unitholders might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, our CAFD to our unitholders might be substantially reduced. Additionally, we may be required to allocate an adjustment disproportionately among our unitholders, causing the publicly-traded units to have different capital accounts, unless the IRS issues further guidance.

In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of our unitholders (without any compensation from us to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller, and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies, which could adversely affect the value of the common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. The IRS may challenge our valuation methods and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

If our assets were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our CAFD to our unitholders.
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If our assets are subjected to a material amount of additional entity-level taxation by individual states, our CAFD would be reduced. States are continually evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. We currently own assets and conduct business in certain states that impose an entity-level tax on partnerships, including Illinois, Texas and Washington. Imposition of an entity-level tax on us in other jurisdictions in which we do business, or to which we expand our operations, could substantially reduce our CAFD.

As a result of investing in our common units, unitholders will likely be subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future. Unitholders may be subject to such taxes, even if they do not live in the jurisdiction imposing the tax. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in a number of states, most of which currently impose a personal income tax on individuals, and most of which also impose an income or similar tax on corporations and certain other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose an income tax or similar tax. In certain states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent tax years. Some states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholders’ income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. It is each unitholder’s responsibility to file all federal, state and local tax returns required by applicable law to be filed by such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units. Prospective unitholders should consult their own tax advisors regarding such matters.

Entity level taxes on income from C corporation subsidiaries will reduce CAFD, and an individual unitholder’s share of dividend and interest income from such subsidiaries would constitute portfolio income that could not be offset by the unitholder’s share of our other losses or deductions.
A portion of our taxable income is earned through LOCAP, Explorer and Colonial, which are all C corporations. Such C corporations are subject to federal income tax on their taxable income at the corporate tax rate, which is currently 21%, and will likely pay state (and possibly local) income tax at varying rates, on their taxable income. Any such entity level taxes will reduce the CAFD to our unitholders. Distributions from any such C corporation will generally be taxed again to unitholders as dividend income to the extent of current and accumulated earnings and profits of such C corporation. As of December 31, 2020, the maximum federal income tax rate applicable to such qualified dividend income that is allocable to individuals was 20% (plus a 3.8% net investment income tax that applies to certain net investment income earned by individuals, estates and trusts). An individual unitholder’s share of dividend and interest income from LOCAP, Explorer, Colonial or other C corporation subsidiaries would constitute portfolio income that could not be offset by the unitholder’s share of our other losses or deductions.
Item 1B. UNRESOLVED STAFF COMMENTS
None.

Item 3. LEGAL PROCEEDINGS
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the ordinary course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our financial position, results of operations or cash flows. In addition, pursuant to the terms of the various agreements under which we acquired assets from Shell affiliates since our initial public offering, those affiliates, as applicable, will indemnify us for certain liabilities relating to litigation and environmental matters attributable to the ownership or operation of the acquired assets prior to our acquisition of those assets.
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Item 4. MINE SAFETY DISCLOSURES
Not applicable.
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 PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Quarterly Common Unit Prices and Cash Distributions Per Unit
Our common units trade on the New York Stock Exchange (the “NYSE”) under the symbol “SHLX.” As of February 22, 2021, SPLC owned 269,457,304 common units, representing an aggregate 68.5% limited partner interest in us, and 50,782,904 Series A perpetual convertible preferred units (the “Series A Preferred Units”). Pursuant to the Partnership Interests Restructuring Agreement with our general partner dated February 27, 2020 (the “Partnership Interests Restructuring Agreement”), all of the incentive distribution rights (“IDRs”) were eliminated and the 2% general partner economic interest was converted into a non-economic general partner interest in the Partnership. As of January 31, 2021, we had seven holders of record of our common units. In determining the number of unitholders, we consider clearing agencies and security position listings as one unitholder for each agency or listing.
Distributions of Available Cash
General
Our Partnership Agreement requires us to distribute all of our available cash to unitholders of record on the applicable record date, within 60 days after the end of each quarter.
Definition of Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
less, the amount of cash reserves established by our general partner to:
provide for the proper conduct of our business (including reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements, Series A Preferred Unit quarterly distributions and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law) subsequent to that quarter;
comply with applicable law, any of our or our subsidiaries’ debt instruments or other agreements; or
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;
plus, all cash and cash equivalents resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter;
plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination resulting from working capital borrowings after the end of the quarter.
The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our Partnership Agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.
General Partner Interest and Incentive Distribution Rights
Until April 1, 2020, our general partner owned an approximate 2% general partner economic interest in the Partnership, including the IDRs. On April 1, 2020, we closed the transactions contemplated by the Partnership Interests Restructuring Agreement, pursuant to which the IDRs were eliminated and the 2% general partner economic interest was converted into a non-economic general partner interest in the Partnership. As of December 31, 2020, our general partner holds a non-economic general partner interest in the Partnership, and affiliates of SPLC own a 68.5% limited partner interest in us (269,457,304 common units), as well as 50,782,904 Series A Preferred Units. Further, under the Second Amended and Restated Partnership Agreement, our general partner or its assignee has agreed to waive a portion of the distributions that would otherwise be
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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.
See Note 3 — Acquisitions and Other Transactions, Note 4 — Related Party Transactions and Note 11 — (Deficit) Equity in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for additional details.
Equity Compensation Plan
The information relating to our equity compensation plan required by Item 5 is incorporated by reference to such information as set forth in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters of this report.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 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 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.

Partnership Overview
We own, operate, develop and acquire pipelines and other midstream assets and logistic assets. As of December 31, 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, please see Part I, Item 1 — Business and Properties of this 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”). Our 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.

Refer to Note 3 — Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements included in Part II, Item 8 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
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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 2020 and certain anticipated 2021 impacts to net income and cash available for distribution (“CAFD”) include:

Hurricanes. As a result of several hurricanes, we incurred an impact of approximately $20 million to net income and CAFD in the latter half 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.

Planned Turnarounds. Certain connected producers had planned turnarounds during 2020. As a result, the impact to net income and CAFD from this turnaround activity was approximately $15 million for the year ended 2020. Further, we anticipate an impact of approximately $10 million to net income and CAFD from planned turnaround activity in 2021.

The broader market environment for our customers was challenging in 2019 and continued to be challenging during 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 $556 million and net income attributable to the Partnership was $543 million in 2020. We generated cash from operations of $650 million. As of December 31, 2020, we had cash and cash equivalents of $320 million, total debt of $2,692 million and unused capacity under our revolving credit facilities of $896 million.
Our 2020 operations and strategic initiatives demonstrated 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
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 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 reconciliation of GAAP measures net income and cash provided by operating activities to non-GAAP measures Adjusted EBITDA and CAFD.

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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 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 Unit distributions, 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 will 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 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 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 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.
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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. It is expected that the project would be fully operational with incremental growth volumes arriving 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. Two of these T&D agreements expired in the fourth quarter of 2020, and have not been replaced. The T&D agreements that expired accounted for less than 10% of our revenue for 2020. There are several ways in which this revenue could be replaced in the future, such as through re-contracting or spot shipments, the outcome of which will be dependent on market and customer dynamics.

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. During 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
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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, further increases in COVID-19 infection rates could have additional 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 during 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 2020 versus 2019 due to demand destruction resulting from the COVID-19 pandemic.

Offshore crude transportation volumes were down in 2020 versus 2019 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 2020 versus 2019 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 against our proportionate share of certain costs and expenses with respect to this project. Costs incurred and reimbursed during 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 incurred approximately $13 million in maintenance capital expenditures in 2020 to complete the project. Any remaining spend in the first quarter of 2021 is not expected to be material.

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 by the end of the first quarter of 2021. SPLC has elected to fund the installation of the equipment necessary to enable greater throughput
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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 with incremental growth volumes arriving 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. 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 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 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 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 2.0% starting on July 1, 2020. Rate complaints are currently pending at FERC in Docket Nos. OR18-7-002, 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 currently scheduled for August 2021. A FERC decision is anticipated by spring 2022.

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 to
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refile their 2019 FERC Form No. 6 either revising their ROE to include the CAPM model or stating 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 6 annual reports. Both the elimination of the income tax allowance, as well as the corporate income tax reduction enacted as part of the TCJA, were considered by FERC in the order on the five-year review that was issued on December 17, 2020, although FERC declined in that order to incorporate the effect of the income tax allowance elimination in setting the new indexing adjustment. 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 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. After reviewing the comments and reply comments by interested parties, FERC issued an order on December 17, 2020 adopting a new formula of PPI-FG plus 0.78% for the next five-year period commencing on July 1, 2021. This order is subject to rehearing and possible judicial review.

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, 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 HCAs to pipelines in Moderate Consequence
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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 liquids side, all onshore lines have leak detection and are currently inspected under our 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.

Acquisition Opportunities
We may 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.

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Results of Operations
202020192018
Revenue$481 $503 $525 
Costs and expenses
Operations and maintenance162 124 162 
Cost of product sold24 36 32 
Loss (gain) from revision of ARO and disposition of fixed assets— (3)
General and administrative56 60 60 
Depreciation, amortization and accretion50 49 46 
Property and other taxes20 17 16 
Total costs and expenses
312 288 313 
Operating income169 215 212 
Income from equity method investments417 373 235 
Dividend income from other investments— 14 67 
Other income40 36 31 
Investment, dividend and other income457 423 333 
Interest income23 
Interest expense93 96 64 
Income before income taxes556 546 483 
Income tax expense— — 
Net income556 546 482 
Less: Net income attributable to noncontrolling interests13 18 18 
Net income attributable to the Partnership$543 $528 $464 
Preferred unitholder’s interest in net income attributable to the Partnership36 — — 
General partner’s interest in net income attributable to the Partnership55 147 134 
Limited Partners’ interest in net income attributable to the Partnership’s common unitholders$452 $381 $330 
Adjusted EBITDA attributable to the Partnership (1)
$767 $730 $616 
Cash available for distribution attributable to the Partnership’s common unitholders (1)
$658 $619 $536 
(1) For a reconciliation of Adjusted EBITDA and CAFD 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)
202020192018
Zydeco - Mainlines577 657 623 
Zydeco - Other segments142 267 249 
Zydeco total system719 924 872 
Amberjack total system326 362 324 
Mars total system490 546 516 
Bengal total system429 511 539 
Poseidon total system290 265 235 
Auger total system74 77 58 
Delta total system211 258 228 
Na Kika total system40 39 42 
Odyssey total system119 145 115 
Colonial total system2,349 2,617 2,616 
Explorer total system474 650 649 
Mattox total system (2)
71 62 
N/A (3)
LOCAP total system960 1,172 1,228 
Other systems427 348 344 
Terminals (4) (5)
Lockport terminaling throughput and storage volumes223 228 226 

Revenue per barrel ($ per barrel)
Zydeco total system (6)
$0.49 $0.52 $0.74 
Amberjack total system (6)
2.37 2.37 2.50 
Mars total system (6)
1.35 1.31 1.19 
Bengal total system (6)
0.41 0.41 0.34 
Auger total system (6)
1.28 1.43 1.34 
Delta total system (6)
0.59 0.58 0.57 
Na Kika total system (6)
0.91 0.80 0.79 
Odyssey total system (6)
0.94 0.92 0.88 
Lockport total system (7)
0.23 0.22 0.21
Mattox total system (8)
1.52 
N/A (9)
N/A (9)
(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) 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 162 thousands of barrels per day for 2020.
(3) Mattox came online during the second quarter of 2019 and therefore there are no volumes presented for 2018.
(4) Terminaling throughput is defined as the volume of delivered barrels and storage is defined as the volume of stored barrels.
(5) 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.
(6) 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.
(7) 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.
(8) 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.
(9) Mattox is billed at a fixed rate (see note above) per dedication and transportation agreements. The rates for 2019 and 2018 are not applicable, as we only entered into these agreements in April 2020. These agreements do not apply to 2019 and 2018.


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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.
 
202020192018
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income$556 $546 $482 
Add:
Loss (gain) from revision of ARO and disposition of fixed assets— (3)
Allowance oil reduction to net realizable value
Depreciation, amortization and accretion61 49 46 
Interest income(23)(4)(2)
Interest expense93 96 64 
Income tax expense— — 
Cash distribution received from equity method investments541 466 301 
Less:
Equity method distributions included in other income37 33 24 
Income from equity method investments 417 373 235 
Adjusted EBITDA782 750 635 
Less:
Adjusted EBITDA attributable to noncontrolling interests15 20 19 
Adjusted EBITDA attributable to the Partnership767 730 616 
Less:
Series A Preferred Units distribution36 — — 
Net interest paid by the Partnership (1)
93 92 62 
Income taxes paid attributable to the Partnership— — — 
Maintenance capex attributable to the Partnership20 28 25 
Add:
Principal and interest payments received on financing receivables23 — — 
Net adjustments from volume deficiency payments attributable to the Partnership17 (10)(4)
Reimbursements from Parent included in partners’ capital— 19 11 
Cash available for distribution attributable to the Partnership’s common unitholders $658 $619 $536 
(1) Amount represents both paid and accrued interest attributable to the period.












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202020192018
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities $650 $597 $507 
Add:
Interest income(23)(4)(2)
Interest expense93 96 64 
Income tax expense— — 
Return of investment91 66 48 
Less:
Change in deferred revenue and other unearned income24 (11)(4)