Shell Midstream Partners, L.P. - Annual Report: 2021 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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(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, 2021


☐			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

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Shell Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)

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Delaware						46-5223743
(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 class	Trading Symbol(s)	Name of each exchange on which registered
Common Units, Representing Limited Partner Interests	SHLX	New 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 filer

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, 2021, was $1,828 million, based on the closing price of such units of $14.77 as reported on the New York Stock Exchange on such date. The registrant had 393,289,537 common units outstanding as of February 24, 2022.

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 outcome of the non-binding, preliminary proposal made by SPLC to acquire all of our issued and outstanding common units not already owned by SPLC or its affiliates.

•The continued ability of Shell and our non-affiliate customers to satisfy their obligations under our commercial and other agreements.

•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 (including our vaccine mandate for offshore employees), and any resulting 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, including disruptions caused by hurricanes; 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 current 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.

•The factors generally described in Part I, Item 1A. Risk Factors of this report.

GLOSSARY OF TERMS

Barrel: 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: U.S. 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.

OPEC: The Organization of Petroleum Exporting Countries.

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



Item			Page

PART I
1 and 2. Business and Properties			6
1A. Risk Factors			23
1B. Unresolved Staff Comments			46
3. Legal Proceedings			47
4. Mine Safety Disclosures			48

PART II
5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			49
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			51
7A. Quantitative and Qualitative Disclosures About Market Risk			70
8. Financial Statements and Supplementary Data			72
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			119
9A. Controls and Procedures			119
9B. Other Information			119

PART III
10. Directors, Executive Officers and Corporate Governance			121
11. Executive Compensation			126
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			131
13. Certain Relationships and Related Transactions, and Director Independence			132
14. Principal Accounting Fees and Services			135

PART IV
15. Exhibits, Financial Statement Schedules			136
16. Form 10-K Summary			139
Signatures			140

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 “Shell” or “Parent” refer collectively to 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 (the “Operating Company”) or through direct ownership. Our general partner is Shell Midstream Partners GP LLC (our “general partner”).

As of December 31, 2021, 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, 2021, 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.

The following table reflects our ownership interests as of December 31, 2021:


	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)	100.0	%
Mattox Pipeline Company LLC (“Mattox”)	79.0	%
Amberjack Pipeline Company LLC (“Amberjack”) – Series A/Series B	75.0% / 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) Prior to May 1, 2021, we owned a 92.5% ownership interest in Zydeco and SPLC owned the remaining 7.5% ownership interest. Effective May 1, 2021, SPLC transferred its 7.5% ownership interest to us as part of the May 2021 Transaction. Refer to Note 3 —Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for additional information.

2021 Transactions

May 2021 Transaction

Effective May 1, 2021, Triton sold to Equilon Enterprises LLC d/b/a Shell Oil Products US (“SOPUS”), as designee of SPLC, substantially all of the assets associated with its clean products truck rack terminal and facility in Anacortes, Washington (the “Anacortes Assets”). In exchange for the Anacortes Assets, SPLC paid Triton $10 million in cash and transferred to the Operating Company, as designee of Triton, SPLC’s 7.5% interest in Zydeco (the “May 2021 Transaction”). Effective May 1, 2021, the Partnership owns a 100.0% ownership interest in Zydeco.

The May 2021 Transaction closed pursuant to a Sale and Purchase Agreement dated April 28, 2021 between Triton and SPLC, effective May 1, 2021 (the “May 2021 Sale and Purchase Agreement”). The May 2021 Sale and Purchase Agreement contains customary representations, warranties and covenants of Triton and SPLC. SPLC, on the one hand, and Triton, on the other hand, have agreed to indemnify each other and their respective affiliates, officers, directors and other representatives against certain losses resulting from any breach of their representations, warranties or covenants contained in the May 2021 Sale and Purchase Agreement, subject to certain limitations and survival periods.

In connection with the May 2021 Transaction, the Partnership and SPLC entered into a Termination of Voting Agreement dated April 28, 2021 and effective May 1, 2021, under which they agreed to terminate the Voting Agreement dated November 3, 2014 between the Partnership and SPLC, relating to certain governance matters for their respective direct and indirect ownership interests in Zydeco.

Auger Divestiture

On April 29, 2021, we executed an agreement to divest the 12” segment of the Auger pipeline, effective June 1, 2021. We received approximately $2 million in cash consideration for this sale. In anticipation of the intended divestment, we recorded an impairment charge of approximately $3 million during the first quarter of 2021. The remainder of the Auger pipeline continues to operate under the ownership of Pecten.

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, 2021:

Our Assets and Operations

Our assets consist of the following systems:

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 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 the 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 the 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 the 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. 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.

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% contracted via four terminal services agreements with expirations ranging from mid-2022 through 2024.

Other Midstream Assets

We have interests in certain other midstream assets. We own an interest in a network of refinery 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, 2021:


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 Neches	250	—
Port Neches to Houma	375	—
Houma to Clovelly	425	—
Houma to St James	270	—
Delta crude oil system	420	—

Offshore Crude Oil Pipelines
Amberjack crude oil system
Jack St. Malo	200	—
Tahiti	300	—
ADP 24”	300	—
Jackalope	200	—
Genesis	50	—
Auger crude oil system
Enchilada Platform to Ship Shoal 28P	200	—
14/16” Auger export line	150	—
Na Kika crude oil system	160	—
Mars crude oil system (1)
Mars TLP to West Delta 143	100	—
Olympus TLP to West Delta 143	100	—


West Delta 143 to Fourchon	400	—
Fourchon to Clovelly	600	—
Poseidon crude oil system	350	—
Odyssey crude oil system	220	—
Mattox crude oil system	300	—
Proteus crude oil system
Thunder Horse TLP to South Pass 89E	425	—
Endymion crude oil system
South Pass 89E to Clovelly	425	—

Refined Products Pipelines
Bengal product system
Norco to Baton Rouge tank farm	305	—
Colonial product system	2,500	—
Explorer product system	660	—

Terminals and Storage
Triton refined products terminals (2)
Colex	—	2,585
Des Plaines	—	1,060
Portland	—	405
Seattle	—	520
Norco Assets (3)	—	10,800
Lockport terminal system	—	2,000

Other Midstream Assets
Refinery Gas Pipelines (4)
Houston Ship Channel	3,960	—
Texas City	5,280	—
Garyville – Norco	3,720	—
Convent to Garyville	3,840	—
Norco – Paraffinic	3,720	—
Permian Basin gas gathering system (4)	240	—
LOCAP pipeline system and storage facility	1,700	3,200
Cleopatra gas gathering system (4)
Atlantis TLP to Ship Shoal 332A	500	—

(1) In addition to the pipeline capacity above, Mars also has storage capacity leases of storage caverns with a related party.

(2) The Des Plaines, Portland and Seattle refined products terminals have truck racks that are not included in the above table.

(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.

Our Relationship with Shell

Shell is an international energy company with expertise in the exploration, production, refining and marketing of oil and natural gas, and the manufacturing and marketing of chemicals. 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 onshore exploration and production interests and produces crude oil and natural gas throughout North America. Shell’s downstream portfolio includes interests in chemical processing plants throughout the United States, as well as a refinery on the

Gulf Coast. 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, 2021, 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 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 assets are subject to regulation by various federal, state and local agencies; for example, our interstate common carrier pipeline systems are subject to economic regulation by the FERC. Intrastate pipeline systems are regulated by the appropriate state agency.

The 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. The FERC’s regulations also require interstate common carrier petroleum pipelines to file with the FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.

Under the ICA, the FERC or interested persons may challenge existing or proposed new or changed rates, services or terms and conditions of service. The FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. A successful 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. The 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. The 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.

EPAct required the FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, the 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. 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. The FERC’s indexing methodology is subject to review every five years.

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. 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.

EPAct also 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. The 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.

With respect to indexing, in 2020, the FERC commenced a proceeding to set the indexing formula for the five years commencing July 1, 2021. While the FERC initially adopted a formula of PPI-FG plus 0.78% on December 17, 2020, the FERC issued an order on rehearing on January 20, 2022 that revised the formula to PPI-FG minus 0.21%. The lower indexing adjustment resulted from the FERC adjusting the data set used to assess pipeline cost; taking into account the elimination of the income tax allowance and previously accrued accumulated deferred income tax (“ADIT”) balances for master limited partnership (“MLP”)-owned pipelines; and using updated cost data for 2014. The FERC’s order on rehearing is subject to potential judicial review. The rehearing order requires pipelines to recalculate their rate ceiling levels using the PPI-FG minus 0.21% formula for the period July 1, 2021 to June 30, 2022. For any rate that exceeds the recalculated ceiling level, the pipeline is required to file a rate reduction with the FERC to be effective March 1, 2022. We do not expect these rate recalculations to have a material effect on our financial position, operating results or cash flows.

We cannot predict whether or to what extent the index factor may change in the future.

In 2018, with respect to cost-of-service ratemaking, the FERC issued a policy statement and related orders that eliminated the recovery of an income tax allowance by MLP oil and gas pipelines in cost-of-service-based rates, although an MLP may claim in an individual proceeding 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.” To the extent that we charge cost-of-service based rates, those rates could be affected by any changes in the FERC’s income tax allowance policy to the extent our rates are subject to complaint or challenge by the FERC acting on its own initiative, or to the extent that we propose new cost-of-service rates or changes to our existing rates.

In May 2021, Zydeco, Mars and LOCAP filed with the FERC to decrease rates subject to the FERC’s indexing adjustment methodology that were previously at their ceiling levels by 0.5812% starting on July 1, 2021 and are required by the January 20, 2022 rehearing order to recalculate their ceiling levels and file a rate reduction for any rates that exceed the recalculated ceiling to be effective March 1, 2022. Rate complaints are currently pending at the 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. A partial initial decision from the Administrative Law Judge was issued on December 1, 2021 finding that Colonial lacks the ability to exercise market power in the 90-county Gulf Coast geographic origin market, but no longer lacks the ability to exercise market power in the 16-county Tuscaloosa-Moundville geographic origin market. The partial initial decision also found that Colonial’s method of net recoveries of product loss is unjust and unreasonable and that Colonial should adopt a fixed allowance oil deduction for shortages in deliveries and determine the amount of reparations, if any, owed to shippers. The partial initial decision is a recommendation to the FERC based on the evidence received into the record by the Administrative Law Judge. The FERC may decide to adopt the recommendations made in full or part or make different determinations. If the FERC adopts the partial initial decision in whole, in addition to the changes in product loss charges described above, which may adversely affect Colonial, Colonial’s rates in respect of the 16-county Tuscaloosa-Moundville geographic origin market will no longer be market-based and could be reduced. The parties to the case will be filing briefs to argue for or against the recommendations, which will be considered by the FERC in its ruling. The timing of such ruling is unknown. For the issues not covered by the initial decision, the deadline for the Administrative Law Judge to issue a partial initial decision covering those issues is April 29, 2022.

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.

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 landowners 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 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).

In early 2021, PHMSA issued a revised map of the ecological High Consequence Areas (“HCAs”) in the Gulf of Mexico. This revised map expanded the ecological HCA of the Gulf of Mexico to include previously excluded dolphin and whale habitats. The HCA now encompasses most of the Gulf of Mexico. This places most liquid pipelines in the Gulf of Mexico in an HCA and subject to the assessment requirements of 49 CFR 195.452. This may impact certain operational activity such as the frequency at which certain inspections need to be performed and the types of inspections required at those intervals. The holistic impact to our business is uncertain at this time, but we expect that all companies with comparable Gulf of Mexico operations will be similarly impacted.

On June 14, 2021, as part of the self-executing provisions of the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020, the PHMSA published an advisory bulletin requiring operators to update inspection and maintenance plans to address eliminating hazardous leaks and minimizing releases of natural gas by December 27, 2021. This advisory bulletin is expected to have minimal impact on our operations but will require minor updates to our inspection and maintenance manuals.

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 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. The review was completed in November 2021 and recommends changes to leasing and permitting practices that, if implemented, could result in increased costs in the form of higher royalties and other charges, as well as restrictions on lands available for leasing activities. Certain lease sales resumed thereafter as a result of legal challenges to the moratorium; however on January 27, 2022, a federal judge invalidated oil and gas lease sales relating to 80 million acres in the Gulf of Mexico, concluding that the Biden administration failed to account for the associated climate change impact in auctioning off the leases. If our customers are unable to secure leases or 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 judicial decision, the executive order and our customers’ potential inability to secure leases, which could adversely affect our long-term 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.

Cybersecurity and Data Privacy

Given our dependence on Information Technology (“IT”) and Operational Technology (“OT”) 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 function, diminished productivity, loss of intellectual property, litigation, regulatory fines and/or reputational damage. Shell, like many other multinational company groups, is the target of attempts to gain unauthorized access to its systems and data through various channels, including by more sophisticated and coordinated actors, which are often referred to as advanced persistent threats. The intent of these attempted attacks range from data exfiltration, to extortion, to data manipulation, to destabilization and destruction.

We and/or our Parent protect our systems through our segmented architecture and with numerous technologies in line with industry best practices. We also maintain and regularly update cybersecurity plans, policies and procedures over our own IT and OT systems. In addition, we have strict protocols in place to better ensure the cybersecurity of any third parties who connect to our networks or process our data.

While the arrangements described above are in place, we cannot guarantee against compromise. A significant cyber-attack, should it be successful, could have a material effect on our operations. We maintain incident response and business continuity plans to mitigate any impact should such an attack occur.

For example, on May 7, 2021, the computerized equipment managing the Colonial pipeline was the target of a ransomware attack. We have a 16.125% ownership interest in Colonial, which owns and operates a pipeline that runs throughout the southern and eastern United States. Colonial proactively took certain systems offline to contain the threat and it paid a ransom in cryptocurrency to regain control of the equipment.

In the aftermath of this cyber intrusion, the Transportation Security Administration (“TSA”) issued two security directives. The first, issued in May 2021, requires owners and operators of TSA-designated critical pipelines to report confirmed and potential cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency (“CISA”) within 12 hours of discovery, designate a cybersecurity coordinator to be available 24 hours a day, seven days a week, review current practices and identify any gaps and related remediation measures to address cyber-related risks and report the results to the TSA and CISA within 30 days.

The second security directive, issued in July 2021, imposes additional obligations on owners and operators of TSA-designated critical pipelines. This directive requires pipeline owners and operators to develop and implement specific mitigation measures to protect against ransomware attacks and other known threats to IT and OT systems, to develop a cybersecurity contingency and recovery plan and to conduct cybersecurity assessments. We have complied with the requirements of the first directive, and

our team continues to work in collaboration with the TSA to complete the requirements of the second directive in a timely manner. We remain committed to working with the TSA and other companies in our industry to increase the physical and cyber security posture of our industry.

We and our affiliates collect, process and maintain significant volumes of confidential data, including personal data, which is increasingly subject to specific U.S. and global regulations, including the California Consumer Privacy Act, the UK and EU General Data Protection Regulation, and a host of new or emerging legislation in other jurisdictions in which our Parent or its affiliates operate, such as Turkey, Brazil, China and India. Many of these laws require specific transparency and security obligations, and they require us to afford certain rights to individuals. They can restrict our ability to freely transfer personal data across borders, including within Shell, and they increasingly carry significant penalties for failing to comply. They can also provide for private rights of action, including via class action.

For additional information about cybersecurity and privacy risks and the cybersecurity and privacy programs and protocols we have in place to protect against those risks, see Item 1A. Risk Factors – IT/Cyber-security/Data Privacy/Terrorism Risks in this report.

Existing Guidance

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.

In 2010, Shell 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 do not believe they 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. Moreover, 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.

For additional information regarding environmental matters that impacted our business prior to 2021, refer to Part I, Items 1 and 2 — Business and Properties — Environmental Matters in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 23, 2021.

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 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 the end of 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, but are not limited to, 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 GHGs, to which some of our facilities may become subject. For example, in November 2021, the EPA proposed new rules that would expand and strengthen emissions reduction requirements that are currently on the books for new, modified and reconstructed oil and natural gas sources, and would require states to reduce methane emissions from existing sources nationwide. 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 2016, the United States signed onto the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement 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.

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 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.

Shell 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 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 Shell 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.

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 (the “Corps”). Regulatory requirements governing wetlands as Clean Water Act-regulated “waters of the United States” (“WOTUS”) 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. The scope of WOTUS jurisdiction saw rapid change under the last two presidential administrations and is still evolving. In 2015, the EPA and the Corps adopted regulations that expanded the scope of WOTUS jurisdiction, but repealed these rules in 2019. In 2020, the two agencies adopted a new, narrower definition of scope of WOTUS jurisdiction. In August 2021, the 2020 rules were judicially vacated, and the EPA and the Corps halted their implementation. On November 18, 2021, the two agencies proposed a rule to restore the pre-2015 WOTUS definition. That proposal remains pending.

Further, the WOTUS permitting landscape is also subject to regulatory change, litigation and uncertainty. In 2020, the U.S. District Court for the District of Montana issued an order invalidating the Corps’ Nationwide Permit 12 (“NWP 12”), the general permit governing dredge-and-fill activities for oil and gas and other pipeline construction projects. This case is ongoing. In January 2021, the EPA and the Corps issued a final rule reissuing and restricting NWP 12 to oil and gas pipelines. However, environmental groups filed a judicial challenge, and the NWP 12 rulemaking is among the agency actions listed for review in a Biden Administration Executive Order. 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 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

Recently, rates of inflation in the United States have risen to historic levels, and such inflationary pressure has the potential to affect our financial condition and results of operations in various ways if it continues. For example, we may experience price increases for raw materials, which could increase our necessary capital expenditures, or see upward pressure on labor costs, which may indirectly increase our operating expenses as we would have to reimburse our affiliates’ actual costs at higher rates under certain agreements. These impacts would thereby limit the sustainability of our recent cost reduction initiatives. Conversely, to the extent that commodity prices increase along with inflation rates, we may see increased demand for our transportation services or be able to obtain a higher price for any product that we sell as a result of our PLA provisions.

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 Shell, 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 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 U.S. Securities and Exchange Commission’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.

•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 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.

•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.

•There can be no assurances that we will enter into a definitive agreement with SPLC related to SPLC’s proposal to

acquire all of our issued and outstanding common units not already owned by SPLC or its affiliates, or that we will

complete any transaction contemplated by such an agreement.

•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.

On March 11, 2020, a novel strain of coronavirus referred to as COVID-19 was officially declared a pandemic by the World Health Organization. In an effort to halt the outbreak, governments worldwide 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 initially caused a significant slowdown in the global economy and financial markets, but the worldwide vaccine rollouts in 2021 allowed governments to ease COVID-19 restrictions and lockdown protocols, and business activity improved. However, concerns regarding increasing infection rates (including an increase in COVID-19 cases resulting from the Omicron variant) have resulted in renewed lockdowns and other restrictions being imposed in some of the affected areas and such measures could be imposed in or affect other areas, and increasing rates of infection could lead to the workforce being absent due to illness or quarantine, all of 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, such as the Omicron variant), the efficacy and distribution of available vaccines or boosters thereto, 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. 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 OPEC members and co-operating non-OPEC resource holders (the “OPEC+ alliance”). Throughout the pandemic, these countries have instituted supply cuts in an effort to counter the demand destruction in the oil and gas markets caused by the effects of COVID-19, which has, at times, resulted in dramatically decreased oil and gas prices. The OPEC+ alliance ultimately reached an agreement in mid-July 2021 that was reaffirmed by the OPEC+ alliance in September 2021, to phase out the COVID-19 production cuts from August 2021 to December 2022. Additional downward pressure on the demand for and price of oil and gas due to these global factors could have substantial negative implications for our transportation revenue, allowance oil revenue and other sources of revenue related to or underpinned by commodity prices. While we saw an increase in both the demand for and price of crude oil in 2021, it is not without continued volatility. 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, the efficacy and timely distributions of available vaccines and boosters thereto and the extent and overall economic effects of the continuing governmental response to the pandemic.

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.

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, or 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, such as Hurricane Ida;

•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 ongoing 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. 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 if the customer cannot utilize the assets due to force majeure incidents when the assets are still operational. If we are unable to provide services to customers as a result of a force majeure incident that impacts a customer’s ability to store or throughput product, then customer payments may be reduced by a prorated amount up to 100% of the payments for such downtime based on a reduction in capacity or in nominated or historical throughput calculated for the duration of the business interruption. 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.

During 2021, certain connected producers had planned turnarounds. The impact to net income and CAFD was approximately $4 million for the year ended December 31, 2021. Further, we anticipate planned turnaround activity in 2022 to be approximately $20 million.

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, the demand for, and price of, oil and natural gas decreased significantly due to the effects of the COVID-19 pandemic and the resulting governmental regulations and travel restrictions aimed at slowing the spread of the virus. Throughout 2021, many of these restrictions were tempered, with several being lifted altogether. While we saw an increase in both the demand for and price of crude oil in 2021, it is not without continued volatility. Current global geopolitical and economic uncertainty continues to contribute to future volatility in financial and commodity markets. For example, the OPEC+ alliance stalemate, which ultimately ended in mid-2021, was resolved when the OPEC+ alliance agreed to phase out the COVID-19 production cuts from August 2021 to December 2022. We expect that the OPEC+ alliance decision will cause the crude oil market to remain relatively tight in the near and medium-term, as this increased production will likely align with the higher global demand.

The continuing effects of the COVID-19 pandemic and the resulting governmental responses worldwide may continue to impact demand 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 2022, 2021 and 2020 were as follows:


	WTI Crude Oil Prices
	High		Average		Low
January 2022	$	89.16	$	83.22	$	75.99
2021	85.64		68.14		47.47
2020	63.27		39.16		(36.98)

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 ongoing 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 the OPEC+ alliance 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.

If lower prices are sustained as a result of the factors noted above, it could lead to a material decrease in exploration, development and production 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 default on or 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 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.

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, with the exception of one policy, which is 90 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 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. 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 on 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, 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 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 the FERC under the ICA. The FERC uses prescribed rate methodologies for developing and changing regulated rates for interstate pipelines. Shippers may protest (and the FERC may investigate) the lawfulness of new or changed tariff rates, or may file a complaint against existing tariff rates. The 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 the 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 the FERC may prescribe new rates prospectively. A successful challenge of any of our rates, or any changes to the FERC’s approved rate or index methodologies, could adversely affect our revenue and our ability to make distributions to our unitholders.

From November 2017 through 2020, twelve separate, nearly identical complaints were filed with the 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 the FERC in Docket Nos. OR18-7-002, et al. and were set for hearing and settlement judge procedures. The FERC also severed the review of Colonial’s market-based rates into a separate, concurrent hearing. Since the consolidated complaint proceedings are ongoing, the 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.

With respect to our rates subject to indexing, in 2020, the FERC commenced a proceeding to set the indexing formula for the five years commencing on July 1, 2021. While the FERC initially adopted a formula of PPI-FG plus 0.78% on December 17, 2020, the FERC issued an order on rehearing on January 20, 2022 that revised the formula to PPI-FG minus 0.21%. The lower indexing adjustment resulted from the FERC adjusting the data used to assess pipeline cost, taking into account the elimination of the income tax allowance and previously accrued ADIT balances for MLP-owned pipelines; and using updated cost data for 2014. The FERC’s order on rehearing is subject to potential judicial review. The rehearing order requires pipelines to recalculate their rate ceiling levels using the PPI-FG minus 0.21% formula for the period July 1, 2021 to June 30, 2022. For any rate that exceeds the recalculated ceiling level, the pipeline is required to file a rate reduction with the FERC to be effective March 1, 2022. The reduction in the indexing adder and the requirement to file a rate reduction if a recalculated rate exceeds the ceiling level 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 the FERC, which may result in adverse findings, enforcement actions and penalties that could adversely affect our business financial position, results of operation and ability to make cash distributions to our unitholders. For example, each of Colonial and Explorer have been subject to audits by the FERC’s Office of Enforcement, resulting in Colonial and Explorer becoming subject to the audit’s findings and submission of a compliance plan and quarterly compliance reports.

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. The LPSC has a more stringent review of rate increases, though it does allow use of the FERC’s index, and may prohibit or limit future rate increases for intrastate movements regulated by Louisiana.

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.

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 the 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;

•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.

There can be no assurances that we will enter into a definitive agreement with SPLC related to SPLC’s proposal to acquire all of our issued and outstanding common units not already owned by SPLC or its affiliates, or that we will complete any transaction contemplated by such an agreement.

On February 11, 2022, the board of directors of our general partner received a non-binding, preliminary proposal letter from SPLC to acquire all of the Partnership’s issued and outstanding common units not already owned by SPLC or its affiliates (the “Proposal”). While the board of directors of our general partner has appointed the conflicts committee to review, evaluate and negotiate the Proposal (the “Potential Transaction”), there can be no assurances that we will enter into a definitive agreement with SPLC related to any Potential Transaction. Furthermore, should we enter into a definitive agreement with SPLC, we anticipate that the consummation of any Potential Transaction will be subject to a number of contingencies, and there can be no assurance that such definitive agreement will be executed or that any transaction will be consummated in a timely manner or at all.

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 in the types of our assets, as well as their 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 the lack of diversification in the types of our assets, as well as their geographic locations, 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 types of assets and in varied 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.

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.

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 the 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.

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 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 with an affiliate of Shell with a total capacity of $3,560 million, under which a total of $2,694 million was drawn as of December 31, 2021. 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.

IT/Cyber-security/Data Privacy/Terrorism Risks

We rely heavily on information technology systems for our operations, and cyber-incidents have and could in the future result in information theft, data corruption, operational disruption and/or financial loss, among other negative impacts to our business systems.

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.

Although Shell’s cybersecurity programs and protocols are in place, our technologies, systems and networks, and those of our business partners, have been, and may be in the future, the target of cyber-attacks or information security breaches and 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. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. The risk of a disruption or breach of our operational systems, or the compromise of the data processed in connection with our operations, through cybersecurity breach or ransomware attack has increased as attempted attacks have advanced in sophistication and number around the world.

Cyber-attacks are becoming more sophisticated, and U.S. government warnings have indicated that infrastructure assets,

including pipelines, have been and may be specifically targeted by certain groups. PHMSA has posted warnings to all pipeline owners and operators of the importance of safeguarding and securing their pipeline facilities and monitoring their supervisory control and SCADA systems for abnormal operations and/or indications of unauthorized access or interference with safe

pipeline operations based on recent incidents involving environmental activists. For example, on May 7, 2021, the computerized equipment managing the Colonial pipeline was the target of a cyberattack, and while Colonial proactively took certain systems offline to contain the threat, it paid a ransom in the form of cryptocurrency to regain control of the equipment. In response, the TSA issued two security directives in May and June of 2021 that pipeline owners must comply with. Potential security events have, and may in the future, implicate our pipeline systems or operating systems and may result in damage to our pipeline facilities and affect our ability to operate or control our pipeline assets; their operations could be disrupted and/or customer information could be stolen.

A cyber-incident or other security breach, involving either our information systems and related infrastructure or that of our business partners, has, and may in the future, expose our business to a risk of loss, misuse or interruption of critical physical assets or information and functions that affect the pipeline operations. Such losses could result in operational impacts, damage to our assets, public or personnel safety incidents, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions, litigation and a potential material adverse effect on our operations, financial position and results of operations. Some specific examples of potential negative impacts to our business are listed below:

•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. There is no certainty that costs incurred related to securing against threats will be recovered through rates. 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 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.

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.

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.

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, 2021, 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

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 $10 million for each agreement, 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 agreement related to Pecten, Sand Dollar and Triton. For the year ended December 31, 2021, we reimbursed our general partner and SPLC $27 million and $11 million, respectively, under this operating agreement. 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

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 the 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.

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.

Additionally, any conversion of our Series A Preferred Units to common units, whether at the holders’ election or at our election, would increase Shell’s ownership of our common units and also increase the number of our common units outstanding, which in turn may reduce distributable cash flow for the existing common units. Holders of our Series A Preferred Units may elect to convert all or any portion of their Series A Preferred Units into common units as of January 1, 2022. We may, in certain instances, elect to convert all or any portion of the Series A Preferred Units into common units after January 1, 2023. See Note 10 — (Deficit) Equity — Units Outstanding — Series A Preferred Units in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for additional details.

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, 2021, 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.

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, 2021, 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.

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, the then current U.S. presidential administration and 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. One such recent proposal was contained in the Biden Administration’s budget proposal released on May 28, 2021, which would repeal the application of the qualifying income exception to partnerships with income and gains from activities relating to fossil fuels for taxable years beginning after 2026. Additionally, Senate Finance Committee Chair Ron Wyden recently proposed legislation that would repeal the application of the qualifying income exception to all partnerships for taxable years beginning after 2022. 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 unitholder’s 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.

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.

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, 2023. 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, 2023.

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.

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.

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, 2021, 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.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

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 24, 2022, 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”). As of January 31, 2022, we had nine 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 the 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

As of December 31, 2021, 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 Partnership’s Second Amended and Restated Agreement of Limited Partnership, effective as of April 1, 2020, our general partner or its assignee agreed to waive a portion of the distributions that would otherwise have been payable on the common units issued to SPLC as part of the April 2020 Transaction (as defined in Note 3 — Acquisitions and Other Transactions of this report), 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 and ending with the distribution made with respect to the first quarter of 2021.

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.

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.

Partnership Overview

We own, operate, develop and acquire pipelines and other midstream assets and logistic assets. As of December 31, 2021, 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, Items 1 and 2 — Business and Properties of this report.

2021 developments include:

•Auger Divestiture. On January 25, 2021, we executed an agreement to divest the 12” segment of the Auger pipeline; however, this agreement was subsequently terminated. As a result of the intended divestment, we recorded an impairment charge of approximately $3 million during the first quarter of 2021. This impairment charge had no impact on cash available for distribution (“CAFD”). On April 29, 2021, we executed a new agreement to divest this segment of pipeline, effective June 1, 2021. We received approximately $2 million in cash consideration for this sale.

•May 2021 Transaction. Effective May 1, 2021, we closed the transaction contemplated by that certain Sale and Purchase Agreement dated April 28, 2021 between Triton and SPLC, pursuant to which Triton sold to Equilon Enterprises LLC d/b/a Shell Oil Products US (“SOPUS”), as designee of SPLC, certain assets associated with its clean products truck rack terminal and facility in Anacortes, Washington (the “Anacortes Assets”). In exchange for the Anacortes Assets, SPLC paid Triton $10 million in cash and transferred to the Operating Company, as designee of Triton, SPLC’s 7.5% interest in Zydeco.

•Credit Facilities. On March 16, 2021, we entered into a ten-year fixed rate credit facility with Shell Treasury Center (West) Inc. (“STCW”) with a borrowing capacity of $600 million (the “2021 Ten Year Fixed Facility”). The 2021 Ten Year Fixed Facility bears an interest rate of 2.96% per annum and matures on March 16, 2031. The 2021 Ten Year Fixed Facility was fully drawn on March 23, 2021, and the borrowings were used to repay the borrowings under, and replace, the Five Year Fixed Facility. The Five Year Fixed Facility automatically terminated in connection with the prepayment. Separately, on June 30, 2021, Zydeco terminated the 2019 Zydeco Revolver with STCW. As a result of the May 2021 Transaction in which our ownership interest in Zydeco increased to 100%, the 2019 Zydeco Revolver is no longer needed.

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 certain logistics assets at the Shell Norco Manufacturing Complex (the “Norco Assets”). Our revenue is generated from customers in the same industry, our Parent’s affiliates, integrated oil companies, marketers and independent exploration, production and refining companies primarily within the Gulf Coast region of the United States. We generally do not own any of the crude oil, refinery gas or refined petroleum products we handle, nor do we engage in the trading of these commodities. We therefore have limited direct exposure to risks associated with fluctuating commodity prices, although these risks indirectly influence our activities and results of operations over the long-term.

Notable 2021 and certain anticipated 2022 impacts to net income and CAFD include:

•Hurricane. As a result of Hurricane Ida, we experienced downtime across various pipeline assets and incurred remediation costs related to our assets in the Gulf of Mexico and onshore in southeastern Louisiana. As a result of

these outages and repairs, we incurred an impact to both net income and CAFD of approximately $40 million and $15 million in the third and fourth quarters, respectively, of 2021.

•Planned Turnarounds. Certain offshore connected producers have had planned turnarounds during 2021. The impact to both net income and CAFD from this turnaround activity was approximately $4 million during 2021. Further, we anticipate planned turnaround activity in 2022 to be approximately $20 million.

•Colonial Dividend. Colonial is currently involved in a rate case with the Federal Energy Regulatory Commission (the “FERC”) that, depending upon the outcome, could negatively impact our net income and CAFD. Considering the rate case, as well as other factors impacting Colonial’s business, the board of directors of Colonial elected not to declare a dividend for each of the three months ended June 30, 2021, September 30, 2021 and December 31, 2021.

•Colonial Impairment. During the fourth quarter of 2021, Colonial recorded an impairment, of which our share was approximately $44 million, that negatively impacted our income from equity method investments and net income.

The broader market environment for our customers was extremely challenging in 2020, and impacted worldwide demand for oil and gas and increased downward pressure on oil prices. Although we are still dealing with the continuing effects of the COVID-19 pandemic, we have seen oil prices rise significantly in 2021. However, the responses of oil and gas producers to the changes in both the demand for and price of oil and natural gas are constantly evolving and remain uncertain. The MLP market has also changed significantly, and capital for high growth fueled by dropdown activity continues to be constrained. We are fortunate that Shell 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.

Executive Overview

Net income was $568 million and net income attributable to the Partnership was $556 million in 2021. We generated cash from operations of $612 million. As of December 31, 2021, we had cash and cash equivalents of $361 million, total debt of $2,692 million and unused capacity under our revolving credit facilities of $866 million.

Our 2021 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 over the long-term; and

•optimize existing assets and pursue organic growth opportunities.

Over the past year and a half, our business, as well as the market and economy as a whole, have experienced unprecedented volatility and uncertainty. Even with these challenges, our assets have largely continued to deliver solid results that have allowed us to execute our business strategies. The conflicts committee appointed by the board of directors of our general partner is currently considering a non-binding, preliminary proposal letter from SPLC to acquire all of the Partnership’s issued and outstanding common units not already owned by SPLC or its affiliates (the “Proposal”). Refer to Note 16 – Subsequent Event(s) – Take Private Proposal in the Notes to the Consolidated Financial Statements included in Part II, Item 8 for additional information.

In the event the transactions contemplated by the Proposal are not consummated, we will continue to evaluate and pursue acquisitions of complementary assets from Shell, as well as from third parties, to the extent that these acquisitions are supported by market conditions at the time the opportunity arises and would provide benefit to the Partnership and unitholders. Given the size and scope of Shell’s footprint, and its significant ownership interest in us, we anticipate that acquisitions from Shell may provide opportunities for further growth in the future.

To the extent the transactions contemplated by the Proposal are not consummated, identifying and executing acquisitions will remain 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 Shell and debt. 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 organic growth of our business.

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) net income attributable to the Partnership; (iv) Adjusted EBITDA (defined below); and (v) 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.

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. Responses of oil and gas producers to the changes in demand for, and price of, oil and natural gas are constantly evolving and unpredictable.

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, we, along with our Parent, started an initiative in 2020 to reduce operational costs. Some of these activities, such as re-scoping and/or deferring projects, evaluating third-party service contracts and reducing the use of contractors, have directly benefited, and we expect will continue to 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, have resulted, and we expect will continue to 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.

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 distributions on our Series A perpetual

convertible preferred units (the “Series A Preferred Units”), 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 (as

defined in Note 3 — Acquisitions and Other Transactions in this report), which resulted in part in the transfer of the Norco Assets to be accounted for as a failed sale leaseback under Accounting Standards Codification (“ASC”) Topic 842, Leases (the “lease standard”). As a result, the Partnership recognized financing receivables from SOPUS and Shell Chemical LP (“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, regulatory, 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, as well as U.S. exports.

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

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

As these supply and demand dynamics shift, we anticipate that we will continue to actively pursue projects that link new sources of supply to producers and consumers and to create new services or capacity arrangements that meet customer requirements. 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. For example, the Mars system is expanding to address growing production volumes in the Gulf of Mexico regions served by Mars. It is expected that the project will 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 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, or by sustained downturns or sluggishness in commodity prices or the economy in general. Our business is also impacted by shifts in supply and demand dynamics, the mix of services requested by our pipeline customers, competition and changes in regulatory requirements affecting our operations. Other factors that can have an effect on our performance include asset integrity or customer interruptions, natural disasters (such as Hurricane Ida) or other events that could lead customers or connecting carriers to invoke force majeure or other defenses to avoid contractual performance.

As contracts expire, there are several ways in which the associated 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 and that will maximize earnings. As we have grown and broadened our business over the past several years, we have benefited from shifting our reliance away from the results of any one asset. For example, 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 have diversified, and 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 effects of the COVID-19 pandemic and the resulting governmental regulations and travel restrictions aimed at slowing the spread of the virus. Throughout 2021, many of these restrictions were tempered, with several being lifted altogether. While we saw an increase in both the demand for and price of crude oil in 2021, it is not without continued volatility. Current global geopolitical and economic uncertainty continues to contribute to future volatility in financial and commodity markets. For example, the stalemate among OPEC members and no-operating non-OPEC resource holders (the “OPEC+ alliance”), which ultimately ended in mid-2021, was resolved when the OPEC+ alliance agreed to phase out the COVID-19 production cuts from August 2021 to December 2022. We expect that the OPEC+ alliance decision will cause the crude oil market to remain relatively tight in the near and medium-term, as this increased production will likely align with the higher global demand.

Our direct exposure to commodity price fluctuations is limited to the PLA provisions in our tariffs. Indirectly, global demand for refined products and chemicals could impact our terminal operations and refined products and refinery gas pipelines, as well as our crude pipelines that feed U.S. manufacturing demand. Likewise, changes in the global market for crude oil could affect our crude oil pipeline and terminals and require expansion capital expenditures to reach growing export hubs. Demand for crude oil, refined products and refinery gas may decline in the areas we serve as a result of decreased production by our customers, depressed commodity prices, decreased third-party investment in the industry, increased competition and other adverse economic factors such as the ongoing COVID-19 pandemic, which affect the exploration, production and refining industries. 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, with the exception of the impacts of the COVID-19 pandemic, we have not experienced a material decline in throughput volumes on our crude oil pipeline systems as a result of lower crude oil prices. If crude oil prices drop to lower levels for a sustained period due to the continuing effects of the COVID-19 pandemic or other factors, we will 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 default, 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. 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.

Other Changes in Customers’ Volumes

Onshore crude transportation volumes were down in 2021 versus 2020 primarily as a result of the closure of the Convent refinery at the end of 2020, which caused a significant decrease in non-mainline volumes in 2021, as well as the negative impacts of Hurricane Ida. This decrease was partially offset by fewer impacts from the COVID-19 pandemic in 2021 as compared to 2020.

Offshore crude transportation volumes were down in 2021 versus 2020 primarily due to storm related outages.

Onshore terminaling and storage volumes increased in 2021 versus 2020 due to a continued increase in local refinery demand in the mid-continent.

Major Maintenance Projects

During 2021, our maintenance capital expenditures were routine in nature and did not relate to any major project.

For expected capital expenditures in 2022, refer to Capital Resources and Liquidity — Capital Expenditures and Investments.

Major Expansion Projects

The Mars system is expanding to address growing production volumes in the Gulf of Mexico regions served by Mars. Two major milestones were reached in 2021 with the placement of the pump module on the platform and the execution of definitive agreements with producers. SPLC has elected to fund the installation of the equipment necessary to enable greater throughput volumes on the system, but the revenue associated with increased throughput volumes will benefit Mars. It is expected that the project will be fully operational with incremental growth volumes arriving into the Mars system in 2022.

Over the course of the next few years, we are considering expanding the Auger corridor in order to position the system to capture potential growth volumes in that region of the Gulf of Mexico.

We intend to expand our Lockport facility to accommodate expected additional volumes coming into the Midwest region. This expansion is pending the completion of certain commercial agreements.

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 a specific mix of crude oil grades, 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, we have historically been able to partially mitigate this risk with the longer-term, fixed rate nature of several of our contracts.

Regulation

We have a 16.125% ownership interest in Colonial, which owns and operates a pipeline that runs throughout the southern and eastern United States (the “Colonial pipeline”). On May 7, 2021, the computerized equipment managing the Colonial pipeline was the target of a cyberattack, and while Colonial proactively took certain systems offline to contain the threat, it paid a

ransom in the form of cryptocurrency to regain control of the equipment. For additional information about cybersecurity risks and the cybersecurity programs and protocols we have in place to protect against those risks, see Part I, Items 1 and 2. Business and Properties – Information Technology and Cyber-security and Item 1A. Risk Factors – IT/Cyber-security/Data Privacy/Terrorism Risks in this report.

In May 2021, the Transportation Security Administration (“TSA”) issued a security directive, their initial regulatory response to the Colonial pipeline ransomware attack. The first security directive requires pipeline owners and operators to report confirmed and potential cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency (“CISA”) within 12 hours of discovery, designate a cybersecurity coordinator to be available 24 hours a day, seven days a week, review current practices and identify any gaps and related remediation measures to address cyber-related risks and report the results to the TSA and CISA within 30 days.

In July 2021, the TSA issued a second security directive imposing additional obligations on owners and operators of TSA-designated critical pipelines. In addition to the requirements under the first directive, the second directive requires pipeline owners and operators to develop and implement specific mitigation measures to protect against ransomware attacks and other known threats to information technology and operational technology systems, and a cybersecurity contingency and recovery plan as well as to conduct cybersecurity assessments. We are in the process of reviewing these new directives.

On June 14, 2021, as part of the self-executing provisions of the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) published an advisory bulletin requiring operators to update inspection and maintenance plans to address eliminating hazardous leaks and minimizing releases of natural gas by December 27, 2021. This advisory bulletin is expected to have minimal impact on our operations but will require minor updates to our inspection and maintenance manuals.

In May 2021, Zydeco, Mars and LOCAP filed with the FERC to decrease rates subject to the FERC’s indexing adjustment methodology that were previously at their ceiling levels by 0.5812% starting on July 1, 2021 and are required by the January 20, 2022 rehearing order to recalculate their ceiling levels and file a rate reduction for any rates that exceed the recalculated ceiling to be effective March 1, 2022. Rate complaints are currently pending at the 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. A partial initial decision from the Administrative Law Judge was issued on December 1, 2021 finding that Colonial lacks the ability to exercise market power in the 90-county Gulf Coast geographic origin market, but no longer lacks the ability to exercise market power in the 16-county Tuscaloosa-Moundville geographic origin market. The partial initial decision also found that Colonial’s method of net recoveries of product loss is unjust and unreasonable and that Colonial should adopt a fixed allowance oil deduction for shortages in deliveries and determine the amount of reparations, if any, owed to shippers. This document is a recommendation to the FERC based on the facts surrounding the case, the law and FERC precedent. The FERC may decide to adopt the recommendations made or make different determinations. If the FERC adopts the partial initial decision in whole, in addition to the changes in product loss charges described above, which may adversely affect Colonial, Colonial’s rates in respect of the 16-county Tuscaloosa-Moundville geographic origin market will no longer be market-based and could be reduced. The parties to the case will be filing briefs to argue for or against the recommendations, which will be considered by the FERC in its ruling. The timing of such ruling is unknown. For the issues not covered by the initial decision, the deadline for the Administrative Law Judge to issue a partial initial decision covering those issues is April 29, 2022.

In 2020, the FERC commenced the five-year review of the oil pipeline rate index formula in Docket No. RM20-14-000. The FERC issued an initial 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. On January 20, 2021, the FERC issued an order on rehearing revising the formula set in the December 17, 2020 order to PPI-FG minus 0.21%. The lower indexing adjustment resulted from the FERC adjusting the data set used to assess pipeline cost changes; taking into account the elimination of the income tax allowance and previously accrued accumulated deferred income tax balances for MLP-owned pipelines; and using updated cost data for 2014. The rehearing order requires pipelines to recalculate their rate ceiling levels using the PPI-FG minus 0.21% formula for the period July 1, 2021 to June 30, 2022. For any rate that exceeds the recalculated ceiling level, the pipeline is required to file a rate reduction with the

FERC to be effective March 1, 2022. The FERC’s order on rehearing is subject to potential judicial review. We do not expect these rate recalculations to have a material effect on our financial position, operating results or cash flows.

Results of Operations


	2021		2020		2019
Revenue	$	556	$	481	$	503
Costs and expenses
Operations and maintenance	172		162		124
Cost of product sold	29		24		36
Loss from impairment of fixed assets and revision of ARO	3		—		2
General and administrative	51		56		60
Depreciation, amortization and accretion	50		50		49
Property and other taxes	19		20		17
Total costs and expenses	324		312		288
Operating income	232		169		215
Income from equity method investments	352		417		373
Dividend income from other investments	—		—		14
Other income	39		40		36
Investment, dividend and other income	391		457		423
Interest income	30		23		4
Interest expense	85		93		96
Income before income taxes	568		556		546
Income tax expense	—		—		—
Net income	568		556		546
Less: Net income attributable to noncontrolling interests	12		13		18
Net income attributable to the Partnership	$	556	$	543	$	528
Preferred unitholder’s interest in net income attributable to the Partnership	48		36		—
General partner’s interest in net income attributable to the Partnership	—		55		147
Limited Partners’ interest in net income attributable to the Partnership’s common unitholders	$	508	$	452	$	381
Adjusted EBITDA attributable to the Partnership (1)	$	720	$	767	$	730
Cash available for distribution attributable to the Partnership’s common unitholders (1)	$	623	$	658	$	619

(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.”


Pipeline throughput (thousands of barrels per day) (1)	2021		2020		2019
Zydeco – Mainlines	595		577		657
Zydeco – Other segments	24		142		267
Zydeco total system	619		719		924
Amberjack total system	319		326		362
Mars total system	431		490		546
Bengal total system	321		429		511
Poseidon total system	261		290		265
Auger total system	58		74		77
Delta total system	229		211		258
Na Kika total system	65		40		39
Odyssey total system	114		119		145
Colonial total system	2,254		2,349		2,617
Explorer total system	572		474		650
Mattox total system (2)	98		71		62
LOCAP total system	740		960		1,172
Other systems	457		427		348

Terminals (3) (4)
Lockport terminaling throughput and storage volumes	246		223		228

Revenue per barrel ($ per barrel)
Zydeco total system (5)	$	0.59	$	0.49	$	0.52
Amberjack total system (5)	2.31		2.37		2.37
Mars total system (5)	1.26		1.35		1.31
Bengal total system (5)	0.39		0.41		0.41
Auger total system (5)	1.72		1.28		1.43
Delta total system (5)	0.63		0.59		0.58
Na Kika total system (5)	1.01		0.91		0.80
Odyssey total system (5)	0.99		0.94		0.92
Lockport total system (6)	0.21		0.23		0.22
Mattox total system (7)	1.52		1.52		N/A (8)

(1) Pipeline throughput is defined as the volume of delivered barrels. For additional information regarding our pipeline and terminal systems, refer to Part I, Item I — Business and Properties — Our Assets and Operations.

(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 156 and 162 thousands of barrels per day for 2021 and 2020, respectively.

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

(4) Refinery Gas Pipeline and our refined products terminals are not included above, as they generate revenue under transportation and terminaling service agreements, respectively, that provide for guaranteed minimum throughput.

(5) Based on reported revenues from transportation and allowance oil divided by delivered barrels over the same time period. Actual tariffs charged are based on shipping points along the pipeline system, volume and length of contract.

(6) Based on reported revenues from transportation and storage divided by delivered and stored barrels over the same time period. Actual rates are based on contract volume and length.

(7) Mattox is billed at a fixed rate of $1.52 per barrel for the monthly minimum quantity in accordance with the terms of dedication and transportation agreements entered into in April 2020.

(8) Mattox is billed at a fixed rate (see note above) per dedication and transportation agreements. The rates for 2019 are not applicable, as we only entered into these agreements in April 2020. These agreements do not apply to 2019.

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.


	2021		2020		2019
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	568	$	556	$	546
Add:
Loss from impairment of fixed assets and revision of ARO	3		—		2
Allowance oil reduction to net realizable value	—		8		1
Loss from adjustment of equity method investment basis difference (1)	2		—		—
Depreciation, amortization and accretion	65		61		49
Interest income	(30)		(23)		(4)
Interest expense	85		93		96
Income tax expense	—		—		—
Cash distribution received from equity method investments	432		541		466
Less:
Equity method distributions included in other income	39		37		33
Income from equity method investments (1)	354		417		373
Adjusted EBITDA (2)	732		782		750
Less:
Adjusted EBITDA attributable to noncontrolling interests	12		15		20
Adjusted EBITDA attributable to the Partnership	720		767		730
Less:
Series A Preferred Units distribution	48		36		—
Net interest paid by the Partnership (3)	85		93		92
Income taxes paid attributable to the Partnership	—		—		—
Maintenance capex attributable to the Partnership	11		20		28
Add:
Principal and interest payments received on financing receivables	35		23		—
Net adjustments from volume deficiency payments attributable to the Partnership	—		17		(10)
2021 Transactions (4)	12		—		—
Reimbursements from Parent included in partners’ capital	—		—		19
Cash available for distribution attributable to the Partnership’s common unitholders	$	623	$	658	$	619

(1) As a result of the impairment taken by Colonial in the fourth quarter of 2021, we wrote-off approximately $2 million of the unamortized basis difference related to our investment. These amounts are presented combined in Income from equity method investments in the Consolidated Statements of Income.

(2) Excludes principal and interest payments received on financing receivables.

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

(4) Amount includes the one-time $10 million payment received as part of the May 2021 Transaction, as well as the cash received as part of

the Auger Divestiture. Refer to Note 3 — Acquisitions and Other Transactions in the Notes to the Consolidated Financial Statements included in Part II, Item 8 for additional information.


	2021		2020		2019
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	612	$	650	$	597
Add:
Interest income	(30)		(23)		(4)
Interest expense	85		93		96
Income tax expense	—		—		—
Return of investment	48		91		66
Less:
Change in deferred revenue and other unearned income	10		24		(11)
Non-cash interest expense	1		1		1
Allowance oil reduction to net realizable value	—		8		1
Loss from adjustment of equity method investment basis difference (1)	2		—		—
Change in other assets and liabilities	(30)		(4)		14
Adjusted EBITDA (2)	732		782		750
Less:
Adjusted EBITDA attributable to noncontrolling interests	12		15		20
Adjusted EBITDA attributable to the Partnership	720		767		730
Less:
Series A Preferred Units distribution	48		36		—
Net interest paid by the Partnership (3)	85		93		92
Income taxes paid attributable to the Partnership	—		—		—
Maintenance capex attributable to the Partnership	11		20		28
Add:
Principal and interest payments received on financing receivables	35		23		—
Net adjustments from volume deficiency payments attributable to the Partnership	—		17		(10)
2021 Transactions (4)	12		—		—
Reimbursements from Parent included in partners’ capital	—		—		19
Cash available for distribution attributable to the Partnership’s common unitholders	$	623	$	658	$	619

(1) As a result of the impairment taken by Colonial in the fourth quarter of 2021, we wrote-off approximately $2 million of the unamortized basis difference related to our investment. This amount is presented in Undistributed equity earnings in the Consolidated Statements of Cash Flows.

(2) Excludes principal and interest payments received on financing receivables.

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

(4) Amount includes the one-time $10 million payment received as part of the May 2021 Transaction, as well as the cash received as part of

the Auger Divestiture. Refer to Note 3 — Acquisitions and Other Transactions in the Notes to the Consolidated Financial Statements included in Part II, Item 8 for additional information.

The following discussion includes a comparison of our Results of Operations and Capital Resources and Liquidity — Cash Flows from Our Operations for 2021 and 2020. A discussion of changes in our Results of Operations and Capital Resources and Liquidity — Cash Flows from Our Operations from 2019 to 2020 has been omitted from the Form 10-K, but may be found in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 2020, filed with the SEC on February 23, 2021.

2021 Compared to 2020

Revenues

Total revenue increased by $75 million in 2021 as compared to 2020, comprised of increases of $38 million in transportation services revenue, $21 million in terminaling services revenue and $18 million attributable to product revenue, partially offset by decreases of $1 million in lease revenue and $1 million in storage service revenue.

Transportation services revenue increased primarily due to higher throughput on Pecten as a result of new volumes coming online from tiebacks in 2021, as well as a temporary shift in the shipping routes in early 2021 on certain Pecten assets. Additionally, there was an increase in transportation services revenue on Zydeco in 2021 versus 2020 related to the committed contracts entered into in mid-2021, as well as from spot shipment activity. Further, transportation services revenue in 2020 had greater impacts from the COVID-19 pandemic than we experienced in 2021. This increase in revenue in 2021 was partially offset by downtime associated with hurricane activity in 2021.

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

Product revenue increased by $18 million due to an increase in the volume of allowance oil sold, as well as an increase in the market price of those sales, for certain of our onshore and offshore crude pipelines in 2021 as compared to 2020.

Lease revenue decreased as a result of the sale of the Anacortes Assets in 2021.

Storage service revenue decreased in 2021 as compared to 2020 as crude prices increased, which resulted in a move away from a contango market and therefore lower storage volumes.

Costs and Expenses

Total costs and expenses increased by $12 million in 2021 primarily due to the increases of $10 million in operations and maintenance expenses, $5 million in cost of products sold and $3 million of loss from the impairment of fixed assets incurred in 2021. These increases were partially offset by decreases of $5 million in general and administrative expenses and $1 million in property taxes.

Operations and maintenance expenses increased in 2021 as compared to 2020 mainly as a result of higher maintenance costs related to the Norco Assets acquired in April 2020.

Cost of product sold increased by approximately $13 million primarily due to higher sales of allowance oil in 2021 as compared to 2020, partially offset by a net realizable value adjustment on allowance oil inventory of approximately $8 million in 2020.

General and administrative expense decreased primarily due to higher professional fees related to the April 2020 Transaction and higher severance costs in 2020.

Property tax expense decreased as a result of a change in the appraisal methodology for certain assets amounting to approximately $3 million. This decrease was partially offset by an increase of approximately $2 million of property taxes associated with the acquisition of the Norco Assets in April 2020.

Investment, Dividend and Other Income

Investment, dividend and other income decreased by $66 million in 2021 as compared to 2020. Income from equity method investments decreased by $65 million primarily due to lower earnings from several investments, most significantly from Colonial due to the impairment taken in the fourth quarter of 2021 and from Mars as a result of outages related to Hurricane Ida. These decreases were partially offset by the equity earnings associated with the acquisition of an interest in Mattox in April 2020 and higher earnings from Explorer. Other income decreased by $1 million related to lower distributions from Poseidon in 2021.

Interest Income and Expense

Interest income was $7 million higher mainly due to interest income related to the financing receivables recorded in connection with the Norco Assets. Interest expense decreased by $8 million due to lower interest rates in 2021 versus 2020 resulting fromthe ongoing effects of the COVID-19 pandemic on market interest rates.

Capital Resources and Liquidity

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our credit facilities and our ability to access the capital markets. We believe this access to credit along with cash generated from operations will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements, and to make quarterly cash distributions. However, we cannot accurately predict the effects of the continuing COVID-19 pandemic on our capital resources and liquidity due to the current significant level of uncertainty. Our liquidity as of December 31, 2021 was $1,227 million, consisting of $361 million cash and cash equivalents and $866 million of available capacity under our credit facilities.

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”), which included the elimination of all the incentive distribution rights, the conversion of the economic general partner interest into a non-economic general partner interest and the establishment of the rights and preferences of the Series A Preferred Units in the Partnership’s Second Amended and Restated Agreement of Limited Partnership, effective as of April 1, 2020 (the “Second Amended and Restated Partnership Agreement”). Pursuant to the Partnership Interests Restructuring Agreement, the general partner (or its assignee) agreed to waive a portion of the distributions that would otherwise have been 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 and ending with the distribution made with respect to the first quarter of 2021. Refer to Note 3 — Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for more details.

On March 16, 2021, we entered into a ten-year fixed rate credit facility with STCW with a borrowing capacity of $600 million (the “2021 Ten Year Fixed Facility”). The 2021 Ten Year Fixed Facility bears an interest rate of 2.96% per annum and matures on March 16, 2031. The 2021 Ten Year Fixed Facility was fully drawn on March 23, 2021, and the borrowings were used to repay the borrowings under, and replace, the Five Year Fixed Facility. Refer to Note 8– Related Party Debt in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for more details.

On August 1, 2019, Zydeco entered into a senior unsecured revolving loan facility agreement with Shell Treasury Center (West) Inc. (“STCW”), effective August 6, 2019 (the “2019 Zydeco Revolver”). The 2019 Zydeco Revolver had a borrowing capacity of $30 million maturing on August 6, 2024. On June 30, 2021, Zydeco entered into a termination of revolving loan facility agreement with STCW to terminate the 2019 Zydeco Revolver. Zydeco had not borrowed any funds under this facility, and therefore, no further obligations existed at the time of termination.

On June 4, 2019, we entered into the Ten Year Fixed Facility, which bears an interest rate of 4.18% per annum and matures on June 4, 2029. No issuance fee was incurred in connection with the Ten Year Fixed Facility. The Ten Year Fixed Facility contains customary representations, warranties, covenants and events of default, the occurrence of which would permit the lender to accelerate the maturity date of amounts borrowed under the Ten Year Fixed Facility. The Ten Year Fixed Facility was fully drawn on June 6, 2019 to partially fund our acquisition of SPLC’s remaining 25.97% ownership interest in Explorer and 10.125% ownership interest in Colonial for consideration valued at $800 million on June 6, 2019 (the “June 2019 Acquisition”).

Credit Facility Agreements

As of December 31, 2021, we have entered into the following credit facilities:


	Total Capacity		Current Interest Rate		Maturity Date
2021 Ten Year Fixed Facility	$	600	2.96	%	March 16, 2031
Ten Year Fixed Facility	600		4.18	%	June 4, 2029
Seven Year Fixed Facility	600		4.06	%	July 31, 2025
Five Year Revolver due July 2023 (1)	760		1.11	%	July 31, 2023
Five Year Revolver due December 2022 (1)	1,000		1.12	%	December 1, 2022

(1) These revolving credit facilities will expire in 2022 and 2023, respectively, and as such, we are currently assessing our options for renewal.

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

Our weighted average interest rate for 2021 and 2020 was 3.0% and 3.3%, respectively. The weighted average interest rate includes drawn and undrawn interest fees, but does not consider the amortization of debt issuance costs or capitalized interest. A 1/8 percentage point (12.5 basis points) increase in the interest rate on the total variable rate debt of $894 million as of December 31, 2021 would increase our consolidated annual interest expense by approximately $1 million.

We will need to rely on the willingness and ability of our related party lender to secure additional debt, our ability to use cash from operations and/or obtain new debt from other sources to repay/refinance such loans when they come due and/or to secure additional debt as needed.

As of December 31, 2021 and 2020, we were in compliance with the covenants contained in our credit facilities.

For definitions and additional information on our credit facilities, refer to Note 8 — Related Party Debt in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.

Equity Issuances

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. Refer to Note 11 — (Deficit) Equity in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for additional details.

On June 6, 2019, in connection with the June 2019 Acquisition, we issued 9,477,756 common units to Shell Midstream LP Holdings LLC, an indirect subsidiary of Shell. In connection with the issuance of the common units, we issued 193,424 general partner units to our general partner in order to maintain its 2% general partner interest in us. The non-cash equity consideration from this issuance was valued at $200 million pursuant to the May 2019 Contribution Agreement and was used to partially fund the June 2019 Acquisition.

Cash Flows from Our Operations

Operating Activities. We generated $612 million in cash flow from operating activities in 2021 compared to $650 million in 2020. The decrease in cash flows was primarily driven by lower equity investment income and distributions, primarily related to Colonial and Mars, as well as the timing of receipt of receivables and payment of accruals in 2021. This decrease was partially offset by an increase in net income related to the acquisition of the Norco Assets and an interest in Mattox in April 2020.

Investing Activities. Our cash flow provided by investing activities was $45 million in 2021 compared to $64 million in 2020.

The decrease in cash flow provided by investing activities was primarily due to a lower return of investment and higher contribution to investment in 2021 compared to 2020. These decreases were partially offset by the transactions completed in 2021, as well as lower capital expenditures in 2021 compared to 2020.

Financing Activities. Our cash flow used in financing activities was $616 million in 2021 compared to $684 million in 2020. The decrease in cash flow used in financing activities was primarily due to decreased distributions paid to unitholders in 2021

compared to 2020, lower distributions to noncontrolling interests in 2021 as a result of acquiring the remaining ownership interest in Zydeco as part of the May 2021 Transaction, higher receipt of principal payments on financing receivables related to the Norco Assets in 2021 and the payment of equity issuance costs in 2020. These decreases were partially offset by the payment of a one-time prepayment fee related to a credit facility in 2021.

Capital Expenditures and Investments

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

We incurred capital expenditures of $12 million, $22 million and $35 million for 2021, 2020 and 2019, respectively. The decrease in capital expenditures from 2020 to 2021 is primarily due to the completion of Zydeco pipeline exposure replacement project at Bessie Heights in 2020, partially offset by a contribution to investment in 2021.

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


	2021		2020		2019
Expansion capital expenditures	$	—	$	1	$	10
Maintenance capital expenditures	11		26		28
Total capital expenditures paid	11		27		38
Increase (decrease) in accrued capital expenditures	1		(5)		(3)
Total capital expenditures incurred	$	12	$	22	$	35
Contributions to investment	$	4	$	—	$	25

We expect total capital expenditures and investments to be approximately $60 million for 2022, a summary of which is shown in table below:


	Actual Capital Expenditures		Expected Capital Expenditures
	2021		2022
Expansion capital expenditures


Pecten	$	—	$	12

Total expansion capital expenditures incurred	—		12
Maintenance capital expenditures
Zydeco	6		6
Pecten	2		2
Triton	2		4

Odyssey	2		33
Total maintenance capital expenditures incurred	12		45
Contributions to investment	4		3
Total capital expenditures and investments	$	16	$	60

Expansion and Maintenance Expenditures

There were no expansion capital expenditures for 2021. For 2022, we expect Pecten’s expansion capital expenditure to be approximately $12 million, of which approximately $8 million is for the intended expansion of the Lockport terminal and $4 million is for the potential expansion of the Auger corridor.

Zydeco’s maintenance capital expenditures for 2021 were $6 million, primarily for an upgrade of the motor control center at Houma, as well as various other maintenance projects. We expect Zydeco’s maintenance capital expenditures to be approximately $6 million for 2022, of which approximately $4 million is related to Houma tank maintenance projects and $1 million is related to the upgrade of the motor control center at Houma. The remaining maintenance capital expenditure is related to other routine maintenance.

Pecten’s maintenance capital expenditures for 2021 were $2 million for various maintenance projects. We expect Pecten’s maintenance capital expenditures to be approximately $2 million in 2022, of which $1 million is related to helideck maintenance on the Auger system and $1 million is related to Lockport tank maintenance.

Triton’s maintenance capital expenditures for 2021 were $2 million related to various maintenance projects. We expect Triton’s maintenance capital expenditures to be approximately $4 million in 2022, of which approximately $1 million is related to the Seattle dock line repair and approximately $1 million is related to a control center integration project for Portland. The remaining maintenance capital expenditure is related to various other routine maintenance projects.

Odyssey’s maintenance capital expenditures for 2021 were $2 million related to a project at MP289C to re-route the pipeline around the platform. We expect Odyssey’s maintenance capital expenditures to be approximately $33 million in 2022 related to this pipeline re-route project.

There were no maintenance capital expenditures for Sand Dollar for 2021, and we do not expect any maintenance capital expenditures for Sand Dollar in 2022.

We anticipate that both maintenance and expansion capital expenditures for 2022 will be funded primarily with cash from operations.

Capital Contributions

In accordance with the Member Interest Purchase Agreement dated October 16, 2017 pursuant to which we acquired a 50% interest in Permian Basin, we will make capital contributions for our pro rata interest in Permian Basin to fund capital and other expenditures, as approved by supermajority (75%) vote of the members. We made capital contributions of approximately $4 million in 2021, and expect to make capital contributions of approximately $3 million in 2022.

Critical Accounting Policies and Estimates

Critical accounting policies are those that are important to our financial condition and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under different operating conditions or under alternative assumptions.

We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with GAAP. Our more critical accounting policies include those related to long-lived assets, equity method investments and revenue recognition. Inherent in such policies are certain key assumptions and estimates. We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. Our significant accounting policies are summarized in Note 2 — Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report. We believe the following to be our most critical accounting policies applied in the preparation of our financial statements.

Long-Lived Assets

We consider the recoverability of carrying values of long-lived assets to be a key estimate. Such estimate could be significantly modified. The carrying values of long-lived assets could be impaired by significant changes or projected changes in supply and demand fundamentals of oil, natural gas, refinery gas or refined products (which could have a negative impact on operating rates or margins), new technological developments, new competitors, adverse changes associated with the U.S. and global economies and with governmental actions. We evaluate long-lived assets for potential impairment indicators whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, including when negative conditions such as significant current or projected operating losses exist. Our judgments regarding the existence of impairment indicators are based on legal factors, market conditions and the operational performance of our businesses. When necessary, the determination of the amount of impairment is based on quoted market prices, if available, or on our judgment as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Actual impairment losses incurred could vary significantly from amounts estimated. Long-lived assets assessed for impairment are grouped at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Additionally,

future events could cause us to conclude that impairment indicators exist and that associated long-lived assets of our businesses are impaired. Any resulting impairment loss could have a material adverse impact on our financial condition and results of operations.

Equity Method Investments

We account for investments where we have the ability to exercise significant influence, but not control, under the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value.

As of and for the year ended December 31, 2021, we did not identify any other-than-temporary impairment related to our equity method investments. However, if the facts and circumstances change in the near-term and indicate a loss in value that is other-than-temporary, we will re-evaluate whether the carrying amount of our equity method investments may not be recoverable.

Revenue Recognition

On January 1, 2018, we adopted Topic 606, Revenue from Contracts with Customers, and all related Accounting Standard Updates to this Topic (collectively, “the revenue standard”). See Note 12 — Revenue Recognition in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for additional information.

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

As a result of FERC regulations, revenues we collect may be subject to refund. We establish reserves for these potential refunds based on actual expected refund amounts on the specific facts and circumstances. We had no reserves for potential refunds as of December 31, 2021 and 2020.

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

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

April 2020 Transaction Fair Value

In connection with the April 2020 Transaction, we utilized the services of independent valuation specialists to determine the fair value of the total consideration, as well as the fair values of the Mattox Transaction, the Norco Transaction, and the GP/IDR Restructuring as of April 1, 2020. Because the components of the April 2020 Transaction were entered in contemplation of each other and were transactions among entities under common control, the fair values of the April 2020 Transaction were used solely for the purpose of allocating a portion of the total consideration on a relative fair value basis to the Norco Transaction. The Partnership issued 50,782,904 Series A Preferred Units and 160,000,000 newly issued common units to SPLC as consideration for the April 2020 Transaction. See Note 3 — Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for additional details and definitions of the defined terms used in this discussion.

As further described in Note 3 — Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report, we acquired the Mattox equity interests from SGOM as a part of the Mattox Transaction. The acquisition was accounted for as a transaction among entities under common control on a prospective basis as an asset acquisition. As a part of the Norco Transaction, SOPUS and Shell Chemical transferred certain logistics assets at the Shell Norco Manufacturing Complex to Triton, as designee of the Partnership. The transfer of the Norco Assets combined with the terminaling service agreements was accounted for as a failed sale leaseback under the lease standard, as control of the assets did not transfer to the Partnership. As a result, the transaction was treated as financing arrangement.

We also recorded contract assets as of April 1, 2020 based on the difference between the consideration allocated to the Norco Transaction and the recognized financing receivables. The contract assets represent the excess of the fair value embedded within the terminaling services agreements transferred by the Partnership to SOPUS and Shell Chemical as part of entering into the terminaling services agreements. The amount of contract assets recognized was dependent on the allocated fair value of the consideration to the Norco Transaction, which was determined using the fair values of the consideration transferred and the fair values of the three components of the April 2020 Transaction. The common units were valued using a market approach based on the market opening price of the Partnership’s common units as of April 1, 2020 less a discount for the distribution waiver and lack of marketability. The Series A Preferred Units were valued using an income approach based on a trinomial lattice model. Further, the fair values of the three components of the April 2020 Transaction were determined using an income approach of discounted cash flows at an average discount rate for each of the Mattox Transaction, the Norco Transaction and the GP/IDR Restructuring components of 14%, 11% and 20%, respectively.

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

Fair value of consideration

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

Valuation Technique

Key assumptions

Common Units

Market Approach

Discount for lack of marketability; waiver discount

Series A Preferred Units

Income Approach

Volatility rate; expected term; yield and conversion price

Fair value of business enterprise value

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

Valuation Technique

Key assumptions

Mattox Transaction

Income Approach

Discount rates; revenue growth rates; terminal growth rates; cash flow projections

Norco Transaction

Income Approach

Discount rates; revenue growth rates; terminal growth rates; cash flow projections

GP/IDR Restructuring

Income Approach

Discount rates; revenue growth rates; terminal growth rates; projected CAFD

Relative Stand -Alone Selling Price

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

Recent Accounting Pronouncements

Please read Note 2 — Summary of Significant Accounting Policies — Recent Accounting Pronouncements included in Part II, Item 8 of this report.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices.

Commodity Price Risk

With the exception of buy/sell arrangements on some of our offshore pipelines and our allowance oil retained, we do not take ownership of the crude oil or refined products that we transport and store for our customers, and we do not engage in the trading of any commodities. We therefore have limited direct exposure to risks associated with fluctuating commodity prices.

Our long-term transportation agreements and tariffs for crude oil shipments include PLA. The PLA provides additional revenue for us at a stated factor per barrel. If product losses on our pipelines are within the allowed levels, we retain the benefit, otherwise we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess product that we transport when product losses are within allowed level, and we sell that product several times per year at prevailing market prices. This allowance oil revenue, which accounted for approximately 6%, 4% and 6% of our total revenue in 2021, 2020 and 2019, respectively, is subject to more volatility than transportation revenue, as it is directly dependent on our measurement capability and commodity prices. As a result, the income we realize under our loss allowance provisions will increase or decrease as a result of changes in the mix of product transported, measurement accuracy and underlying commodity prices. We do not intend to enter into any hedging agreements to mitigate our exposure to decreases in commodity prices through our loss allowances.

Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under our revolving credit facilities. To the extent that interest rates increase, interest expense for these revolving credit facilities will also increase. As of both December 31, 2021 and December 31, 2020, the Partnership had $894 million in outstanding variable rate borrowings under these revolving credit facilities. A hypothetical change of 12.5 basis points in the interest rate of our variable rate debt would impact the Partnership’s annual interest expense by approximately $1 million for both 2021 and 2020. We do not currently intend to enter into any interest rate hedging agreements, but will continue to monitor interest rate exposure.

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

Other Market Risks

We may also have risk associated with changes in policy or other actions taken by the FERC. Please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors Affecting our Business and Outlook — Regulation” for additional information.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

SHELL MIDSTREAM PARTNERS, L.P.

INDEX TO FINANCIAL STATEMENTS


			Page
Reports of Independent Registered Public Accounting Firms (PCAOB ID: 42)			73
CONSOLIDATED BALANCE SHEETS			76
CONSOLIDATED STATEMENTS OF INCOME			77
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME			78
CONSOLIDATED STATEMENTS OF CASH FLOWS			79
CONSOLIDATED STATEMENTS OF CHANGES IN (DEFICIT) EQUITY			80
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS			81

Report of Independent Registered Public Accounting Firm

To the Unitholders of Shell Midstream Partners, L.P. and the Board of Directors of Shell Midstream Partners GP LLC

Opinion on Internal Control Over Financial Reporting

We have audited Shell Midstream Partners, L.P.’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Shell Midstream Partners, L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Shell Midstream Partners, L.P. as of December 31, 2021 and 2020, and the related consolidated statements of income, comprehensive income, cash flows and changes in (deficit) equity for each of the three years in the period ended December 31, 2021, and the related notes and our report dated February 24, 2022 expressed an unqualified opinion thereon.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 24, 2022

Report of Independent Registered Public Accounting Firm

To the Unitholders of Shell Midstream Partners, L.P. and the Board of Directors of Shell Midstream Partners GP LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Shell Midstream Partners, L.P. (the Partnership) as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, changes in (deficit) equity and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 24, 2022 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures to which it relates.


						Presentation and Disclosure of Related Party Transactions

Description of the Matter						As described in Note 4 to the consolidated financial statements, the Partnership has material amounts of related party transactions as it regularly transacts with Shell plc and its affiliates (“Shell”) in the normal course of business. Auditing the presentation and disclosure of these related party transactions was challenging due to the large volume of transactions that Shell has with the Partnership’s business, specifically as it relates to revenue earned from providing transportation, terminaling, and storage services, direct and allocated expenses charged from Shell for services provided under operating and administrative management agreements, and fees charged for general and administrative services provided by Shell.
How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership’s process of identifying and disclosing related party transactions. To test the appropriateness of related party disclosures, we performed procedures to test material related party account activity and account balances including, among others, testing the related and third party classification of transactions in transportation, terminaling and storage services revenue, accounts receivable, operations and maintenance expenses, general and administrative expenses, accounts payable and accrued liabilities by inspecting source documentation and evaluating the aggregation and presentation of related party financial statement line items.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2016.

Houston, Texas

February 24, 2022

SHELL MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS


	December 31,
	2021		2020

	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	361	$	320
Accounts receivable – third parties, net	16		20
Accounts receivable – related parties	40		21
Allowance oil	22		9
Prepaid expenses	26		24
Total current assets	465		394
Equity method investments	974		1,013
Property, plant and equipment, net	654		699
Operating lease right-of-use assets	3		4
Other investments	2		2
Contract assets – related parties	218		233
Other assets – related parties	2		2
Total assets	$	2,318	$	2,347
LIABILITIES
Current liabilities
Accounts payable – third parties	$	4	$	5
Accounts payable – related parties	17		16
Deferred revenue – third parties	2		4
Deferred revenue – related parties	31		19
Accrued liabilities – third parties	11		10
Accrued liabilities – related parties	24		28
Debt payable – related party	400		—
Total current liabilities	489		82
Noncurrent liabilities
Debt payable – related party	2,292		2,692
Operating lease liabilities	4		4
Finance lease liabilities	23		24
Deferred revenue and other unearned income	3		3
Total noncurrent liabilities	2,322		2,723
Total liabilities	2,811		2,805
Commitments and Contingencies (Note 15)
(DEFICIT) EQUITY
Preferred unitholders (50,782,904 units issued and outstanding as of both December 31, 2021 and December 31, 2020)	(1,059)		(1,059)
Common unitholders – public (123,832,233 units issued and outstanding as of both December 31, 2021 and December 31, 2020)	3,354		3,382
Common unitholder – SPLC (269,457,304 units issued and outstanding as of both December 31, 2021 and December 31, 2020)	(2,488)		(2,497)
Financing receivables – related parties	(293)		(298)
Accumulated other comprehensive loss	(8)		(9)
Total partners’ deficit	(494)		(481)
Noncontrolling interests	1		23
Total deficit	(493)		(458)
Total liabilities and deficit	$	2,318	$	2,347

The accompanying notes are an integral part of the consolidated financial statements.

SHELL MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME


	2021		2020		2019

	(in millions of dollars, except per unit data)
Revenue
Transportation, terminaling and storage services – third parties	$	151	$	123	$	143
Transportation, terminaling and storage services – related parties	312		282		264
Product revenue – third parties	1		—		5
Product revenue – related parties	36		19		35
Lease revenue – related parties	56		57		56
Total revenue	556		481		503
Costs and expenses
Operations and maintenance – third parties	48		48		65
Operations and maintenance – related parties	124		114		59
Cost of product sold	29		24		36
Loss from impairment of fixed assets and revision of ARO	3		—		2
General and administrative – third parties	6		7		11
General and administrative – related parties	45		49		49
Depreciation, amortization and accretion	50		50		49
Property and other taxes	19		20		17
Total costs and expenses	324		312		288
Operating income	232		169		215
Income from equity method investments	352		417		373
Dividend income from other investments	—		—		14
Other income	39		40		36
Investment, dividend and other income	391		457		423
Interest income	30		23		4
Interest expense	85		93		96
Income before income taxes	568		556		546
Income tax expense	—		—		—
Net income	568		556		546
Less: Net income attributable to noncontrolling interests	12		13		18
Net income attributable to the Partnership	$	556	$	543	$	528
Preferred unitholder’s interest in net income attributable to the Partnership	48		36		—
General partner’s interest in net income attributable to the Partnership	—		55		147
Limited Partners’ interest in net income attributable to the Partnership’s common unitholders	$	508	$	452	$	381

Net income per Limited Partner Unit - Basic and Diluted:
Common - basic	$	1.29	$	1.28	$	1.66
Common - diluted	$	1.25	$	1.25	$	1.66
Distributions per Limited Partner Unit	$	1.36	$	1.84	$	1.75

Weighted average Limited Partner Units outstanding - Basic and Diluted:
Common units - public - basic	123.8		123.8		123.8
Common units - SPLC - basic	269.5		229.7		105.4
Common units - public - diluted	123.8		123.8		123.8
Common units - SPLC - diluted	320.3		267.9		105.4

The accompanying notes are an integral part of the consolidated financial statements.

SHELL MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


		2021		2020		2019

	(in millions of dollars)
Net income		$	568	$	556	$	546
Other comprehensive gain (loss), net of tax:
Remeasurements of pension and other postretirement benefits related to equity method investments, net of tax		1		(1)		(2)
Comprehensive income		$	569	$	555	$	544
Less comprehensive income attributable to:
Noncontrolling interests		12		13		18
Comprehensive income attributable to the Partnership		$	557	$	542	$	526

The accompanying notes are an integral part of the consolidated financial statements.

SHELL MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	2021		2020		2019

	(in millions of dollars)
Cash flows from operating activities
Net income	$	568	$	556	$	546
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	50		50		49
Amortization of contract assets - related parties	15		11		—
Loss from impairment of fixed assets and revision of ARO	3		—		2
Non-cash interest expense	1		1		1
Allowance oil reduction to net realizable value	—		8		1
Undistributed equity earnings	(5)		(4)		(6)
Changes in operating assets and liabilities
Accounts receivable	(15)		—		7
Allowance oil	(13)		(6)		—
Prepaid expenses and other assets	(1)		(7)		—
Accounts payable	1		7		2
Deferred revenue and other unearned income	10		24		(11)
Accrued liabilities	(2)		10		6
Net cash provided by operating activities	612		650		597
Cash flows from investing activities
Capital expenditures	(11)		(27)		(38)
Acquisitions from Parent	—		—		(90)
May 2021 Transaction	10		—		—
Contributions to investment	(4)		—		(25)
Return of investment	48		91		66
Auger Divestiture	2		—		—
Net cash provided by (used in) investing activities	45		64		(87)
Cash flows from financing activities
Payment of equity issuance costs	—		(2)		—

Borrowings under credit facilities	—		—		600


Capital distributions to general partner	—		—		(510)
Distributions to noncontrolling interests	(12)		(16)		(17)
Distributions to unitholders and general partner	(606)		(670)		(519)
Other contributions from Parent	—		2		19
Prepayment fee on credit facility	(2)		—		—
Receipt of principal payments on financing receivables	5		3		—
Repayment of principal on finance leases	(1)		(1)		(1)
Net cash used in financing activities	(616)		(684)		(428)
Net increase in cash and cash equivalents	41		30		82
Cash and cash equivalents at beginning of the period	320		290		208
Cash and cash equivalents at end of the period	$	361	$	320	$	290


Supplemental Cash Flow Information
Non-cash investing and financing transactions:

Change in accrued capital expenditures	$	1	$	(5)	$	(3)

The accompanying notes are an integral part of the consolidated financial statements.

SHELL MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN (DEFICIT) EQUITY


	Partnership
(in millions of dollars)	Preferred Unitholder SPLC		Common Unitholders Public		Common Unitholder SPLC		General Partner SPLC		Financing Receivables		Accumulated Other Comprehensive Loss		Noncontrolling Interests		Total
Balance as of December 31, 2018	$	—	$	3,459	$	(198)	$	(3,543)	$	—	$	—	$	25	$	(257)
Impact of change in accounting policy (Note 5)	—		(4)		(5)		—		—		—		—		(9)
Net income	—		204		177		147		—		—		18		546
Other contributions from Parent	—		—		—		25		—		(6)		—		19
Other comprehensive loss	—		—		—		—		—		(2)		—		(2)
Distributions to unitholders and general partner	—		(209)		(177)		(133)		—		—		—		(519)
Distributions to noncontrolling interests	—		—		—		—		—		—		(17)		(17)
June 2019 Acquisition	—		—		—		(510)		—		—		—		(510)
Balance as of December 31, 2019	$	—	$	3,450	$	(203)	$	(4,014)	$	—	$	(8)	$	26	$	(749)
Net income	36		160		292		55		—		—		13		556
Other contributions from Parent	—		—		2		—		—		—		—		2
Other comprehensive loss	—		—		—		—		—		(1)		—		(1)
Distributions to unitholders and general partner	(24)		(228)		(308)		(110)		—		—		—		(670)
Distributions to noncontrolling interests	—		—		—		—		—		—		(16)		(16)
Principal repayments on financing receivables	—		—		—		—		3		—		—		3
April 2020 Transaction	(1,071)		—		(2,280)		4,069		(301)		—		—		417
Balance as of December 31, 2020	$	(1,059)	$	3,382	$	(2,497)	$	—	$	(298)	$	(9)	$	23	$	(458)
Net income	48		160		348		—		—		—		12		568

Other comprehensive income	—		—		—		—		—		1		—		1
Distributions to unitholders	(48)		(188)		(370)		—		—		—		—		(606)
Distributions to noncontrolling interests	—		—		—		—		—		—		(12)		(12)
Principal repayments on financing receivables	—		—		—		—		5		—		—		5
May 2021 Transaction	—		—		31		—		—		—		(22)		9
Balance as of December 31, 2021	$	(1,059)	$	3,354	$	(2,488)	$	—	$	(293)	$	(8)	$	1	$	(493)

The accompanying notes are an integral part of the consolidated financial statements.

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Except as noted within the context of each note disclosure, the dollar amounts presented in the tabular data within these note disclosures are stated in millions of dollars.

1. Description of the Business and Basis of Presentation

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

Description of the Business

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.

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table reflects our ownership interests as of December 31, 2021:


	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)	100.0	%
Mattox Pipeline Company LLC (“Mattox”)	79.0	%
Amberjack Pipeline Company LLC (“Amberjack”) – Series A/Series B	75.0% / 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	%

Basis of Presentation

Our consolidated financial statements include all subsidiaries required to be consolidated under generally accepted accounting principles in the United States (“GAAP”). Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars. The accompanying consolidated financial statements and related notes have been prepared under the rules and regulations of the United States Securities and Exchange Commission (“SEC”). These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification, the single source of GAAP.

Our consolidated subsidiaries include Pecten, Sand Dollar, Triton, Zydeco, Odyssey and the Operating Company. Asset acquisitions of additional interests in previously consolidated subsidiaries and interests in equity method and other investments are included in the financial statements prospectively from the effective date of each acquisition. In cases where these types of acquisitions are considered acquisitions of businesses under common control, the financial statements are retrospectively adjusted.

Expense Allocations. Our consolidated statements of income also include expense allocations for certain functions performed by SPLC and Shell on our behalf. Such costs are included in either general and administrative expenses or operations and maintenance expenses in the accompanying consolidated statements of income, depending on the nature of the employee’s role in our operations. The expense allocations have been determined on a basis that we, SPLC and Shell consider to be a reasonable reflection of the utilization of the services provided or the benefit received during the periods presented.

See Note 4 — Related Party Transactions for details of operating agreements impacting expense allocations, as well as details of related party transactions.

Cash. For all consolidated subsidiaries, we establish our own cash accounts for the funding of our operating and investing activities. Funds are not commingled with the cash of other entities.

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include all subsidiaries where we have control. The assets and liabilities in the accompanying consolidated financial statements have been reflected on a historical basis. All significant intercompany accounts and transactions are eliminated upon consolidation. See Note 1 — Description of the Business and Basis of Presentation for additional details.

Regulation

Certain businesses are subject to regulation by various authorities including, but not limited to, the FERC. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported of assets, liabilities, revenues and expenses in the accompanying consolidated financial statements and notes. Actual results could differ from those estimates.

Common Control Transactions

Assets and businesses acquired from our Parent and its subsidiaries are accounted for as common control transactions whereby the net assets acquired are combined with ours at our Parent’s historical carrying value. If any recognized consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital distribution to our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any recognized consideration transferred including, if applicable, the fair value of any limited partner units issued, then our Parent would record an impairment, and our net assets acquired would be recorded at fair value. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our consolidated statement of cash flows. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our consolidated statement of cash flows. Assets and businesses sold to our Parent are also common control transactions accounted for using historical carrying value with any resulting gain treated as a contribution from Parent.

Revenue Recognition

Our revenues are primarily generated from the transportation, terminaling and storage of crude oil, refined gas and refined petroleum products through our pipelines, terminals, storage tanks, docks, truck and rail racks. We recognize revenue when we transfer promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. We recognize revenue through the application of a five-step model, which includes: identification of the contract; identification of the performance obligations; determination of the transaction price; allocation of the transaction price to the performance obligations; and recognition of revenue as the entity satisfies the performance obligations. See Note 12 — Revenue Recognition for information and disclosures related to revenue from contracts with customers.

Leases, Sale Leaseback

When entering into sale-leaseback transactions as a buyer-lessor, the requirements in Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, and all related accounting standards updates to such Topic (collectively, “the revenue standard”) are applied in determining whether the transfer of an asset shall be accounted for as a sale of the asset by assessing whether it satisfies a performance obligation under the contract by transferring control of an asset. If the seller-lessee transfers control of an asset to us, we account for the transfer of the asset as a purchase and recognize the transferred asset. The subsequent leaseback of the asset is accounted for in accordance with ASC Topic 842, Leases (the “lease standard”), in the same manner as any other lease. If the seller-lessee does not transfer the control of an asset to us, the failed sale-leaseback transaction is accounted for as a financing arrangement. Transactions in which control of an asset is not transferred are accounted for as financing receivables in accordance with ASC Topic 310, Receivables. Since the seller-lessee did not transfer the control of assets to us in the April 2020 Transaction (as defined in Note 3 — Acquisitions and Other Transactions below), we did not recognize the transferred assets, and instead they were accounted for as financing receivables. Receivables issued in exchange for the Partnership’s capital stock are presented as a component of the partners’ (deficit) equity. Since the Partnership issued common units and preferred units as consideration in exchange for the financing receivables in the April 2020 Transaction, we recorded the financing receivables as contra-equity. Refer to Note 3 — Acquisitions and Other

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Transactions and Note 11 – (Deficit) Equity for additional details. We recognize interest income on the financing receivables on the basis of the imputed interest rate determined in accordance with ASC Topic 835, Interest.

Cash and Cash Equivalents

Our cash and cash equivalents includes cash and short-term highly liquid overnight deposits.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable represent valid claims against customers for products sold or services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. We establish provisions for losses on third-party accounts receivable due from shippers and operators based on current expected credit losses. As of December 31, 2021 and 2020, we did not have a material amount of allowance for doubtful accounts.

Equity Method Investments

We account for investments where we have the ability to exercise significant influence, but not control, under the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. Differences in the basis of the investments and the underlying net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its historical cost of construction or, upon acquisition, at either the fair value of the assets acquired or the historical carrying value to the entity that placed the asset in service. Expenditures for major renewals and betterments are capitalized while those minor replacement, maintenance and repairs that do not improve or extend asset life are expensed when incurred. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs. We capitalize interest on certain projects. For 2021, 2020 and 2019, the total amount of interest capitalized was immaterial.

We use the straight-line method to depreciate property, plant and equipment based on the estimated useful life of the asset. We report gains or losses on dispositions of fixed assets as Loss (gain) from revision of asset retirement obligations (“AROs”) and disposition of fixed assets in the accompanying consolidated statements of income.

Impairment of Long-lived Assets

We evaluate long-lived assets of identifiable business activities 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 a significant decrease in the market value of the asset, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an 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.

In 2021, we recorded an impairment charge of approximately $3 million related to the divestment of the Auger pipeline. We determined that there were no asset impairments in 2020 or 2019.

Income Taxes

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are generally borne by our partners through the allocation of taxable income. Our income tax expense results from partnership activity in the state of Texas, as conducted by Zydeco, Sand Dollar and Triton. Income tax expense for 2021, 2020 and 2019 was immaterial.

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Investments

We account for equity investments in entities where we do not have control or significant influence at fair value with changes in fair value recognized in net income when the fair value is readily determinable. For investments without readily determinable fair values, we carry such investments at cost less impairments, if any. These investments are remeasured either upon the occurrence of an observable price change or upon identification of impairment. These investments are reported as Other investments in our consolidated balance sheets and dividends received are reported in Dividend income from other investments in our consolidated income statements. Our equity investments which are accounted for at cost as they do not have readily determinable fair values, consist of:


	December 31, 2021				December 31, 2020
	Ownership		Amount		Ownership		Amount
Cleopatra	1.0	%	$	2	1.0	%	$	2

During the years ended December 31, 2021 and 2020, we did not identify the occurrence of an observable price change or an identification of impairment for these equity investments.

Asset Retirement Obligations

AROs represent contractual or regulatory obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Our AROs were zero as of both December 31, 2021 and 2020.

Our assets include pipelines and terminals that have contractual or regulatory obligations that will need to be settled at retirement. The settlement date of these obligations will depend mostly on the various supply sources that connect to our systems and the ongoing demand for usage in the markets we serve. We expect these supply sources and market demands to continue for the foreseeable future. As the settlement dates of obligations are indeterminate, there is not sufficient information to make a reasonable estimate of the ARO of our remaining assets as of December 31, 2021 and 2020.

We re-evaluate our AROs in each reporting period, and future developments could impact the amounts we record.

Pensions and Other Postretirement Benefits

We do not have our own employees. Employees that work on our pipelines or terminals are employees of SPLC, and we share employees with other SPLC-controlled and non-controlled entities. For presentation of these accompanying consolidated financial statements, our portion of payroll costs and employee benefit plan costs have been allocated as a charge to us by SPLC and Shell Oil Company. Shell Oil Company sponsors various employee pension and postretirement health and life insurance plans. For purposes of these accompanying consolidated financial statements, we are considered to be participating in the benefit plans of Shell Oil Company. We participate in the following defined benefits plans: Shell Oil Pension Plan, Shell Oil Retiree Health Care Plan and Pennzoil-Quaker State Retiree Medical & Life Insurance. As a participant in these benefit plans, we recognize as expense in each period an allocation from Shell Oil Company, and we do not recognize any employee benefit plan assets or liabilities. See Note 4 — Related Party Transactions for total pension and benefit expenses under these plans.

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We use both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time, is probable to occur and may require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for the most probable outcome. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit. We expense costs such as permits, compliance with existing environmental regulations, remedial investigations, soil sampling, testing and monitoring costs to meet applicable environmental laws and regulations where prudently incurred or determined to be reasonably possible in the ordinary course of business. We are permitted to recover such expenditures through tariff rates charged to customers. We also expense costs that relate to an

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

existing condition caused by past environmental incidents, which do not contribute to current or future revenue generation. We record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.

For 2021, 2020 and 2019, the environmental cleanup costs incurred were immaterial. At both December 31, 2021 and 2020, the accruals for environmental clean-up costs pursuant to a Consent Decree issued in 1998 by the State of Washington Department of Ecology with respect to our products terminal located in Seattle, Washington were immaterial. The costs relate to ongoing groundwater compliance monitoring and other remedial activities. Refer to Note 4 — Related Party Transactions under the Omnibus Agreement (defined below) for additional details.

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income statement in the period in which they are probable and reasonably estimable.

Other Contingencies

We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the lower end of the range is accrued.

Fair Value Estimates

We measure assets and liabilities requiring fair value presentation or disclosure using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclose such amounts according to the quality of valuation inputs under the following hierarchy:

Level 1: Quoted prices in an active market for identical assets or liabilities.

Level 2: Inputs other than quoted prices that are directly or indirectly observable.

Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.

We classify the fair value of an asset or liability based on the lowest level of input significant to its measurement. A fair value initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement or corroborating market data becomes available. Asset and liability fair values initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable.

The carrying amounts of our accounts receivable, accounts payable and accrued liabilities approximate their fair values due to their short-term nature.

Net income per limited partner unit

Prior to the April 2020 Transaction, we used the two-class method when calculating the net income per unit applicable to limited partners as there were different participating securities included in the calculation – including common units, general partner units and incentive distribution rights (“IDRs”). After the April 2020 Transaction, the IDRs were eliminated, the 2% general partner economic interest was converted into a non-economic general partner interest in the Partnership and the newly issued Series A Preferred Units did not qualify as participating securities. Since the transaction occurred during 2020, the two-class method was still applied to the year-to-date calculation for the year 2020, but was not applied to calculations for any year-to-date calculation for the year 2021 or any quarterly periods beginning with the second quarter of 2020. See Note 11 — (Deficit) Equity for additional information.

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Recent Accounting Pronouncements

Standards Adopted as of January 1, 2021

In August 2020, the FASB issued Accounting Standards Update (“ASU”) 2020-06, Debt — Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging — Contracts in Entity’s Own Equity. The update will simplify the accounting for convertible instruments by reducing the number of accounting models for convertible debt instruments and convertible preferred stock. Limiting the accounting models may result in fewer embedded conversion features being separately recognized from the host contract as compared with current GAAP. This update also amends the guidance for the derivatives scope exception for contracts in an entity’s own equity to reduce form-over-substance-based accounting conclusions. The update is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2021 for SEC filers, excluding smaller reporting companies. We elected to early adopt effective January 1, 2021. The adoption of ASU 2020-06 did not have a material impact on our consolidated financial statements.

3. Acquisitions and Other Transactions

May 2021 Transaction

Auger Divestiture

On January 25, 2021, we executed an agreement to divest the 12” segment of the Auger pipeline; however, this agreement was subsequently terminated. As a result of the intended divestment, we recorded an impairment charge of approximately $3 million during the first quarter of 2021. On April 29, 2021, we executed a new agreement to divest this segment of pipeline, effective June 1, 2021. We received approximately $2 million in cash consideration for this sale. The remainder of the Auger pipeline continues to operate under the ownership of Pecten.

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 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 with our general partner dated February 27, 2020 (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 also agreed to waive a portion of the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

distributions that would otherwise have been 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 and ending with the distribution made with respect to the first quarter of 2021.

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. Certain third-party fair value appraisals were performed to determine the fair value of the total consideration as well as the fair values of each of the Mattox Transaction, the Norco Transaction and the GP/IDR Restructuring, as of April 1, 2020. Because the components of the April 2020 Transaction were entered in contemplation of each other and were transactions among entities under common control, the fair values of the April 2020 Transaction were used solely for the purpose of allocating a portion of the consideration on a relative fair value basis to the Norco Transaction.

In connection with the April 2020 Transaction, the Partnership recorded the following balances as of April 1, 2020:


Equity method investment (1)	$	174
Financing receivables – related parties (2)	302
Contract assets - related parties (3)	244
April 2020 Transaction	$	720

(1) Equity method investment was recorded at SGOM’s historical carrying value of the 79% interest in Mattox. See more discussion in the section entitled “Mattox Transaction” below.

(2) Financing receivables under the failed sale leaseback were recorded at the fair value of the property, plant and equipment of the Norco Assets transferred by SOPUS and Shell Chemical and recognized as a component of the Partners’ deficit. See more discussion in the section entitled “Norco Transaction” below.

(3) Contract assets were recorded based on the difference between the consideration allocated to the Norco Transaction and the financing receivables. See more discussion in the section entitled “Norco Transaction” below.

Mattox Transaction

We acquired 79% of the issued and outstanding membership interests in Mattox from SGOM. The acquisition was accounted for as a transaction among entities under common control on a prospective basis as an asset acquisition. As a result of the Mattox Transaction, we have significant influence, but not control, over Mattox and account for this investment as an equity method investment. As such, we recorded the acquired equity interests in Mattox at SGOM’s historical carrying value of $174 million, which is included in Equity method investments in our consolidated balance sheet as of December 31, 2021. See Note 5 —Equity Method Investments for additional details.

Norco Transaction

SOPUS and Shell Chemical transferred 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, to Triton, as a designee of the Partnership. The Partnership treated the transaction for accounting purposes as simultaneously leasing the Norco Assets back to SOPUS and Shell Chemical pursuant to the terminaling services agreements entered into among Triton, SOPUS and Shell Chemical related to the Norco Assets. The Partnership receives an annual net payment of $140 million, which is the total annual payment pursuant to the terminaling services agreements of $151 million, less $11 million, which primarily represents the allocated utility costs from SOPUS related to the Norco Assets. Both payments are subject to annual Consumer Price Index (“CPI”) adjustments pursuant to an inflation escalation clause in each of the agreements, which provides that the annual payments increase on July 1 of each year commencing on July 1, 2021. On July 1, 2021, the annual payments were escalated by applying a CPI adjustment of 4.86%. After such escalation, the Partnership receives an annual net payment of $147 million, which is the total annual payment of $158 million, less $11 million related to the allocated utility costs from SOPUS.

The transfer of the Norco Assets combined with the terminaling services agreements were accounted for as a failed sale leaseback under the lease standard, as control of the assets did not transfer to the Partnership. As a result, the transaction was treated as a financing arrangement. As the Norco Transaction was entered into simultaneously and in contemplation of the Mattox Transaction and the GP/IDR Restructuring components, we allocated $546 million of the fair value of the consideration of the April 2020 Transaction to the Norco Transaction based on its relative stand-alone fair value to the other components of the April 2020 Transaction. From this amount, we recorded financing receivables of $302 million, based on the fair value of the Norco Assets’ property, plant and equipment transferred from SOPUS and Shell Chemical, using a combination of market and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

cost valuation approaches. The financing receivables were recorded as the fair value of property, plant and equipment because the annual payments received by the Partnership are directly related to the lease of the property, plant and equipment of the Norco Assets. Since the financing receivables from SOPUS and Shell Chemical arose from transactions involving the issuance of the Partnership’s common and preferred units, the financing receivables are presented as a component of (deficit) equity and not as assets on the balance sheet.

As of April 1, 2020, we also recorded contract assets in the amount of $244 million, which represent the difference between the allocated fair value of the Norco Transaction of $546 million and the recognized financing receivables of $302 million. The contract assets represent the excess of the fair value embedded within the terminaling services agreements transferred by the Partnership to SOPUS and Shell Chemical as part of entering into the terminaling services agreements. See Note 12 — Revenue Recognition for additional details.

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

GP/IDR Restructuring

On April 1, 2020, we also closed the transactions contemplated by the Partnership Interests Restructuring Agreement, which included the elimination of all the IDRs and the cancellation of all of the general partner units, both of which were held by our general partner, and amended and restated our partnership agreement to reflect these and other changes (as so amended, the “Second Amended and Restated Partnership Agreement”). The 2% general partner economic interest was converted into a non-economic general partner interest. Because the components of the April 2020 Transaction were among entities under common control, our general partner’s negative equity balance of $4 billion at April 1, 2020 was transferred to SPLC’s equity accounts, allocated between its holdings of common units and preferred units, based on the relative fair value of the consideration related to the issuance of common units and preferred units in the April 2020 Transaction.

Upon the closing of the April 2020 Transaction, the Partnership had 393,289,537 common units outstanding, of which SPLC’s wholly owned subsidiary, Shell Midstream LP Holdings LLC (“LP Holdings”), owned 269,457,304 common units in the Partnership, representing an aggregate 68.5% limited partner interest. The Partnership also had 50,782,904 of Series A Preferred Units outstanding, which are entitled to receive a quarterly distribution of $0.2363 per unit and all of which are owned by LP Holdings. See Note 11 — (Deficit) Equity for additional details.

2019 Acquisition

On June 6, 2019, we acquired SPLC’s remaining 25.97% ownership interest in Explorer and 10.125% ownership interest in Colonial for consideration valued at $800 million (the “June 2019 Acquisition”). The June 2019 Acquisition increased our ownership interest in Explorer to 38.59% and in Colonial to 16.125%. The June 2019 Acquisition closed pursuant to a Contribution Agreement dated May 10, 2019 (the “May 2019 Contribution Agreement”) between us and SPLC, and is accounted for as a transaction between entities under common control on a prospective basis as an asset acquisition. As such, we recorded the acquired equity interests at SPLC’s historical carrying value of $90 million, which is included in Equity method investments in our consolidated balance sheet. In addition, as a transfer between entities under common control, we recorded Accumulated other comprehensive loss of $6 million related to historical remeasurements of pension and other postretirement benefits provided by Explorer and Colonial to their employees. We recognized $510 million of cash consideration in excess of the historical carrying value of equity interests acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. We funded the June 2019 Acquisition with $600 million in cash consideration from borrowings under our Ten Year Fixed Facility (as defined in Note 8 — Related Party Debt) with Shell Treasury Center (West) Inc. (“STCW”) and non-cash equity consideration valued at $200 million. Pursuant to the May 2019 Contribution Agreement, the number of common units representing the equity consideration was determined by dividing the contribution amount (25% of total consideration of $800 million) by the price per unit of $20.68, which represents the volume weighted average sales prices of the common units calculated for the five trading day period ended on April 30, 2019, less the general partner units issued to our general partner in order to maintain its 2% general partner interest in us. The equity issued consisted of 9,477,756 common units issued to LP Holdings, an indirect subsidiary of Shell, and 193,424 general partner units issued to our general partner in order to maintain its 2% general partner interest in us. These common and general partner units

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

issued were assigned no book value because the cash consideration exceeded the historical carrying value of equity interests acquired. Accordingly, the units issued had no impact on partner capital accounts, other than changing ownership percentages.

As a result of the June 2019 Acquisition, we now have significant influence over both Explorer and Colonial and account for these investments as equity method investments. See Note 5 — Equity Method Investments for additional details.

4. Related Party Transactions

Related party transactions include transactions with SPLC and Shell, including those entities in which Shell has an ownership interest but does not have control. See Note 16 – Subsequent Event(s) – Take Private Proposal for additional information regarding the non-binding, preliminary proposal letter that the Board of Directors of our general partner (the “Board”) received from SPLC to acquire all of the Partnership’s issued and outstanding common units not already owned by SPLC or its affiliates.

Acquisition Agreements

Refer to Note 3 — Acquisitions and Other Transactions for a description of other applicable agreements.

Partnership Interests Restructuring Agreement

On February 27, 2020, we and our general partner entered into the Partnership Interests Restructuring Agreement, effective April 1, 2020, 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. See Note 3 — Acquisitions and Other Transactions for additional details.

May 2021 Sale and Purchase Agreement

On April 28, 2021, we entered into the May 2021 Sale and Purchase Agreement between Triton and SPLC, effective May 1, 2021, pursuant to which we sold the Anacortes Assets in exchange for $10 million in cash and the remaining 7.5% interest in Zydeco.

Purchase and Sale Agreement

On February 27, 2020, we entered into the Purchase and Sale Agreement by and among Triton, SPLC, SGOM, Shell Chemical and SOPUS, effective April 1, 2020, pursuant to which we acquired 79% of the issued and outstanding membership interests in Mattox from SGOM and SOPUS and Shell Chemical transferred to Triton, as a designee of the Partnership, the Norco Assets.

Omnibus Agreement

We, our general partner, SPLC and the Operating Company entered into an Omnibus Agreement effective February 1, 2019 (the “2019 Omnibus Agreement”). On February 16, 2021, pursuant to the 2019 Omnibus Agreement, the Board approved a decrease in the annual general and administrative fee to $10 million for 2021, based on a change in the cost of the services provided.

The 2019 Omnibus Agreement addresses, among other things, the following matters:

•our payment of an annual general and administrative fee of approximately $10 million for the provision of certain services by SPLC;

•our obligation to reimburse SPLC for certain direct or allocated costs and expenses incurred by SPLC on our behalf; and

•our obligation to reimburse SPLC for all expenses incurred by SPLC as a result of us becoming and continuing as a publicly-traded entity; we will reimburse our general partner for these expenses to the extent the fees relating to such services are not included in the general and administrative fee.

Trade Marks License Agreement

We, our general partner and SPLC entered into a Trade Marks License Agreement with Shell Trademark Management Inc. effective as of February 1, 2019. The Trade Marks License Agreement grants us the use of certain Shell trademarks and trade names and expires on January 1, 2024 unless earlier terminated by either party upon 360 days’ notice.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Tax Sharing Agreement

We have entered into a tax sharing agreement with Shell. Pursuant to this agreement, we have agreed to reimburse Shell for state and local income and franchise taxes attributable to any activity of our operating subsidiaries and reported on Shell’s state or local income or franchise tax returns filed on a combined or unitary basis. Reimbursements under this agreement equal the amount of tax our applicable operating subsidiaries would be required to pay with respect to such activity, if such subsidiaries were to file a combined or unitary tax return separate from Shell. Shell will compute and invoice us for the tax reimbursement amount within 15 days of Shell filing its combined or unitary tax return on which such activity is included. We may be required to make prepayments toward the tax reimbursement amount to the extent that Shell is required to make estimated tax payments during the relevant tax year. The tax sharing agreement currently in place is effective for all taxable periods ending on or after December 31, 2017. The current agreement replaced a similar tax sharing agreement between Zydeco and Shell, which was effective for all tax periods ending before December 31, 2017. Reimbursements settled in the years ended December 31, 2021, 2020 and 2019 were not material to our consolidated statements of income.

Other Agreements

We have entered into several customary agreements with SPLC and Shell. These agreements include pipeline operating agreements, reimbursement agreements and services agreements.

Operating Agreements

On December 1, 2019, we entered into an Operating and Administrative Management Agreement with SPLC (the “2019 Operating Agreement”). Pursuant to the 2019 Operating Agreement, SPLC provides certain operations, maintenance and administrative services for the assets wholly owned by Pecten, Sand Dollar and Triton (collectively, the “Owners”). The Owners are required to reimburse SPLC for certain costs in connection with the services that SPLC provides pursuant to the 2019 Operating Agreement. SPLC and the Owners each provide standard indemnifications as operator and asset owners, respectively. Upon entering into the 2019 Operating Agreement, certain operating agreements previously entered into between SPLC and each of the Owners were terminated.

In December 2017, we were assigned an operating agreement for Odyssey, whereby SPLC performs physical operations and maintenance services and provides general and administrative services for Odyssey. Odyssey is required to reimburse SPLC for costs and expenses incurred in connection with such services. Also pursuant to the agreement, SPLC and Odyssey agree to standard indemnifications as operator and asset owner, respectively.

Beginning July 1, 2014, Zydeco entered into an operating and management agreement with SPLC under which SPLC provides general management and administrative services to us. Therefore, we do not receive allocated corporate expenses from SPLC or Shell under this agreement. We receive direct and allocated field and regional expenses including payroll expenses not covered under this agreement.

Partnership Agreement

Concurrently with the execution of the Partnership Interests Restructuring Agreement, on April 1, 2020, we executed the Second Amended and Restated Partnership Agreement, which amended and restated the Partnership’s First Amended and Restated Agreement of Limited Partnership dated November 3, 2014 (“First Amended and Restated Partnership Agreement”, as the same was previously amended) in its entirety. Under the Second Amended and Restated Partnership Agreement, the IDRs were eliminated, the economic general partnership interest was converted into a non-economic general partner interest, and our general partner or its assignee agreed to waive a portion of the distributions that would otherwise have been 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 and ending with the distribution made with respect to the first quarter of 2021. The transaction closed simultaneously with the closing of the transactions described in Note 3 — Acquisitions and Other Transactions—April 2020 Transaction.

Prior to the execution of the Second Amended and Restated Partnership Agreement, on December 21, 2018, we executed Amendment No. 2 (the “Second Amendment”) to the First Amended and Restated Partnership Agreement. Under the Second Amendment, our general partner agreed to waive $50 million of distributions in 2019 by agreeing to reduce distributions to holders of the IDRs by: (1) $17 million for the three months ended March 31, 2019, (2) $17 million for the three months ended June 30, 2019 and (3) $16 million for the three months ended September 30, 2019.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Noncontrolling Interests

For Zydeco, there is no non-controlling interest as of December 31, 2021 as a result of the May 2021 Transaction. Refer to Note 3 — Acquisitions and Other Transactions for additional information. The noncontrolling interest for Zydeco consisted of SPLC’s 7.5% retained ownership interest as of December 31, 2020 and 2019. For Odyssey, noncontrolling interest consists of GEL Offshore Pipeline LLC’s (“GEL”) 29.0% retained ownership interest as of December 31, 2021, 2020 and 2019.

Other Related Party Balances

Other related party balances consist of the following:


	December 31,
	2021		2020
Accounts receivable	$	40	$	21
Prepaid expenses	23		22
Other assets	2		2
Contract assets (1)	218		233
Accounts payable (2)	17		16
Deferred revenue	31		19
Accrued liabilities (3)	24		28
Debt payable (4)	2,692		2,692
Finance lease liability	2		2
Financing receivables (1)	293		298

(1) Contract assets and Financing receivables were recognized in connection with the April 2020 Transaction. Refer to the section entitled “Sale Leaseback” below for additional details. Financing receivables were presented as a component of (deficit) equity.

(2) Accounts payable reflects amounts owed to SPLC for reimbursement of third-party expenses incurred by SPLC for our benefit.

(3) As of December 31, 2021, Accrued liabilities reflects $15 million of accrued interest and $9 million of other accrued liabilities. As of December 31, 2020, Accrued liabilities reflects $16 million of accrued interest and $12 million of other accrued liabilities. Other accrued liabilities are primarily related to the accrued operation and maintenance expenses on the Norco Assets.

(4) Debt payable reflects borrowings outstanding after taking into account unamortized debt issuance costs of $2 million as of both December 31, 2021 and December 31, 2020.

Related Party Credit Facilities

We have entered into five credit facilities with STCW: the 2021 Ten Year Fixed Facility, the Ten Year Fixed Facility, the Seven Year Fixed Facility, the Five Year Revolver due July 2023, and the Five Year Revolver due December 2022. On June 30, 2021, Zydeco entered into a termination of revolving loan facility agreement with STCW to terminate the 2019 Zydeco Revolver. See Note 8 — Related Party Debt for definitions and additional information regarding these credit facilities.

Related Party Revenues and Expenses

We provide crude oil transportation, terminaling and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our business. Our revenue from related parties for 2021, 2020 and 2019 is disclosed in Note 12 — Revenue Recognition.

The following table shows related party expenses, including certain personnel costs, incurred by Shell and SPLC on our behalf that are reflected in the accompanying consolidated statements of income for the indicated periods. Included in these amounts, and disclosed below, is our share of operating and general corporate expenses, as well as the fees paid to SPLC under certain agreements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	2021		2020		2019
Allocated operating expenses	$	53	$	45	$	18
Major maintenance costs (1)	8		6		—
Insurance expense (2)	20		20		18
Other (3)	43		43		23
Operations and maintenance – related parties	$	124	$	114	$	59

Allocated general corporate expenses	$	25	$	29	$	28
Management Agreement fee	10		9		9
Omnibus Agreement fee	10		11		11
Other	—		—		1
General and administrative – related parties	$	45	$	49	$	49

(1) Major maintenance costs are expensed as incurred in connection with the maintenance services of the Norco Assets. Refer to section entitled “Sale Leaseback” below for additional details.

(2) Prior to November 1, 2021, the majority of our insurance coverage was provided by a wholly owned subsidiary of Shell, with the remaining coverage provided by third-party insurers. After November 1, 2021, a third-party insurer provided and continues to provide the first 5% of our insurance coverage with the remaining coverage provided by an affiliate of Shell as a reinsurer.

(3) Other expenses primarily relate to salaries and wages, other payroll expenses and special maintenance.

For a discussion of services performed by Shell on our behalf, see Note 1 — Description of the Business and Basis of Presentation – Basis of Presentation – Expense Allocations.

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health and life insurance and defined contribution benefit plans sponsored by Shell, which include other Shell subsidiaries. Our share of pension and postretirement health and life insurance costs for 2021, 2020 and 2019 was $5 million, $5 million and $6 million, respectively. Our share of defined contribution benefit plan costs was $2 million for each of 2021, 2020 and 2019. Pension and defined contribution benefit plan expenses are included in either General and administrative – related parties or Operations and maintenance – related parties in the accompanying consolidated statements of income, depending on the nature of the employee’s role in our operations.

Severance

Severance expenses are included in either General and administrative – related parties or Operations and maintenance – related parties, depending on the nature of the employee’s role in our operations. We recorded voluntary and involuntary severance costs of $7 million in 2020. These costs for 2021 and 2019 were not material.

Equity and Other Investments

We have equity and other investments in various entities. In some cases, we may be required to make capital contributions or other payments to these entities. See Note 5 — Equity Method Investments for additional details.

Reimbursements from Our General Partner

Historically, reimbursements received were primarily related to the directional drill project on the Zydeco pipeline system (the

“directional drill project”). As the directional drill project was completed at the end of 2019, the amounts incurred by the project in 2021 and 2020, and associated claims for reimbursement from our Parent, were both not material. In 2019, the amount incurred and claimed for reimbursement was $19 million. These reimbursements are included in Other contributions from Parent in the accompanying consolidated statements of cash flows and consolidated statements of (deficit) equity. For each of these periods, this amount reflects our proportionate share of the directional drill project costs and expenses.

Further, in the fourth quarter of 2019, we received approximately $9 million from SPLC with respect to a Mars storage revenue reimbursement provision contained in the Purchase and Sale Agreement entered into in 2016 that was recognized as an additional capital contribution. See Note 5 — Equity Method Investments for additional details.

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Sale Leaseback

Pursuant to the terminaling services agreement entered into among Triton, SOPUS and Shell Chemical related to the Norco Assets acquired in the April 2020 Transaction (see Note 3 — Acquisitions and Other Transactions), the Partnership receives an annual net payment of $140 million, which is the total annual payment pursuant to the terminaling service agreements of $151 million, less $11 million, which primarily represents the allocated utility costs from SOPUS related to the Norco Assets. The annual payments are subject to annual Consumer Price Index adjustments. See Note 12 — Revenue Recognition for additional details.

The transfer of the Norco Assets, combined with the terminaling services agreements, were accounted for as a failed sale leaseback under the lease standard. As a result, the transaction was treated as a financing arrangement in which the underlying assets were not recognized in property, plant and equipment of the Partnership as control of the Norco Assets did not transfer to the Partnership, and instead were recorded as financing receivables from SOPUS and Shell Chemical.

We recognize interest income on the financing receivables on the basis of an imputed interest rate of 11.1% related to SOPUS and 7.4% related to Shell Chemical. The following table shows the cash payments received for interest income and cash principal payments received on the financing receivables for the years ended December 31, 2021 and 2020:


	For the Year Ended December 31,
	2021		2020
Cash payments received for interest income	$	30	$	20
Cash principal payments received on financing receivables	5		3

The transfer of the Norco Assets and the terminaling services agreements as a result of the April 2020 Transaction have operation and maintenance service components and major maintenance service components (together “service components”). Consistent with our operating lease arrangements, we allocate a portion of the arrangement’s transaction price to any service components within the scope of ASC Topic 606, Revenue from Contracts with Customers (“the revenue standard”) and defer the revenue, if necessary, until the point at which the performance obligation is met. We present the revenue earned from the service components under the revenue standard within Transportation, terminaling and storage services – related parties in the consolidated statements of income. See Note 12 — Revenue Recognition for additional details related to revenue recognized on the service components and amortization of the contract assets.

5. Equity Method Investments

For each of the following investments, we have the ability to exercise significant influence over these investments based on certain governance provisions and our participation in the significant activities and decisions that impact the management and economic performance of the investments.

Equity method investments comprise the following as of the dates indicated:


	December 31,
	2021			2020
	Ownership	Amount		Ownership	Amount
Mattox	79.0%	$	156	79.0%	$	163
Amberjack – Series A / Series B	75.0% / 50.0%	359		75.0% / 50.0%	382
Mars	71.5%	150		71.5%	152
Bengal	50.0%	85		50.0%	88
Permian Basin	50.0%	80		50.0%	83
LOCAP	41.48%	15		41.48%	12
Explorer	38.59%	68		38.59%	73
Poseidon	36.0%	—		36.0%	—
Colonial	16.125%	32		16.125%	29
Proteus	10.0%	13		10.0%	14
Endymion	10.0%	16		10.0%	17
		$	974		$	1,013

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Impacts to Equity Method Investments

Earnings from our equity method investments were as follows during the periods indicated:


	For the Year Ended December 31,
	2021		2020		2019
Mattox (1)	$	60	$	45	$	—
Amberjack	106		102		125
Mars	83		114		126
Bengal	9		18		24
Explorer (2)	61		44		41
Colonial (2)	18		75		40
Poseidon (3)	—		—		—
Other (4)	15		19		17
	$	352	$	417	$	373

(1) We acquired an interest in Mattox in the April 2020 Transaction. The acquisition of this interest has been accounted for prospectively.

(2) We acquired additional interests in Explorer and Colonial in the June 2019 Acquisition. The acquisition of these interests has been accounted for prospectively.

(3) As stated below, the equity method of accounting has been suspended since early 2018 for Poseidon and excess distributions are recorded in Other income.

(4) Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion.

For the years ended December 31, 2021, 2020 and 2019, distributions received from equity method investments were $433 million, $541 million and $466 million, respectively.

Unamortized differences in the basis of the initial investments and our interest in the separate net assets within the financial statements of the investees are amortized into net income over the remaining useful lives of the underlying assets. The amortization is included in Income from equity method investments. As of December 31, 2021 and 2020, the unamortized basis differences included in our equity method investments were $75 million and $84 million, respectively. For the years ended 2021, 2020 and 2019, the net amortization expense was $9 million, $8 million and $6 million, respectively. Included in the net amortization expense for 2021 is a write-off of approximately $2 million of unamortized basis difference as a result of an impairment taken by Colonial.

Cumulatively, distributions received from Poseidon have been in excess of our investment balance and, therefore, the equity method of accounting has been suspended for this investment and the investment amount reduced to zero. As we have no commitments to provide further financial support to Poseidon, we have recorded excess distributions of $39 million, $37 million and $33 million in Other income for the years ended December 31, 2021, 2020 and 2019, respectively. Once our cumulative share of equity earnings becomes greater than the cumulative amount of distributions received, we will resume the equity method of accounting as long as the equity method investment balance remains greater than zero.

Transactions

We acquired a 79% interest in Mattox from SGOM in the April 2020 Transaction. This investment qualifies for equity method accounting, as we exercise significant influence but do not control this investment. Upon acquisition, we recorded SGOM’s historical carrying value of the equity interests transferred as a transaction between entities under common control, totaling $174 million. We recognize equity earnings for Mattox prospectively from the date of acquisition, and record the distributions from Mattox as a reduction to the equity method investment balance.

We acquired an additional 25.97% interest in Explorer and an additional 10.125% interest in Colonial in the June 2019 Acquisition. As a result, these investments now qualify for equity method accounting as we have the ability to exercise significant influence over these investments as of the acquisition date. Prior to the acquisition date, Explorer and Colonial were accounted for as Other investments without readily determinable fair values and were therefore carried at cost. Upon acquisition, we added our Parent’s historical carrying value of the equity interests transferred as a transaction between entities under common control, totaling $90 million, to the basis of our previously held interests of $60 million as this is the date these investments qualified for equity method accounting. Since the June 2019 Acquisition, we record distributions from these investments as reductions to the respective equity method investment balances for Explorer and Colonial as these amounts are

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

no longer considered dividend income due to the change in the method of accounting. We recognize equity earnings for both Explorer and Colonial prospectively from the date of acquisition.

Significant Developments

•The board of directors of Colonial elected not to declare a dividend for each of the three months ended June 30, 2021, September 30, 2021 and December 31, 2021.

•During the fourth quarter of 2021, Colonial recorded an impairment, of which our share was approximately $44 million, that negatively impacted both our income from equity method investments and net income.

•Effective June 4, 2021, Amberjack executed an agreement to divest a small segment of the Amberjack pipeline that is no longer utilized nor deemed a material component in the operation of the pipeline. As a result of the divestment, Amberjack recorded an impairment charge of approximately $4 million during the second quarter of 2021. Our share of approximately $3 million impacted our Income from equity method investments in our consolidated statements of income. The remainder of the Amberjack pipeline continues to operate under its existing ownership structure.

•Under the lease standard, the adoption date for our equity method investments will follow the non-public business entity adoption date of January 1, 2020 for their stand-alone financial statements, with the exception of Permian Basin, which adopted on January 1, 2019. There has been no material impact on the Partnership’s consolidated financial statements as a result of the adoption of the lease standard by our equity method investees.

•On October 23, 2019, we entered into a Settlement Agreement with SPLC (the “Settlement Agreement”) with respect to the storage revenue reimbursement provision contained in the Purchase and Sale Agreement entered into in 2016 under which we acquired an additional 20% interest in Mars. Pursuant to this Purchase and Sale Agreement, SPLC had agreed to pay us up to $10 million if Mars inventory management fees do not meet certain levels for the calendar years 2017 through 2021. As a result of the Settlement Agreement, we received approximately $9 million during the fourth quarter of 2019 from SPLC that was recognized as an additional capital contribution.

Capital Contributions

We make capital contributions for our pro rata interest in Permian Basin to fund capital and other expenditures. We made capital contributions to Permian Basin of approximately $4 million and $25 million in 2021 and 2019, respectively. We did not make any capital contributions in 2020.

Impairment Assessment

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 evaluated whether an impairment indicator existed as of December 31, 2021. Based on expectations of market conditions, we determined that there was no triggering event that required us to update our impairment evaluation of our equity method investments. However, if the facts and circumstances change in the near-term and indicate a loss in value that is other-than-temporary, we will re-evaluate whether the carrying amount of our equity method investments may not be recoverable.

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our equity method investments on a 100% basis. However, during periods in which an acquisition occurs, the selected balance sheet and income statement data reflects activity from the date of the acquisition.

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	For the Year Ended December 31, 2021
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox	$	88	$	12	$	76	$	76
Amberjack	271		66		205		203
Mars	211		91		120		120
Bengal	46		29		17		17
Explorer	405		178		227		165
Colonial	1,304		1,002		302		123
Poseidon	134		37		97		93
Other (1)	213		126		87		82


	As of December 31, 2021
	Current assets		Non-current assets		Total assets		Current liabilities		Non-current liabilities		Equity (deficit)		Total liabilities and equity (deficit)
Balance Sheets
Mattox	$	11	$	195	$	206	$	—	$	9	$	197	$	206
Amberjack	53		786		839		5		134		700		839
Mars	50		245		295		26		79		190		295
Bengal	28		164		192		11		—		181		192
Explorer	85		574		659		54		508		97		659
Colonial	695		3,008		3,703		307		3,503		(107)		3,703
Poseidon	18		167		185		8		232		(55)		185
Other (1)	33		871		904		43		459		402		904

(1) Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion.


	For the Year Ended December 31, 2020
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox (1)	$	66	$	9	$	57	$	57
Amberjack	280		78		202		201
Mars	259		97		162		163
Bengal	65		30		35		35
Explorer	329		175		154		119
Colonial	1,395		660		735		473
Poseidon	147		36		111		105
Other (2)	220		123		97		88

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	As of December 31, 2020
	Current assets		Non-current assets		Total assets		Current liabilities		Non-current liabilities		Equity (deficit)		Total liabilities and equity (deficit)
Balance Sheets
Mattox (1)	$	13	$	204	$	217	$	—	$	12	$	205	$	217
Amberjack	44		836		880		10		124		746		880
Mars	47		269		316		23		103		190		316
Bengal	33		161		194		7		—		187		194
Explorer	74		537		611		49		459		103		611
Colonial	501		3,105		3,606		245		3,508		(147)		3,606
Poseidon	31		176		207		10		238		(41)		207
Other (2)	35		920		955		56		486		413		955

(1) Our interest in Mattox was acquired in the April 2020 Transaction. Mattox’s total revenues, total operating expenses and operating income (on a 100% basis) were $85 million, $12 million and $73 million, respectively.

(2) Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion.


	For the Year Ended December 31, 2019
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Amberjack	$	315	$	73	$	242	$	243
Mars	282		104		178		179
Bengal	77		30		47		47
Explorer (1)	258		115		143		111
Colonial (2)	829		449		380		255
Poseidon	132		35		97		87
Other (3)	190		108		82		73


	As of December 31, 2019
	Current assets		Non-current assets		Total assets		Current liabilities		Non-current liabilities		Equity (deficit)		Total liabilities and equity (deficit)
Balance Sheets
Amberjack	$	56	$	804	$	860	$	4	$	32	$	824	$	860
Mars	57		173		230		8		22		200		230
Bengal	35		157		192		6		—		186		192
Explorer (1)	93		530		623		44		442		137		623
Colonial (2)	323		2,920		3,243		519		2,873		(149)		3,243
Poseidon	30		190		220		16		246		(42)		220
Other (3)	60		917		977		73		469		435		977

(1) Our interest in Explorer was acquired on June 6, 2019. Explorer total revenues, total operating expenses and operating income (on a 100% basis) was $443 million, $196 million and $247 million, respectively.

(2) Our interest in Colonial was acquired on June 6, 2019. Colonial total revenues, total operating expenses and operating income (on a 100% basis) was $1,437 million, $735 million and $702 million, respectively.

(2) Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion.

6. Property, Plant and Equipment

Property, plant and equipment, net consists of the following as of the dates indicated:

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


		December 31,
	Depreciable Life	2021		2020
Land	—	$	12	$	12
Building and improvements	10 - 40 years	45		47
Pipeline and equipment (1)	10 - 30 years	1,240		1,263
Other	5 - 25 years	35		34
		1,332		1,356
Accumulated depreciation and amortization (2)		(690)		(661)
		642		695
Construction in progress		12		4
Property, plant and equipment, net		$	654	$	699

(1) As of December 31, 2021 and 2020, includes cost of $366 million and $372 million, respectively, related to assets under operating leases (as lessor). As of both December 31, 2021 and 2020, includes cost of $23 million related to assets under capital lease (as lessee).

(2) As of December 31, 2021 and 2020, includes accumulated depreciation of $155 million and $147 million, respectively, related to assets under operating leases (as lessor), which commenced in May 2017 and December 2017. As of December 31, 2021 and 2020, includes accumulated depreciation of $9 million and $8 million, respectively, related to assets under capital lease (as lessee).

Depreciation and amortization expense on property, plant and equipment for 2021, 2020 and 2019 was $50 million, $50 million and $49 million, respectively, and is included in cost and expenses in the accompanying consolidated statements of income. Depreciation and amortization expense on property, plant and equipment includes amounts pertaining to assets under operating (as lessor) and capital leases (as lessee).

We evaluate long-lived assets for potential impairment indicators whenever events or changes in circumstances indicate that the carrying amount of our assets may not be recoverable. Due to the changes in market conditions and the extent of use of certain long-lived assets, we evaluated whether an impairment indicator existed as of December 31, 2021. Based on our current forecast and expectations of market conditions, we determined that there was no triggering event that required us to update our impairment evaluation of property, plant and equipment. However, if current volatile market conditions deteriorate or any future downturn continues for an extended period of time, we may be required to assess the recoverability of our long-lived assets, which could result in an impairment.

May 2021 Transaction

Effective May 1, 2021, Triton sold to SOPUS, as designee of SPLC, the Anacortes Assets. In exchange for the Anacortes Assets, SPLC paid Triton $10 million in cash and transferred to the Operating Company, as designee of Triton, SPLC’s 7.5% interest in Zydeco. Effective May 1, 2021, the Partnership owns a 100.0% ownership interest in Zydeco. Refer to Note 3 – Acquisitions and Other Transactions for additional information on this transaction.

Auger Divestiture

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Accrued Liabilities – Third Parties

Accrued liabilities – third parties consist of the following as of the dates indicated:


	December 31,
	2021		2020
Project accruals	$	2	$	4
Property taxes	6		5
Other accrued liabilities	3		1
Total accrued liabilities – third parties	$	11	$	10

8. Related Party Debt

Consolidated related party debt obligations comprise the following as of the dates indicated:


	December 31, 2021						December 31, 2020
	Outstanding Balance		Total Capacity		Available Capacity		Outstanding Balance		Total Capacity		Available Capacity
Current
Five Year Revolver due December 2022	$	400	$	1,000	$	600	$	—	$	—	$	—
Total current debt payable (1)	$	400	$	1,000	$	600	$	—	$	—	$	—

Noncurrent
2021 Ten Year Fixed Facility	$	600	$	600	$	—	$	—	$	—	$	—
Ten Year Fixed Facility	600		600		—		600		600		—
Seven Year Fixed Facility	600		600		—		600		600		—
Five Year Revolver due July 2023	494		760		266		494		760		266
Five Year Revolver due December 2022	—		—		—		400		1,000		600
Five Year Fixed Facility (2)	—		—		—		600		600		—
2019 Zydeco Revolver (3)	—		—		—		—		30		30
Unamortized debt issuance costs	(2)		n/a		n/a		(2)		n/a		n/a
Total noncurrent debt payable	$	2,292	$	2,560	$	266	$	2,692	$	3,590	$	896

Total debt payable	$	2,692	$	3,560	$	866	$	2,692	$	3,590	$	896

(1) The unamortized debt issuance costs for the current debt payable is less than $1 million and is therefore not being reflected in this table.

(2) The Five Year Fixed Facility was terminated in March 2021. See below for additional information.

(3) The 2019 Zydeco Revolver was terminated effective June 30, 2021. See below for additional information.

Interest and fee expenses associated with our borrowings, net of capitalized interest, were $82 million, $90 million and $92 million for 2021, 2020 and 2019, respectively, of which we paid $81 million, $92 million and $88 million, respectively.

Credit Facility Agreements

2021 Ten Year Fixed Facility

On March 16, 2021, we entered into a ten-year fixed rate credit facility with STCW with a borrowing capacity of $600 million (the “2021 Ten Year Fixed Facility”). The 2021 Ten Year Fixed Facility bears an interest rate of 2.96% per annum and matures on March 16, 2031. No issuance fee was incurred in connection with the 2021 Ten Year Fixed Facility. The 2021 Ten Year Fixed Facility contains customary representations, warranties, covenants and events of default, the occurrence of which would permit the lender to accelerate the maturity date of amounts borrowed under the 2021 Ten Year Fixed Facility.

Ten Year Fixed Facility

On June 4, 2019, we entered into a ten-year fixed rate credit facility with STCW with a borrowing capacity of $600 million (the “Ten Year Fixed Facility”). The Ten Year Fixed Facility bears an interest rate of 4.18% per annum and matures on June 4, 2029. No issuance fee was incurred in connection with the Ten Year Fixed Facility. The Ten Year Fixed Facility contains

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

customary representations, warranties, covenants and events of default, the occurrence of which would permit the lender to accelerate the maturity date of amounts borrowed under the Ten Year Fixed Facility.

Seven Year Fixed Facility

On July 31, 2018, we entered into a seven-year fixed rate credit facility with STCW with a borrowing capacity of $600 million (the “Seven Year Fixed Facility”). We incurred an issuance fee of $1 million, which was paid on August 7, 2018. The Seven Year Fixed Facility contains customary representations, warranties, covenants and events of default, the occurrence of which would permit the lender to accelerate the maturity date of amounts borrowed under the Seven Year Fixed Facility.

The Seven Year Fixed Facility bears an interest rate of 4.06% per annum and matures on July 31, 2025.

Five Year Revolver due July 2023

On August 1, 2018, we amended and restated the five year revolving credit facility originally due October 2019 such that the facility will now mature on July 31, 2023 (the “Five Year Revolver due July 2023”). The Five Year Revolver due July 2023 has a borrowing capacity of $760 million and will continue to bear interest at LIBOR plus a margin and we continue to pay interest of 0.19% on any unused capacity. Commitment fees began to accrue beginning on the date we entered into the agreement. There was no issuance fee associated with this amendment. All other material terms and conditions of the Five Year Revolver due July 2023 remain unchanged.

As of December 31, 2021, the annualized weighted average interest rate for the Five Year Revolver due July 2023 was 1.28%.

The Five Year Revolver due July 2023 was originally entered into on November 3, 2014, and provides that loans advanced under the facility can have a term ending on or before its maturity date.

Five Year Revolver due December 2022

On December 1, 2017, we entered into a five year revolving credit facility with STCW (the “Five Year Revolver due December 2022”) with a borrowing capacity of $1,000 million and paid an issuance fee of $2 million. Borrowings under the Five Year Revolver due December 2022 bear interest at the three-month LIBOR rate plus a margin, or, in the alternative, the percentage rate per annum which is the rate notified to us by STCW in accordance with the terms thereunder before interest is due to be paid in respect of a loan. Additionally, we pay interest of 0.19% on any unused capacity. As of December 31, 2021, the weighted average interest rate for the Five Year Revolver due December 2022 was 1.47%. Commitment fees began to accrue beginning on the date we entered into the agreement. The Five Year Revolver due December 2022 matures on December 1, 2022.

Five Year Fixed Facility

On March 1, 2017, we entered into a Loan Facility Agreement with STCW with a borrowing capacity of $600 million (the “Five Year Fixed Facility”). In March 2021, the Five Year Fixed Facility was replaced and repaid by the borrowings under the 2021 Ten Year Fixed Facility. In consideration for STCW’s consent to the prepayment of the Five Year Fixed Facility, the Partnership incurred a fee of approximately $2 million, which was paid on March 23, 2021. The Five Year Fixed Facility automatically terminated in connection with the prepayment.

Zydeco Revolving Credit Facility Agreement

On August 1, 2019, Zydeco entered into a senior unsecured revolving loan facility agreement with STCW, effective August 6, 2019 (the “2019 Zydeco Revolver”). The 2019 Zydeco Revolver had a borrowing capacity of $30 million. On June 30, 2021, Zydeco entered into a termination of revolving loan facility agreement with STCW to terminate the 2019 Zydeco Revolver. Zydeco had not borrowed any funds under this facility, and therefore, no further obligations existed at the time of termination.

Borrowings and Repayments

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Borrowings under these revolving credit facilities approximate fair value as the interest rates are variable and reflective of market rates, which results in Level 2 instruments. The fair value of our fixed rate credit facilities is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as Level 2 within the fair value hierarchy. As of December 31, 2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,694 million and $2,849 million, respectively. As of December 31, 2020, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,694 million and $2,928 million, respectively.

The 2021 Ten Year Fixed Facility was fully drawn on March 23, 2021, and the borrowings were used to repay the borrowings under, and replace, the Five Year Fixed Facility. In consideration for STCW’s consent to the prepayment of the Five Year Fixed Facility, the Partnership incurred a fee of approximately $2 million, which was paid on March 23, 2021. The Five Year Fixed Facility automatically terminated in connection with the prepayment.

The Ten Year Fixed Facility was fully drawn on June 6, 2019 to partially fund the June 2019 Acquisition.

Borrowings and repayments under our credit facilities for 2021, 2020 and 2019 are disclosed in our consolidated statements of cash flows. See Note 3 — Acquisitions and Other Transactions for additional information regarding our use of borrowings if applicable to the period. See Note 11 – (Deficit) Equity for additional information regarding the source of our repayments, if applicable to the period.

Covenants

Under the 2021 Ten Year Fixed Facility, the Ten Year Fixed Facility, the Seven Year Fixed Facility, the Five Year Revolver due July 2023 and the Five Year Revolver due December 2022, we have agreed, amongst other things:

•to restrict additional indebtedness not loaned by STCW;

•to give the applicable facility pari passu ranking with any new indebtedness; and

•to refrain from securing our assets except as agreed with STCW.

These facilities also contain customary events of default, such as nonpayment of principal, interest and fees when due and violation of covenants, as well as cross-default provisions under which a default under one credit facility may trigger an event of default in another facility with the same borrower. Any breach of covenants included in our debt agreements that could result in our related party lender demanding payment of the unpaid principal and interest balances will have a material adverse effect upon us and would likely require us to default on or seek to renegotiate these debt arrangements with our related party lender and/or obtain new financing from other sources. As of December 31, 2021, we were in compliance with the covenants contained in our credit facilities.

9. Leases

Adoption of ASC Topic 842 “Leases”

On January 1, 2019, we adopted the lease standard by applying the modified retrospective approach to all leases on January 1, 2019. We elected the package of practical expedients upon transition that permits us to not reassess (1) whether any contracts entered into prior to adoption are or contain leases, (2) the lease classification of existing leases and (3) initial direct costs for any leases that existed prior to adoption. We also elected the practical expedient to not evaluate existing or expired land easements that were not accounted for as leases under previous guidance. Generally, we account for term-based land easements where we control the use of the land surface as leases.

Upon adoption on January 1, 2019, we recognized operating lease right-of-use (“ROU”) assets and corresponding lease liabilities of $5 million. As lessor, the accounting for operating leases has not changed and the adoption did not have an impact on our existing transportation and terminaling services agreements that are considered operating leases. As lessee, the accounting for finance leases (capital leases) was substantially unchanged.

Lessee accounting

We determine if an arrangement is or contains a lease at inception. Our assessment is based on (1) whether the contract involves the use of a distinct identified asset, (2) whether we obtain the right to substantially all the economic benefit from the use of the asset throughout the period and (3) whether we have the right to direct the use of the asset. Leases are classified as either finance leases or operating leases. A lease is classified as a finance lease if any one of the following criteria are met: the lease transfers ownership of the asset by the end of the lease term, the lease contains an option to purchase the asset that is reasonably

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

certain to be exercised, the lease term is for a major part of the remaining useful life of the asset or the present value of the lease payments equals or exceeds substantially all of the fair value of the asset. A lease is classified as an operating lease if it does not meet any one of these criteria. The lease classification affects the expense recognition in the income statement. Operating lease costs are recorded entirely in operating expenses. Finance lease costs are split, where amortization of the ROU asset is recorded in operating expenses and an implied interest component is recorded in interest expense.

Under the lease standard, operating leases (as lessee) are included in Operating lease right-of-use assets, Accrued liabilities - third parties and Operating lease liabilities in our consolidated balance sheets. Finance leases (as lessee) are included in Property, plant and equipment, Accrued liabilities – third parties and Finance lease liabilities in our consolidated balance sheets. ROU assets and lease liabilities are recognized at commencement date based on the present value of the future minimum lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we use our incremental borrowing rate (“IBR”) based on the information available at transition date in determining the present value of future payments. The ROU asset includes any lease payments made but excludes lease incentives and initial direct costs incurred, if any. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.

We have long-term non-cancelable third-party operating leases for land. Several of the leases provide for renewal terms. We hold cancellable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Obligations under these easements are not material to the results of our operations.

Odyssey entered into an operating lease in May 1999 with a third party for usage of offshore platform space at Main Pass 289C. The terms of this operating lease agreement were modified as of August 27, 2021 and the contract modification is effective retrospectively from January 26, 2021. The variable lease payment for the modified agreement consists of the operating expenses incurred and the throughput fee required by the platform. The agreement will terminate as of January 1, 2023.

We are also obligated under two finance leases. On December 1, 2014, we entered into a terminal services agreement in which we were to take possession of certain storage tanks located in Port Neches, Texas, effective December 1, 2015. In October 2015, the terminal services agreement was amended to provide for an interim in-service period for the purposes of commissioning the tanks in which we paid a nominal monthly fee. Our capitalized costs and related capital lease obligation commenced effective December 1, 2015, and the storage tanks were placed in-service on September 1, 2016. Under this agreement, in the eighteenth month after the in-service date, actual fixed and variable costs could be compared to premised costs. If the actual and premised operating costs differ by more than 5%, the lease would be adjusted accordingly, and this adjustment will be effective for the remainder of the lease. No adjustment has been made to date. The imputed interest rate on the capital portion of the lease is 15%. We also have a lease of offshore platform space on the Garden Banks 128 “A” platform.

Lease extensions. Many of our leases have options to either extend or terminate the lease. In determining the lease term, we considered all available contract extensions that are reasonably certain of occurring.

Significant assumptions and judgments

Incremental borrowing rate. We are generally not made aware of the interest rate implicit in a lease due to several reasons, including: (1) uncertainty as to the total amount of the costs incurred by the lessor in negotiating the lease or whether certain costs incurred by the lessor would qualify as initial direct costs and (2) uncertainty as to the lessor’s expectation of the residual value of the asset at the end of the lease. Therefore, we use our IBR at the commencement of the lease and estimate the IBR for each lease agreement taking into consideration lease contract term, collateral and entity credit ratings, and use sensitivity analyses to evaluate the reasonableness of the rates determined.

Lease balances and costs

The following tables summarize balance sheet data related to leases at December 31, 2021 and 2020 and our lease costs as of and for the year ended December 31, 2021, 2020 and 2019:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Leases	Classification	December 31, 2021		December 31, 2020
Assets
Operating lease assets	Operating lease right-of-use assets	$	3	$	4
Finance lease assets	Property, plant and equipment, net (1)	14		16
Total lease assets		$	17	$	20

Liabilities
Current
Finance	Accrued liabilities - third parties	$	1	$	1
Noncurrent
Operating	Operating lease liabilities	4		4
Finance	Finance lease liabilities	23		24
Total lease liabilities		$	28	$	29

(1) Finance lease assets are recorded net of accumulated amortization of $9 million as of December 31, 2021 and $8 million as of December 31, 2020.


Lease cost	Classification	December 31, 2021		December 31, 2020		December 31, 2019
Operating lease cost (1)	Operations and maintenance - third parties	$	—	$	—	$	—
Finance lease cost (cost resulting from lease payments):
Amortization of leased assets	Depreciation and amortization	1		1		1
Interest on lease liabilities	Interest expense, net	3		4		4
Total lease cost		$	4	$	5	$	5

(1) Amounts for each year ended December 31, 2021, 2020 and 2019 were less than $1 million.

Other information


	December 31, 2021		December 31, 2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases (1)	$	—	$	—
Operating cash flows from finance leases	(3)		(3)
Financing cash flows from finance leases	(1)		(1)

(1) Amounts for each year ended December 31, 2021 and 2020 were less than $1 million.


	December 31, 2021		December 31, 2020		December 31, 2019
Weighted-average remaining lease term (years):
Operating leases	18		19		20
Finance leases	9		10		11

Weighted-average discount rate:
Operating leases	5.3	%	5.8	%	5.8	%
Finance leases	14.3	%	14.3	%	14.3	%

Annual maturity analysis

The future annual maturity of lease payments as of December 31, 2021 for the above lease obligations was:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Maturity of lease liabilities	Operating Leases (1)		Finance Leases (2)		Total
2022	$	—	$	4	$	4
2023	1		4		5
2024	—		4		4
2025	—		5		5
2026	—		5		5
Remainder	5		22		27
Total lease payments	6		44		50
Less: Interest (3)	(2)		(20)		(22)
Present value of lease liabilities (4)	$	4	$	24	$	28

(1) Operating lease payments include $2 million related to options to extend lease terms that are reasonably certain of being exercised.

(2) Includes $24 million in principal and excludes $7 million in executory costs.

(3) Calculated using the interest rate for each lease.

(4) Includes the current portion of $1 million for the finance lease.

Lessor accounting

We have certain transportation and terminaling services agreements with related parties entered into prior to the adoption date of January 1, 2019 that are considered operating leases and include both a lease component and an implied operation and maintenance service component (“non-lease service component”). Certain of these agreements were entered into for terms of ten years with the option to extend for two additional terms of five years each. One of these contracts was amended to include an option for the lessee to extend for a fourteen-month term prior to the original extension options. However, it is reasonably certain that the original extension options of the two additional five-year terms will not be exercised for this contract. Further, we have agreements with an initial term of ten years with the option to extend for up to ten additional one-year terms. As is the case with certain of our agreements, when the renewal options are reasonably certain to be exercised, the payments are included in the future maturity of lease payments. Our transportation, terminaling and storage services revenue and lease revenue from related parties for the years ended December 31, 2021, 2020 and 2019 are disclosed in Note 12 — Revenue Recognition.

Our risk management strategy for the residual assets is mitigated by the long-term nature of the underlying assets and the long-term nature of our lease agreements.

Significant assumptions and judgments

Lease and non-lease components. Certain of our revenues are accounted for under the lease standard, as the underlying contracts convey the right to control the use of the identified asset for a period of time. We allocate the arrangement consideration between the lease components that fall within the scope of the lease standard and any non-lease service components within the scope of the revenue standard based on the relative stand-alone selling price of each component. See Note 12 — Revenue Recognition for additional information regarding the allocation of the consideration in a contract between the lease and non-lease service components.

Annual maturity analysis

As of December 31, 2021, future annual maturity of lease payments to be received under the contract terms of these operating leases, which includes only the lease components of these leases, was estimated to be:


Maturity of lease payments	Operating leases (1)
2022	$	56
2023	56
2024	56
2025	56
2026	56
Remainder	394
Total lease payments	$	674

(1) Operating lease payments include $366 million related to options to extend lease terms that are reasonably certain of being exercised.

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other

As of December 31, 2021 and 2020, we had short-term payment obligations relating to capital expenditures each totaling $1 million, respectively. These represent unconditional payment obligations to vendors for products and services delivered in connection with capital projects.

10. Accumulated Other Comprehensive Loss

As a result of the transactions contemplated by the June 2019 Acquisition, we recorded an accumulated other comprehensive loss related to pension and other post-retirement benefits provided by Explorer and Colonial to their employees. We are not a sponsor of these benefits plans. The June 2019 Acquisition is accounted for as a transaction between entities under common control on a prospective basis, and we have recorded the acquisition on our consolidated balance sheet at SPLC’s historical basis, which included accumulated other comprehensive loss. In 2021, we recorded $1 million in other comprehensive gain, and in 2020 and 2019, we recorded $1 million and $2 million, respectively, in other comprehensive loss, related to remeasurements related to these pension and other post-retirement benefits.

11. (Deficit) Equity

General Partner and IDR Restructuring

Prior to April 1, 2020, our capital accounts were comprised of a 2% general partner interest and 98% limited partner interests. On April 1, 2020, in connection with the April 2020 Transaction, we closed on 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. As a result, 4,761,012 general partner units and the IDRs were canceled and are no longer outstanding, and therefore, no longer participate in distributions of cash from the Partnership. Because the transaction was among entities under common control, our general partner’s negative equity balance of $4 billion at April 1, 2020 was transferred to SPLC’s equity accounts, allocated between its holdings of common units and preferred units, based on the relative fair value of the common units and preferred units issued as consideration in the April 2020 Transaction.

Shelf Registrations

We have a universal shelf registration statement on Form S-3 on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of common units and partnership securities representing limited partner units.

Units Outstanding

The changes in the number of units outstanding from December 31, 2019 through December 31, 2021 are as follows:


(in units)	SPLC Preferred	Public Common	SPLC Common	General Partner
Balance as of December 31, 2019	—	123,832,233	109,457,304	4,761,012
April 2020 Acquisition	50,782,904	—	160,000,000	(4,761,012)
Balance as of December 31, 2020	50,782,904	123,832,233	269,457,304	—
2021 activities	—	—	—	—
Balance as of December 31, 2021	50,782,904	123,832,233	269,457,304	—

Common units

The common units represent limited partner interests in us. The holders of common units, both public and SPLC, are entitled to participate in partnership distributions and have limited rights of ownership as provided for under the Second Amended and Restated Partnership Agreement.

As of both December 31, 2021 and 2020, we had 393,289,537 common units outstanding, of which 123,832,233 were publicly owned. SPLC owned 269,457,304 common units representing an aggregate 68.5% limited partner interest in us.

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Series A Preferred Units

As of both December 31, 2021 and 2020, we had 50,782,904 preferred units outstanding. On April 1, 2020, as partial consideration for the April 2020 Transaction, we issued 50,782,904 Series A Preferred Units to SPLC at a price of $23.63 per preferred unit. The Series A Preferred Units rank senior to all common units with respect to distribution rights and rights upon liquidation. The Series A Preferred Units have voting rights, distribution rights and certain redemption rights, and are also convertible (at the option of the Partnership and at the option of the holder, in each case under certain circumstances) and are otherwise subject to the terms and conditions as set forth in the Second Amended and Restated Partnership Agreement. We classified the Series A Preferred Units as permanent equity since they are not redeemable for cash or other assets 1) at a fixed or determinable price on a fixed or determinable date; 2) at the option of the holder; or 3) upon the occurrence of an event that is not solely within the control of the issuer.

Conversion

At the option of Series A Preferred Unitholders. Beginning with the earlier of (1) January 1, 2022 and (2) immediately prior to the liquidation of the Partnership, the Series A Preferred Units are convertible by the preferred unitholders, at the preferred unitholders’ option, into common units on a one-for-one basis, adjusted to give effect to any accrued and unpaid distributions on the applicable preferred units.

At the option of the Partnership. The Partnership shall have the right to convert the Series A Preferred Units on a one-for-one basis, adjusted to give effect to any accrued and unpaid distributions on the applicable Series A Preferred Units, into common units at any time from and after January 1, 2023, if the closing price of the common units is greater than $33.082 per unit (140% of the Series A Preferred Unit Issue Price (as defined in the Second Amended and Restated Partnership Agreement)) for at least 20 trading days (whether or not consecutive) in a period of 30 consecutive trading days, including the last trading day of such 30 trading day period, ending on and including the trading day immediately preceding the date on which the Partnership sends notice to the holders of Series A Preferred Units of its election to convert such Series A Preferred Units. The conversion rate for the Series A Preferred Units shall be the quotient of (a) the sum of (i) $23.63, plus (ii) any unpaid cash distributions on the applicable Series A Preferred Units, divided by (b) $23.63.

Voting

The Series A Preferred Units are entitled to vote on an as-converted basis with the common units and have certain other class voting rights with respect to any amendment to the Second Amended and Restated Partnership Agreement. In the event of any liquidation of the Partnership, the Series A Preferred Units are entitled to receive, out of the assets of the Partnership available for distribution to the partners or any assignees, prior and in preference to any distribution of any assets of any junior securities, the value in each holder’s capital account in respect of such Series A Preferred Units.

Change of Control

Upon the occurrence of certain events involving a change of control in which more than 90% of the consideration payable to the holders of the common units is payable in cash, the Series A Preferred Units will automatically convert into common units at the then-applicable conversion rate. Upon the occurrence of certain other events involving a change of control, the holders of the Series A Preferred Units may elect, among other potential elections, to convert the Series A Preferred Units to common units at the then-applicable conversion rate.

Special Distribution

Each Series A Preferred Unit has the right to share in any special distributions by the Partnership of cash, securities or other property pro rata with the common units or any other securities, on an as-converted basis, provided that special distributions shall not include regular quarterly distributions paid in the normal course of business on the common units.

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Distributions to our Unitholders

In connection with the April 2020 Transaction, commencing with the quarter ending June 30, 2020, the holders of the Series A Preferred Units are entitled to cumulative quarterly distributions at a rate of $0.2363 per Series A Preferred Unit, payable quarterly in arrears no later than 60 days after the end of the applicable quarter. The Partnership will not be entitled to pay any distributions on any junior securities, including any of the common units, prior to paying the quarterly distribution payable to the Series A Preferred Units, including any previously accrued and unpaid distributions. For the year ended December 31, 2021, the aggregate and per unit amounts of cumulative preferred distributions paid were $48 million and $0.9452, respectively. For the year ended December 31, 2020, the aggregate and per unit amounts of cumulative preferred distributions paid were $36 million and $0.7089, respectively.

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 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 and ending with the distribution made with respect to the first quarter of 2021. See Note 4 — Related Party Transactions for terms of the Second Amended and Restated Partnership Agreement.

Under the Second Amendment, our general partner elected to waive $50 million of distributions with respect to the IDRs in 2019 to be used for future investment by the Partnership. See Note 4 — Related Party Transactions for terms of the Second Amendment.

The following table details the distributions declared and/or paid for the periods presented:


Date Paid or to be Paid	Three Months Ended	Public Common		SPLC Preferred		SPLC Common		General Partner						Distributions per Limited Partner Unit
								IDRs		2%		Total

		(in millions, except per unit amounts)
February 14, 2019	December 31, 2018	$	49	$	—	$	40	$	37	$	3	$	129	$	0.40000
May 15, 2019	March 31, 2019 (1)	51		—		42		23		3		119		0.41500
August 14, 2019	June 30, 2019 (1)	53		—		47		28		3		131		0.43000
November 14, 2019	September 30, 2019 (1)	56		—		48		33		3		140		0.44500
February 14, 2020	December 31, 2019	57		—		50		52		3		162		0.46000
May 15, 2020	March 31, 2020	57		—		50		52 (3)		3 (4)		162		0.46000
August 14, 2020	June 30, 2020 (2)	57		12		104		—		—		173		0.46000
November 13, 2020	September 30, 2020 (2)	57		12		104		—		—		173		0.46000
February 12, 2021	December 31, 2020 (2)	57		12		104		—		—		173		0.46000
May 14, 2021	March 31, 2021(2)	57		12		104		—		—		173		0.46000
August 13, 2021	June 30, 2021	37		12		81		—		—		130		0.30000
November 12, 2021	September 30, 2021	37		12		81		—		—		130		0.30000
February 11, 2022	December 31, 2021 (5)	37		12		81		—		—		130		0.30000

(1) Includes the impact of waived distributions to the holders of IDRs with respect to the Second Amendment as described above.

(2) Includes the impact of waived distributions to SPLC with respect to the April 2020 Transaction as described above.

(3) This amount represents the Final IDR Payment (as defined in the Partnership Interests Restructuring Agreement) to which our general partner (or its assignee) was entitled pursuant to the Partnership Interests Restructuring Agreement. Also pursuant to the Partnership Interests Restructuring Agreement, our general partner agreed (on its own behalf and on behalf of its assignees) to waive any distributions that it would otherwise be entitled to receive with respect to the newly-issued 160 million common units that it received in the April 2020 Transaction for the quarter in which it receives the Final IDR Payment. Our general partner is not entitled to any further payments with respect to the IDRs, as they were cancelled as a part of the April 2020 Transaction.

(4) This amount represents the final distribution payment on the 2% economic general partner interest. Our general partner is not entitled to any further payments with respect to the economic general partner interest, as it was converted into a non-economic general partner interest as a part of the April 2020 Transaction.

(5) See Note 16 — Subsequent Event(s) for additional information.

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Distributions to Noncontrolling Interests

Beginning with the third quarter of 2021, there is no distribution to SPLC for its noncontrolling interest in Zydeco as a result of the May 2021 Transaction. Refer to Note 3 — Acquisitions and Other Transactions for additional information. Distributions to SPLC for its noncontrolling interest in Zydeco were less than $1 million in 2021, and were $5 million and $4 million in 2020 and 2019, respectively.

Distributions to GEL for its noncontrolling interest in Odyssey were $11 million, $11 million and $13 million in 2021, 2020 and 2019, respectively.

See Note 4 — Related Party Transactions for additional details.

12. Revenue Recognition

The revenue standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The revenue standard requires entities to recognize revenue through the application of a five-step model, which includes: identification of the contract; identification of the performance obligations; determination of the transaction price; allocation of the transaction price to the performance obligations; and recognition of revenue as the entity satisfies the performance obligations.

Our revenues are primarily generated from the transportation, terminaling and storage of crude oil, refinery gas and refined petroleum products through our pipelines, terminals, storage tanks, docks, truck and rail racks. To identify the performance obligations, we considered all the products or services promised in the contracts with customers, whether explicitly stated or implied based on customary business practices. Revenue is recognized when each performance obligation is satisfied under the terms of the contract.

Each barrel of product transported or day of services provided is considered a distinct service that represents a performance obligation that would be satisfied over time if it were accounted for separately. The services provided over the contract period are a series of distinct services that are substantially the same, have the same pattern of transfer to the customer, and, therefore, qualify as a single performance obligation. Since the customer simultaneously receives and consumes the benefits of services, we recognize revenue over time based on a measure of progress of volumes transported for transportation services contracts or number of days elapsed for storage and terminaling services contracts.

Product revenue related to allowance oil sales is recognized at the point in time when the control of the oil transfers to the customer.

For all performance obligations, payment is typically due in full within 30 days of the invoice date.

Disaggregation of Revenue

The following table provides information about disaggregated revenue by service type and customer type:


	2021		2020		2019
Transportation services revenue – third parties	$	142	$	114	$	134
Transportation services revenue – related parties (1)	174		164		210
Storage services revenue – third parties	9		9		9
Storage services revenue – related parties	7		8		7
Terminaling services revenue – related parties (2)	120		103		47
Terminaling services revenue – major maintenance service – related parties (3)	11		7		—
Product revenue – third parties (4)	1		—		5
Product revenue – related parties (4)	36		19		35
Total Topic 606 revenue	500		424		447
Lease revenue – related parties	56		57		56
Total revenue	$	556	$	481	$	503

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Transportation services revenue – related parties for each of 2021, 2020 and 2019 includes $5 million of non-lease service component in our transportation services contract.

(2) Terminaling services revenue – related parties is comprised of the service components in our terminaling services contracts, including the operation and maintenance service components related to the Norco Assets in connection with the April 2020 Transaction. See Note 4 – Related Party Transactions for additional details.

(3) Terminaling services revenue – major maintenance service – related parties is comprised of the service components related to providing required major maintenance to the Norco Assets in connection with the April 2020 Transaction. See Note 4 – Related Party Transactions for additional details.

(4) Product revenue is comprised of allowance oil sales.

Lease revenue

Certain of our long-term transportation and terminaling services contracts with related parties are accounted for as operating leases. These agreements have both lease and non-lease service components. We allocate the arrangement consideration between the lease components and any non-lease service components based on the relative stand-alone selling price of each component. We estimate the stand-alone selling price of the lease and non-lease service components based on an analysis of service-related and lease-related costs for each contract, adjusted for a representative profit margin. The contracts have a minimum fixed monthly payment for both the lease and non-lease service components. We present the non-lease service components under the revenue standard within Transportation, terminaling and storage services – related parties in the consolidated statements of income.

Revenues from the lease components of these agreements are recorded within Lease revenue – related parties in the consolidated statements of income. Some of these agreements were each entered into for terms of ten years, with the option for the lessee to extend for two additional five-year terms. One of these contracts was amended to include an option for the lessee to extend for a fourteen-month term prior to the original extension options. However, it is reasonably certain that the original extension options of the two additional five-year terms will not be exercised for this contract. Further, we have agreements with initial terms of ten years with the option for the lessee to extend for up to ten additional one-year terms. As of December 31, 2021, future minimum payments of both the lease and non-lease service components to be received under the ten-year contract term of these operating leases were estimated to be:


	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating leases	$	617	$	109	$	218	$	218	$	72

Transportation services revenue

We have both long-term transportation contracts and month-to-month contracts for spot shippers that make nominations on our pipelines. Some of the long-term contracts entitle the customer to a specified amount of guaranteed capacity on the pipeline. Transportation services are charged at a per barrel rate or other applicable unit of measure. We apply the allocation exception guidance for variable consideration related to market indexing for long-term transportation contracts because (a) the variable payment relates specifically to our efforts to transfer the distinct service and (b) we allocate the variable amount of consideration entirely to the distinct service, which is consistent with the allocation objective. Except for guaranteed capacity payments as discussed below, transportation services are billed monthly as services are rendered.

Our contracts and tariffs contain terms for the customer to reimburse us for losses from evaporation or other loss in transit in the form of allowance oil. Allowance oil represents the net difference between the tariff PLA volumes and the actual volumetric losses. We obtain control of the excess oil not lost during transportation, if any. Under the revenue standard, we include the excess oil retained during the period, if any, as non-cash consideration and include this amount in the transaction price for transportation services on a net basis. Our allowance oil revenue is valued at the average market price of the relevant type of crude oil during the month product was transported. Gains from pipeline operations that relate to allowance oil are recorded in Operations and maintenance expenses in the accompanying consolidated statements of income.

Storage and terminaling services revenue

Storage and terminaling services are provided under short-term and long-term contracts, with a fixed price per month for committed storage and terminaling capacity, or under a monthly spot-rate for uncommitted storage or terminaling. Since the customer simultaneously receives and consumes the benefits of services, we recognize revenue over time based on the number

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of days elapsed. We apply the allocation exception guidance for variable consideration related to market indexing for long-term contracts because (a) the variable payment relates specifically to our efforts to transfer the distinct service and (b) we allocate the variable amount of consideration entirely to the distinct service, which is consistent with the allocation objective. Storage and terminaling services are billed monthly as services are rendered.

Terminaling services revenue - Norco Assets

In April 2020, the Partnership closed the April 2020 Transaction pursuant to which the Norco Assets were transferred from SOPUS and Shell Chemical to Triton. In connection with closing the April 2020 Transaction, Triton entered into terminaling service agreements with SOPUS and Shell Chemical related to the Norco Assets. These terminaling service agreements were entered into for an initial term of fifteen years, with the option to extend for additional five-year terms. The transfer of the Norco Assets, combined with the terminaling services agreements, were accounted for as a failed sale leaseback under the lease standard. The Partnership receives an annual net payment of $140 million, which is the total annual payment pursuant to the terminaling service agreements of $151 million, less $11 million, which primarily represents the allocated utility costs from SOPUS related to the Norco Assets. Both payments are subject to annual CPI adjustments pursuant to an inflation escalation clause in each of the agreements, which provides that the annual payments increase on July 1 of each year commencing on July 1, 2021. On July 1, 2021, the annual payments were escalated by applying a CPI adjustment of 4.86%. After such escalation, the Partnership receives an annual net payment of $147 million, which is the total annual payment of $158 million, less $11 million related to the allocated utility costs from SOPUS.

These agreements have components related to financing receivables, for which the interest income is recognized in the consolidated statements of income and principal payments are recognized as a reduction to the financing receivables in the consolidated balance sheet. Revenue related to the operation and maintenance service components and major maintenance service components are presented within Transportation, terminaling and storage services – related parties in the consolidated statements of income.

The operation and maintenance service components consist of the Partnership’s obligation to operate the Norco Assets over the life of the agreements. It is considered a distinct service that represents a performance obligation that would be satisfied over time if it were accounted for separately. The services provided over the contract period are a series of distinct services that are substantially the same, have the same pattern of transfer to the customer, and, therefore, qualify as a single performance obligation. Since the customer simultaneously receives and consumes the benefits of services, we recognize revenue over time based on the number of days elapsed.

The major maintenance service components consist of the Partnership’s obligation to provide major maintenance on the Norco Assets such that the current capacity available to the customers is maintained over the life of the agreements. It is considered a distinct service that represents a performance obligation that would be satisfied over time if it were accounted for separately. The services provided over the contract period are a series of distinct services that are substantially the same, have the same pattern of transfer to the customer, and, therefore, qualify as a single performance obligation. Since the customer simultaneously receives and consumes the benefits of services, we recognize revenue over time using the input method (cost-to-cost method) based on the ratio of actual major maintenance costs incurred to date to the total forecasted major maintenance costs over the contract term.

We allocate the arrangement consideration between the components based on the relative stand-alone selling price of each component in accordance with the revenue standard. The Partnership established the stand-alone selling price for the financing components based off an expected return on the assets being financed. The Partnership established the stand-alone selling price for the service components using expected cost-plus margin approach based on the Partnership’s forecasted costs of satisfying the performance obligation plus an appropriate margin for the service. The key assumptions include forecasts of the future operation and maintenance costs and major maintenance costs and the expected margin with respect to the service components and the expected return on the assets with respect to the financing components. Index-based inflation escalations represent variable consideration. In the period when index-based inflation escalations become effective, such escalations will be allocated based on the relative standalone selling prices established at the inception of the terminaling service agreements.

In the third quarter of 2021, a force majeure was declared under the terminaling service agreements as a result of Hurricane Ida when the Norco Assets were shut down following the hurricane. This event resulted in a combined decrease to terminaling service revenue and interest income of approximately $3 million for the year ended December 31, 2021.

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Deferred revenue

Our FERC-approved transportation services agreements on Zydeco 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 (i.e., deficiency payments) 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, a contract liability under the revenue standard. 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.

Under the revenue standard, we are required to estimate the likelihood that unused volumes will be shipped or forfeited at each reporting period based on additional data that becomes available and only to the extent that it is probable that a significant reversal of revenue will not occur. In some cases, this estimate could result in the earlier recognition of revenue.

We also recognize deferred revenue on the major maintenance service components of the terminaling service agreement related to Norco Assets when we invoice SOPUS and Shell Chemical for the minimum volume commitment. Please refer to the Terminaling services revenues - Norco Assets section above for additional revenue recognition discussion.

Reimbursements from customers

Under certain transportation, terminaling and storage service contracts, we receive reimbursements from customers to recover costs of construction, maintenance or operating costs either under a tariff surcharge per volume shipped or under separate reimbursement payments. Because we consider these amounts as consideration from customers associated with ongoing services to be provided to customers, we defer these payments in deferred revenue and recognize amounts in revenue over the life of the associated revenue contract as performance obligations are satisfied under the contract. We consider these payments to be revenue because control of the long-lived assets does not transfer to our customer upon completion. Our financial statements were not materially impacted by adoption of the revenue standard related to reimbursements from customers.

Product revenue

We generate revenue by selling accumulated allowance oil inventory to customers. The sale of allowance oil is recorded as product revenue, with specific cost based on a weighted average price per barrel recorded as cost of product sold.

Joint tariff

Under a certain joint tariff, we record revenues on a gross basis within Transportation, terminaling and storage services – third parties or related parties because we control the transportation service before it is transferred to the customer and are therefore the principal.

Contract Balances

We perform our obligations under a contract with a customer by providing services in exchange for consideration from the customer. The timing of our performance may differ from the timing of the customer’s payment, which results in the recognition of a contract asset or a contract liability. We recognize a contract asset when we transfer goods or services to a customer and contractually bill an amount which is less than the revenue allocated to the related performance obligation. We recognize deferred revenue (contract liability) when the customer’s payment of consideration precedes our performance. The following table provides information about receivables and contract liabilities from contracts with customers:


	January 1, 2021		December 31, 2021
Receivables from contracts with customers – third parties	$	19	$	13
Receivables from contracts with customers – related parties	18		35
Contract Assets - related parties	233		218
Deferred revenue – third parties	4		2
Deferred revenue – related parties (1)	19		31

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	January 1, 2020		December 31, 2020
Receivables from contracts with customers – third parties	$	11	$	19
Receivables from contracts with customers – related parties	24		18
Contract Assets - related parties	—		233
Deferred revenue – third parties	—		4
Deferred revenue – related parties (1)	—		19

(1) Deferred revenue - related parties is related to deficiency credits from certain minimum volume commitment contracts and certain components of our terminaling service contracts on the Norco Assets.

In connection with the April 2020 Transaction, we also recorded contract assets based on the difference between the consideration allocated to the Norco Transaction and the recognized financing receivables. The contract assets represent the excess of the fair value embedded within the terminaling services agreements transferred by the Partnership to SOPUS and Shell Chemical as part of entering into the terminaling services agreements. The contract assets balance is amortized in a pattern consistent with the recognition of revenue on the service components of the contract. The portion of the contract assets related to operations and maintenance is amortized on a straight-line basis over a fifteen-year period, and the portion related to major maintenance is amortized based on the ratio of actual major maintenance costs incurred to the total projected major maintenance costs over the fifteen year term. We recorded amortization as a component of Transportation, terminaling and storage services – related parties of $15 million and $11 million for the year ended December 31, 2021 and 2020, respectively. We had $218 million and $233 million contract assets recognized from the costs to obtain or fulfill a contract as of December 31, 2021 and 2020, respectively.

The estimated future amortization related to the contract assets for the next five years is as follows:


	2022		2023		2024		2025		2026
Amortization	$	17	$	17	$	18	$	19	$	16

Significant changes in the deferred revenue balances with customers during the period are as follows:


	December 31, 2020		Additions (1)		Reductions (2)		December 31, 2021
Deferred revenue – third parties	$	4	$	4	$	(6)	$	2
Deferred revenue – related parties	19		27		(15)		31

(1) Deferred revenue additions resulted from $21 million deficiency payments from minimum volume commitment contracts and $10 million of deferred revenue related to the major maintenance service components of our terminaling service contracts on the Norco Assets.

(2) Deferred revenue reductions resulted from revenue earned through the actual or estimated use and expiration of deficiency credits.


	December 31, 2019		Additions (1)		Reductions (2)		December 31, 2020
Deferred revenue – third parties	$	—	$	8	$	(4)	$	4
Deferred revenue – related parties	—		21		(2)		19

(1) Deferred revenue additions resulted from $24 million deficiency payments from minimum volume commitment contracts and $5 million of deferred revenue related to the major maintenance service components of our terminaling service contracts on the Norco Assets.

(2) Deferred revenue reductions resulted from revenue earned through the actual or estimated use and expiration of deficiency credits.

Remaining Performance Obligations

The following table includes revenue expected to be recognized in the future related to performance obligations exceeding one year of their initial terms that are unsatisfied or partially unsatisfied as of December 31, 2021:

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Total		2022		2023		2024		2025		2026 and beyond
Revenue expected to be recognized on multi-year committed shipper transportation contracts	$	410	$	63	$	63	$	57	$	50	$	177
Revenue expected to be recognized on other multi-year transportation service contracts (1)	29		6		6		6		5		6
Revenue expected to be recognized on multi-year storage service contracts	18		10		4		4		—		—
Revenue expected to be recognized on multi-year terminaling service contracts (1)	281		47		47		47		48		92
Revenue expected to be recognized on multi-year operation and major maintenance terminaling service contracts(2)	1,481		113		119		123		127		999
Total	$	2,219	$	239	$	239	$	237	$	230	$	1,274

(1) Relates to the non-lease service components of certain of our long-term transportation and terminaling service contracts which are accounted for as operating leases.

(2) Relates to the operation and maintenance service components and the major maintenance service components of our terminaling service contracts on the Norco Assets in connection with the April 2020 Transaction.

As an exemption under the revenue standard, we do not disclose the amount of remaining performance obligations for contracts with an original expected duration of one year or less or for variable consideration that is allocated entirely to a wholly unsatisfied promise to transfer a distinct service that forms part of a single performance obligation.

13. Net Income Per Limited Partner Unit

Net income per unit applicable to common limited partner units is computed by dividing the respective limited partners’ interest in net income attributable to the Partnership for the period by the weighted average number of common units outstanding for the period. Prior to April 1, 2020, the classes of participating securities included common units, general partner units and IDRs. Because we had more than one class of participating securities, we used the two-class method when calculating the net income per unit applicable to limited partners. Effective April 1, 2020, the classes of participating securities included only common units, as the general partner units and the IDRs were eliminated and the Series A Preferred Units are not considered a participating security. See Note 11 – (Deficit) Equity for a discussion of the elimination of our general partner’s IDRs and 2% economic interest effective April 1, 2020. For the year ended December 31, 2021 and 2020, our Series A Preferred Units were dilutive to net income per limited partner unit.

Net income earned by the Partnership is allocated between the classes of participating securities in accordance with the terms of our partnership agreement as in effect on the date such calculation is performed, after giving effect to priority income allocations to the holders of the Series A Preferred Units if applicable. Earnings are allocated based on actual cash distributions declared to our unitholders, including those attributable to the IDRs prior to the second quarter of 2020, if applicable. To the extent net income attributable to the Partnership exceeds or is less than cash distributions, this difference is allocated based on the unitholders’ respective ownership percentages. For the diluted net income per limited partner unit calculation under the Second Amended and Restated Partnership Agreement, the Series A Preferred Units are assumed to be converted at the beginning of the period into common limited partner units on a one-for-one basis, and the distribution formula for available cash is recalculated using the available cash amount increased only for the preferred distributions, which would have been attributable to the common units after conversion.

The following tables show the allocation of net income attributable to the Partnership to arrive at net income per limited partner unit:

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	2021 (1)	2020		2019
Net income	*	$	556	$	546
Less:
Net income attributable to noncontrolling interests	*	13		18
Net income attributable to the Partnership	*	543		528
Less:
General partner’s distribution declared (2)	*	55		148
Preferred unitholder’s interest in net income	*	36		—
Limited partners’ distribution declared on common units (3)	*	590		404
Distributions in excess of income	*	$	(138)	$	(24)

(1) Effective April 1, 2020, the classes of participating securities included only common units, as the general partner units and the IDRs were eliminated and the Series A Preferred Units are not considered a participating security. Therefore, the allocation of net income attributable to the Partnership to arrive at net income per limited partner unit is not applicable for the year ended December 31, 2021.

(2) For 2019, this includes the impact of waived distributions to the holders of the IDRs. See Note 4 — Related Party Transactions for additional information.

(3) For 2020, this includes the impact of waived distributions to SPLC. See Note 4 — Related Party Transactions for additional information.


		2021
		Limited Partners’ Common Units

	(in millions of dollars, except per unit data)
Net income attributable to the Partnership’s common unitholders (basic)		$	508
Dilutive effect of preferred units		48
Net income attributable to the Partnership’s common unitholders (diluted)		$	556

Weighted average units outstanding - Basic		393.3
Dilutive effect of preferred units		50.8
Weighted average units outstanding - Diluted		444.1

Net income per limited partner unit:
Basic		$	1.29
Diluted		$	1.25

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	2020
	General Partner		Limited Partners’ Common Units		Total

	(in millions of dollars, except per unit data)
Distributions declared (1)	$	55	$	590	$	645
Distributions in excess of income	—		(138)		(138)
Net income attributable to the Partnership’s common unitholders (basic)	$	55	$	452	$	507
Dilutive effect of preferred units			36
Net income attributable to the Partnership’s common unitholders (diluted)			$	488

Weighted average units outstanding - Basic			353.5
Dilutive effect of preferred units			38.2
Weighted average units outstanding - Dilutive			391.7
Net income per limited partner unit:
Basic			$	1.28
Diluted			$	1.25

(1) This includes the impact of waived distributions to SPLC. See Note 4 — Related Party Transactions for additional information.


	2019
	General Partner		Limited Partners’ Common Units		Total

	(in millions of dollars, except per unit data)
Distributions declared (1)	$	148	$	404	$	552
Distributions in excess of income	(1)		(23)		(24)
Net income attributable to the Partnership	$	147	$	381	$	528
Weighted average units outstanding:
Basic and diluted			229.2
Net income per limited partner unit:
Basic and diluted			$	1.66

(1) This includes the impact of waived distributions to the holders of the IDRs. See Note 4 — Related Party Transactions for additional information.

14. Transactions with Major Customers and Concentration of Credit Risk

Our Parent and its affiliates accounted for approximately 73%, 75% and 70% of our total revenues for 2021, 2020 and 2019, respectively. There is no third-party customer that accounted for a 10% or greater share of consolidated revenues or net accounts receivable for the year ended December 31, 2021.

We have a concentration of revenues and trade receivables due 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. These concentrations of customers may impact our overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory, regional and other factors. We are potentially exposed to concentration of credit risk primarily through our accounts receivable with our Parent. These receivables have payment terms of 30 days or less, and there has been no history of collectability issues. We monitor the creditworthiness of third-party major customers. We manage our exposure to credit risk through credit analysis, credit limit approvals and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. As of December 31, 2021 and 2020, there were no such arrangements with customers.

We have concentrated credit risk for cash by maintaining deposits in a major bank, which may at times exceed amounts covered by insurance provided by the United States Federal Deposit Insurance Corporation (“FDIC”). We monitor the financial health of the bank, have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk. As

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of December 31, 2021 and 2020, we had approximately $360 million and $320 million, respectively, in cash and cash equivalents in excess of FDIC limits.

15. Commitments and Contingencies

Environmental Matters

We are subject to federal, state and local environmental laws and regulations. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are probable and reasonably estimable. For both December 31, 2021 and 2020, these costs and any related liabilities are not material.

Legal Proceedings

We are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results or cash flows.

Other Commitments

Odyssey entered into a tie-in agreement effective January 2012 with a third party, which allowed producers to install the tie-in connection facilities and tying into the system. The tie in agreement will terminate in the fourth quarter of 2022 because the third party elected not to participate in the project to re-reroute the Odyssey pipeline around the MP289C Platform.

On September 1, 2016, which is the in-service date of the capital lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective. The tariff will be reviewed annually and the rate updated based on the FERC’s indexing adjustment to rates effective July 1 of each year. Effective July 1, 2021, there was an approximate 1% decrease to this rate based on the FERC’s indexing adjustment. The initial term of the agreement is ten years with automatic one-year renewal terms with the option to cancel prior to each renewal period.

We hold cancellable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Obligations under these easements are not material to the results of our operations.

16. Subsequent Event(s)

We have evaluated events that occurred after December 31, 2021 through the issuance of these consolidated financial statements. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the consolidated financial statements and accompanying notes.

Distribution

On January 19, 2022, the Board declared a cash distribution of $0.3000 per limited partner unit and $0.2363 per limited partner preferred unit for the three months ended December 31, 2021. The distribution was paid on February 11, 2022 to unitholders of record as of February 1, 2022.

Take Private Proposal

On February 11, 2022, the Board received a non-binding, preliminary proposal letter from SPLC to acquire all of the Partnership's issued and outstanding common units not already owned by SPLC or its affiliates at a value of $12.89 per each issued and outstanding publicly-held common units of the Partnership (the “Proposal”). The Board has appointed the conflicts committee to review, evaluate and negotiate the Proposal.

The proposed transaction is subject to a number of contingencies, including the approval of the Board, the negotiation of a definitive agreement concerning the transaction, and the satisfaction of conditions to the consummation of a transaction set forth in any such definitive agreement. There can be no assurance that such definitive agreement will be executed or that any transaction will be consummated on the terms described above or at all.

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Repayment of Debt

On February 16, 2022, we used excess cash to repay $150 million of borrowings under the Five Year Revolver due December 2022.

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Management of the Partnership, with the participation of its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the annual period. Our disclosure controls and procedures have been designed to provide reasonable assurance that the information required to be disclosed in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on their evaluation, the Partnership’s Chief Executive Officer and Chief Financial Officer have concluded that the Partnership’s disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Exchange Act), were effective at the reasonable assurance level as of the end of the annual period covered by this report.

Management’s Report on Internal Control over Financial Reporting

Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting. The Partnership’s internal control system is designed to provide reasonable assurance to the Partnership’s management and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management of the Partnership assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2021.

The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2021 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included in Part II, Item 8. Financial Statements and Supplementary Data of this report.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. OTHER INFORMATION

Disclosures Required Pursuant to Section 13(r) of the Securities Exchange Act of 1934

In accordance with our General Business Principles and Code of Conduct, Shell Midstream Partners, L.P. seeks to comply with all applicable international trade laws, including applicable sanctions and embargoes.

Under the Iran Threat Reduction and Syria Human Rights Act of 2012, and Section 13(r) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities during the period covered by the report. Because the U.S. Securities and Exchange Commission defines the term “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us.

The activities listed below have been conducted outside the United States by non-U.S. affiliates of Shell plc that may be deemed to be under common control with us. The disclosure does not relate to any activities conducted directly by us, our subsidiaries or our general partner and does not involve our or our general partner’s management.

For purposes of this disclosure, we refer to Shell plc and its subsidiaries, other than us, our subsidiaries, our general partner and Shell Midstream LP Holdings LLC, as the “Shell Group.” When not specifically identified, references to actions taken by the

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Shell Group mean actions taken by the applicable Shell Group company. None of the payments disclosed below were made in U.S. dollars, nor are any of the balances disclosed below held in U.S. dollars; however, for disclosure purposes, all have been converted into U.S. dollars at the appropriate exchange rate. We do not believe that any of the transactions or activities listed below violated U.S. sanctions.

In 2021, Saba & Co. Intellectual Property s.a.l (Offshore) (Saba & Co.) paid $2,288 for trademark registration fees in Iran on the Shell Group’s behalf to the Iranian Intellectual Property Office (IIPO). In addition, Saba & Co. billed the Shell Group $4,540 for professional, translation and publication services related to the Shell Group’s trademark registration. There was no gross revenue or net profit associated with these transactions.

During 2021, the Shell Group paid $3,639 for the clearance of overflight permits for Shell Group aircraft over Iranian airspace to Civil Aviation Organization (Iran). There was no gross revenue or net profit associated with these transactions. On occasion, Shell Group aircraft may be routed over Iran, and, therefore, these payments may continue in the future.

The Shell Group maintains accounts with Karafarin Bank where its cash deposits (balance of $5,628,256 at December 31, 2021) generated non-taxable interest income of $64,907 in the fourth quarter of 2021 (total of $249,542 interest income in 2021). In addition, the Shell Group paid $1 for bank charges in 2021. As the accounts with Karafarin Bank will be maintained by the Shell Group for the foreseeable future, we expect that receipt of non-taxable interest income and payment of bank charges by the Shell Group will continue in the future.

Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management of Shell Midstream Partners, L.P.

We are managed by the board of directors (the “Board”) and executive officers of Shell Midstream Partners GP LLC, our general partner. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. SPLC owns all of the membership interests in our general partner. Our general partner has a board of directors, and our common unitholders are not entitled to elect the directors or to participate directly or indirectly in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

SPLC appointed all eight directors on our general partner’s Board. We have three directors who have been determined by the Board to be independent under the independence standards of the New York Stock Exchange (“NYSE”).

We do not have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct operations, whether through directly hiring employees or by obtaining services of personnel employed by Shell, SPLC or third parties, but we sometimes refer to these individuals as our employees because they provide services directly to us.

Directors and Executive Officers of Shell Midstream Partners GP LLC

Directors are elected by the sole member of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the Board. The following table shows information for the directors and executive officers of our general partner as of February 24, 2022.

Name

Age

Position with Shell Midstream Partners GP LLC

Paul R. A. Goodfellow

Director, Chairman of the Board of Directors

Steven C. Ledbetter (1)

Director, Chief Executive Officer and President

Shawn J. Carsten

Director, Vice President and Chief Financial Officer

Lori M. Muratta

Vice President, General Counsel and Secretary

Gregory T. Mouras (2)

Vice President, Operations

Sean Guillory (3)

Vice President, Commercial

James J. Bender

Director

Carlos A. Fierro

Director

Rob L. Jones

Director

Anne C. Anderson

Director

Cynthia V. Hablinski (4)

Director

(1) Effective March 1, 2021, Kevin M. Nichols elected to retire from his role as President, Chief Executive Officer and Director, and was replaced by Steven C. Ledbetter.

(2) Jesse C. H. Stanley resigned as Vice President, Operations effective July 31, 2021, and effective October 15, 2021 was replaced by Gregory T. Mouras.

(3) Effective March 1, 2021, Sean Guillory was elected to the role of Vice President, Commercial, replacing Steven C. Ledbetter.

(4) Cynthia V. Hablinski was elected as a Director effective March 25, 2021.

Paul R. A. Goodfellow. Paul Goodfellow became a member of the Board on October 29, 2014. He was named Chairman of the Board on April 15, 2019. Since April 2019, Dr. Goodfellow has served as Executive Vice President, Deep Water for Shell Energy Resources. Prior to this, Dr. Goodfellow served as Executive Vice President, Wells for Shell International. Prior to this, Dr. Goodfellow served as Vice President, United Kingdom and Ireland for Upstream International since February 2015 and as the Vice President, Unconventionals U.S. and Canada for Shell Upstream Americas from January 2013. Prior to this role, Dr. Goodfellow moved into the role of Vice President Development, Onshore in September 2009 for Upstream Americas responsible for field development planning, technical and technology functions. In July 2008, Dr. Goodfellow was named Venture Manager for North America Onshore. In August of 2003 he took up the role of Wells Manager for the Americas

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Region and in 2000, Dr. Goodfellow was assigned to Shell Exploration & Production Company as the Operations Manager for Deepwater Drilling and Completions. He has worked in a variety of wells related roles throughout the Shell Group. Dr. Goodfellow worked in the mining industry in South Africa and Finland prior to joining Shell in Holland in 1991. Dr. Goodfellow is a Chartered Engineer and a member of the Institute of Mining and Metallurgy and the Society of Petroleum Engineers. Dr. Goodfellow earned a Bachelor of Engineering in Mining Engineering and a Ph.D. in Rock Mechanics from The Camborne School of Mines in the United Kingdom. We believe that Dr. Goodfellow’s extensive experience in the energy industry makes him well qualified to serve as a member of the Board.

Steven C. Ledbetter. Steven Ledbetter was appointed as President and Chief Executive Officer of our general partner and elected as a member of the Board effective March 1, 2021. Mr. Ledbetter is a 22-year Shell executive with deep financial and operational management experience. Previously, Mr. Ledbetter became Vice President, Commercial of our general partner on April 1, 2018, where he was responsible for business development, joint ventures, oil movements and portfolio activity. Prior to that, Mr. Ledbetter served as the President of Jiffy Lube International (“Jiffy Lube”), a wholly owned subsidiary of Shell. Prior to his role as President of Jiffy Lube, Mr. Ledbetter served as Director of Key Accounts for Shell’s Consumer Lubricants business for North America from 2010 to 2013, where he was responsible for large platform multi-site business development throughout North America. From 2009 to 2010, he worked as Deal Manager setting strategy and negotiating large platform deals for the route to market for the Lubricants business in North America. In 2007, Mr. Ledbetter was North American Consumer Finance Manager for the Lubricants business, where he was responsible for financial support and economic assurance of the business. In 2004, he became a member of the leadership team for Shell’s Puget Sound Refinery in Anacortes, Washington, and was accountable for finance and procurement activities of the site. From 1999 to 2004, Mr. Ledbetter held various roles in SPLC, including working in a financial support role for the business, serving as treasurer of several joint ventures and business planning and accounting. Prior to joining Shell, Mr. Ledbetter was a facility cost analyst with United States Gypsum Company based in Texas. Mr. Ledbetter holds a bachelor’s degree in Finance from Texas A&M University. The Partnership believes that Mr. Ledbetter’s extensive experience across a wide range of strategy, finance, commercial deal structuring, business transformation and business leadership makes him well qualified to serve as an executive officer.

Shawn J. Carsten. Shawn Carsten became Chief Financial Officer and Vice President of our general partner on March 1, 2017. He is a 32-year Shell executive with deep financial and operational management experience, as well as significant experience in Shell’s Upstream, Downstream and Retail businesses. Prior to his current role, Mr. Carsten served as the Downstream Controller - Americas of SOPUS, where he was responsible for the financial results and control framework for Shell’s Downstream companies in North and South America, as well as finance operations personnel in the Americas and in Asia. Prior to his role as Controller, Mr. Carsten spent 2013 serving as the Finance Shareholding Representative for Motiva, a multi-billion dollar joint venture, where he was responsible for assessing value proposals and investment opportunities. From 2011 through 2012, Mr. Carsten served as the Finance Manager for Supply and Distribution, supporting North and South America with operational management and functional leadership for capital project development, commercial development and business performance, having served in various related capacities since 2008. Mr. Carsten holds a bachelor’s degree in Finance from the University of Colorado and a MBA from the Kellogg School of Management at Northwestern University. We believe that Mr. Carsten’s extensive experience across a wide range of energy segments, particularly his experience in financial management of domestic supply and distribution, makes him well qualified to serve as a director.

Lori M. Muratta. Lori Muratta became Vice President, General Counsel and Secretary of our general partner in 2014. In 2017, she was named Managing Counsel, Midstream & Commercial for Shell, a role she fills in addition to her role with our general partner. Ms. Muratta devotes the majority of her time to our business and affairs and also spends time devoted to the business and affairs of Shell. Prior to her current roles, from 2000 Ms. Muratta served as Senior Counsel for Shell Oil Company, where she advised the company in mergers, acquisitions, divestments, joint ventures and financings in the Upstream, Midstream and Downstream businesses. She also provided corporate law support to Shell’s U.S. subsidiaries and affiliates. Before her time at Shell, Ms. Muratta was Attorney and Manager of Communications at Solvay America, Inc. and worked as an associate at Mayor, Day, Caldwell & Keeton LLP and O’Melveny & Myers LLP. Ms. Muratta received a Bachelor of Science in Foreign Service, cum laude, from Georgetown University and a Juris Doctor, cum laude, from Harvard Law School.

Gregory T. Mouras. Greg Mouras has been appointed as the General Manager of U.S. Midstream Operations for SPLC and was elected as Vice President, Operations our general partner, both effective as of October 15, 2021. Previously, Mr. Mouras served as the Asset Operations Manager for SPLC in the Gulf of Mexico region since 2018, and filled the role of interim General Manager of U.S. Midstream Operations since July 2021, helping to lead our business through Hurricane Ida recovery. Since joining Shell in 2003, Mr. Mouras served in various engineering and operational roles in Shell’s Deepwater Gulf of Mexico business, including Facilities and Reliability Engineering Manager, Surface Technical Development Manager and Regional Discipline Lead, thereby gaining expertise in the integrated Gulf of Mexico value chain from Upstream to the market.

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Mr. Mouras graduated from Louisiana State University with a Bachelor’s degree in Mechanical Engineering and holds a Professional Engineering license in Louisiana.

Sean Guillory. Mr. Guillory has been elected as Vice President, Commercial of our general partner effective March 1, 2021. Mr. Guillory is a 17-year Shell executive with deep commercial, operational and management experience. Mr. Guillory formerly served as the General Manager of Business Units, Joint Ventures and as a manager of business development for SPLC. Prior to this, Mr. Guillory was a Business Development lead for Gulf of Mexico deepwater pipelines and major growth projects, where he was instrumental in the successful completion and commercial deal execution of multiple export solutions for large Gulf of Mexico deep water developments. Prior to his roles with SPLC, Mr. Guillory was the Americas Category Manager for Shell’s Supply and Distribution business, where he was responsible for setting procurement and negotiation strategies supporting operational management for several sites across North and South America. Prior, Mr. Guillory served as Shell Chemical’s Aromatics Supply manager, where he was accountable for operational logistics and demand management for various chemicals manufacturing sites. From 2004 to 2006, Mr. Guillory was the Business Support Manger for the Major Projects Organization at Shell’s Puget Sound Refinery in Anacortes, Washington, where he was accountable for finance, procurement and economic assurance of business activities for the site. Prior to joining Shell, Mr. Guillory served for eight years as an officer in the United States Air Force, where he was a distinguished graduate from the Air Force Reserve Officer Training Program receiving the Tulane University Award for Leadership. Mr. Guillory was a Combat Engineer leading several large teams in the completion of multiple large scale military projects in support of contingency deployment operations vital to national defense across four different continents. Mr. Guillory holds a bachelor’s degree in Mechanical Engineering from the University of New Orleans and an MBA from the University of Colorado.

James (Jim) J. Bender. Jim Bender became a member of the Board on October 29, 2014. Since April 2016, Mr. Bender has been employed with the Hall Estill Law Firm in Denver as Of Counsel. Since December 2015, he has served as an Advisory Board Member of Orion Energy Partners. From May 2014 to July 2014, Mr. Bender served as Senior Vice President of Special Projects of WPX Energy, Inc. (“WPX”), and from December 2013 to May 2014 as interim President and Chief Executive Officer of WPX. Mr. Bender served as a member of the board of directors of WPX from December 2013 to May 2014. He also served as Chairman of the board of directors of APCO Oil and Gas International Inc., a publicly-traded affiliate of WPX, from December 2013 to August 2014. From April 2011 to December 2013, Mr. Bender served as Senior Vice President and General Counsel of WPX. Mr. Bender has served as a member of the board of directors of Two Harbors Investment Corp. since May 2013. Mr. Bender served as Senior Vice President and General Counsel of The Williams Companies, Inc. from December 2002 to December 2011 and General Counsel of Williams Partners GP LLC, the general partner of Williams Partners L.P., from September 2005 until December 2011. Mr. Bender served as the General Counsel of the general partner of Williams Pipeline Partners L.P., from 2007 until its merger with Williams Partners L.P. in August 2010. From June 1997 to June 2002, he was Senior Vice President and General Counsel of NRG Energy, Inc. Mr. Bender earned a bachelor’s degree in mathematics, summa cum laude, from St. Olaf College and a Juris Doctor, magna cum laude, from the University of Minnesota Law School. We believe that Mr. Bender’s extensive experience in the energy industry, and more specifically with sponsored master limited partnerships, makes him well qualified to serve as a member of the Board.

Carlos A. Fierro. Carlos A. Fierro became a member of the Board January 1, 2015. Mr. Fierro is a private investor and consultant based in Washington, D.C. In addition to this Board, Mr. Fierro serves on the board of directors, audit committee and governance and compensation committee of Athabasca Oil Corporation, a Canadian energy company with a focused strategy on the development of thermal and light oil assets. From May 2016 to the present, Mr. Fierro has served as a Senior Advisor to Guggenheim Securities, the investment banking arm of Guggenheim Partners. From September 2008 through June 2013, Mr. Fierro was a Managing Director and Global Head of the Natural Resources Group of Barclays, which encompasses Barclays’ oil and gas, chemicals and metals and mining businesses. Mr. Fierro joined Barclays Capital in 2008 from Lehman Brothers, where he was the Global Head of the Natural Resources Group from January 2007 through September 2008. From September 2004 through January 2007, Mr. Fierro served as Co-Head of Mergers & Acquisitions in Europe for Lehman Brothers from a base in London. Prior to that, Mr. Fierro led Lehman Brothers’ mergers and acquisitions effort in the natural resources sector for seven years, based in New York. Throughout his banking career, Mr. Fierro participated in the development, structuring, negotiation and execution of numerous merger, acquisition, divestiture, restructuring and joint venture transactions. In the natural resources sector, these included transactions for companies involved in exploration and production, refining and marketing, oil field services, mining, pipelines, petrochemicals and coal. Prior to his banking career, Mr. Fierro practiced corporate, M&A and securities law for eleven years with Baker Botts L.L.P., where he was a partner. In his practice, Mr. Fierro devoted his time principally to oil and gas transactions, including hostile takeovers, acquisitions, divestitures, public and private debt and equity financing transactions, corporate restructurings and proxy fights. Mr. Fierro holds a Bachelors of the Arts degree from the University of Notre Dame and a Juris Doctor from Harvard University. We believe that Mr. Fierro’s extensive experience in the energy banking industry, as well as his work in mergers and acquisitions, makes him well qualified to serve as a member of the Board.

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Rob L. Jones. Rob Jones became a member of the Board on October 29, 2014. Mr. Jones is a private investor and consultant based in Houston, Texas. Mr. Jones also currently serves as a director on the board of Spire Inc., a public utility holding company based in St. Louis, Missouri. Mr. Jones also serves as a director on the board of BancAffiliated Inc., a privately held bank based in Arlington, Texas. From September 2012 until June 2014, Mr. Jones served as an Executive in Residence at the McCombs School of Business at the University of Texas at Austin (“McCombs”). Mr. Jones continues as a guest lecturer and speaker at McCombs. Mr. Jones also served as Lead Independent Director for Susser Petroleum Partners, L.P., a publicly-traded partnership. From 2007 through June 2012, Mr. Jones was the Co-Head of Bank of America Merrill Lynch Commodities (“MLC”). MLC is a global commodities trading business and a wholly owned subsidiary of Bank of America Merrill Lynch. Prior to taking leadership of MLC in 2007, he served as Head of Merrill Lynch’s Global Energy and Power Investment Banking Group and founder of Merrill Lynch Commodities Partners, a private equity vehicle for the firm. An investment banker with Merrill Lynch and The First Boston Corporation for over 20 years, Mr. Jones worked extensively with a variety of energy and power clients, with a particular focus on the natural gas and utility sectors. From 1980 until 1985, Mr. Jones was a Financial Associate with the oil and gas exploration and production division of Sun Company, primarily based in Dallas, Texas. He is a graduate of the University of Texas, where he received a Bachelor of Business Administration in Finance with Honors and an MBA with High Honors and was a Sord Scholar. Mr. Jones is a Life Member of the Dean’s Advisory Council of McCombs and an Emeritus Member of the Children’s Fund of Houston Texas. We believe that Mr. Jones’s extensive experience in financial and mergers and acquisitions roles in the energy banking industry and his experience as a lead independent director makes him well qualified to serve as a member of the Board.

Anne C. Anderson. Since July 2019, Ms. Anderson has served as Vice President of the Americas organization within Shell Chemical, where she is responsible for the Americas region of Shell’s global chemicals business. Prior to that role, Ms. Anderson was Vice President of Shell’s Aviation organization from 2014 to 2019, where she successfully led Shell’s global supply organization for aviation fuels and lubricants. From 2009 to 2014, she held roles with increasing responsibility in Shell’s Trading and Supply organization, including as the General Manager of Trading and Supply for SOPUS. Before that, Ms. Anderson served as the General Manager of the PDO (Propanediol) and Corterra™ Polymers business units in Shell Chemical from 2006 to 2009 and as a Board Member of PTT PolyCanada, a Shell Chemical joint venture, in Montreal, Quebec. Ms. Anderson started her career as a chemical engineer in manufacturing and technology at the Monsanto Company. Ms. Anderson holds a Bachelor of Science in Chemical Engineering from Florida State University and an MBA from Washington University in St. Louis. The Partnership believes that Ms. Anderson’s extensive technical and operational experience makes her well qualified to serve as a director.

Cynthia V. Hablinski. Ms. Hablinski is currently the Head of U.S. Pensions and Treasury Americas for Shell Oil Company and has more than 20 years of experience working with energy businesses. Since Ms. Hablinski joined Shell in 2005 as Senior Tax Counsel, she has held a wide range of U.S. and global finance roles across many lines of business. In her current role, she is accountable for the oversight and operation of the Shell Pension Trust and Shell Provident Fund, serving 65,000 participants. She works with the trustees for these plans such that the trustees have the structure and information to carry out their responsibilities and to ensure regulatory compliance. She also serves as a member of the Investment Committee for these plans. Additionally, Ms. Hablinski has oversight for all Shell Treasury activity in the Americas. Prior to joining Shell, Ms. Hablinski was a consultant in Ernst & Young LLP’s International Tax Services group, where she specialized in cross-border tax planning for both U.S. and foreign-based energy clients. From 1997 to 2000, she represented the Internal Revenue Service in various tax litigation matters as a trial attorney at the U.S. Department of Justice Tax Division. She began her career as an associate at Ackels & Ackels, LLP in Dallas, Texas. Ms. Hablinski graduated from Baylor University with a BBA in Accounting and Economics. She completed her Juris Doctor and MBA at Texas Tech University and her LLM in Taxation at SMU Dedman School of Law. She is a licensed CPA and attorney in Texas. The Partnership believes that Ms. Hablinski’s extensive experience across a wide range of finance and deal structuring roles makes her well qualified to serve as a director.

Board Leadership Structure

Although the chief executive officer of our general partner currently does not also serve as the chairman of the Board, the Board has no policy with respect to the separation of the offices of chairman of the Board and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the Board are designated or elected by SPLC. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our Partnership Agreement.

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Board Role in Risk Oversight

Our corporate governance guidelines provide that the Board is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility is satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

Director Independence

Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require publicly-traded partnerships to have a majority of independent directors on the Board or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within one year of the date our common units are first listed on the NYSE, and all of our audit committee members are required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.

Committees of the Board of Directors

The Board has an audit committee and a conflicts committee. The Board may also have such other committees as the Board determines from time to time. Each of the standing committees of the Board has the composition and responsibilities described below.

Audit Committee

Our general partner has an audit committee composed of at least three directors, each of whom meets the independence and experience standards established by the NYSE and the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Our audit committee assists the Board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to our audit committee. Messrs. Jones, Bender and Fierro currently serve as members of our audit committee; Mr. Jones is the committee chair. Each of Messrs. Jones, Bender and Fierro is deemed to be “financially literate” as defined by the listing standards of NYSE, and each of Messrs. Jones and Fierro is deemed an “audit committee financial expert,” as defined in SEC regulations. Our audit committee charter is posted on the “Corporate Governance” section of our website. We have a separately-designated standing audit committee in accordance with section 3(a)(58)(A) of the Exchange Act.

Our audit committee has reviewed and discussed the audited financial statements with management. It has also discussed with the independent auditors the matters required by Public Company Accounting Oversight Board (“PCAOB”) Auditing Standard No. 16, Communications with Audit Committees. Our audit committee has received written disclosures and the letter from the independent accountants required by applicable requirements of the PCAOB regarding the independent accountant’s communications with the audit committee concerning independence and has discussed with the independent accountant the independent accountant’s independence. The audit committee recommended to the Board that the audited financial statements as of and for the year ended December 31, 2021 be included in this report.

Conflicts Committee

In accordance with the terms of our Partnership Agreement, at least two members of the Board will serve on our conflicts committee to review specific matters that may involve conflicts of interest. The members of our conflicts committee cannot be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee cannot own any interest in our general partner or its affiliates or any interest in us or our subsidiaries other than common units or awards, if any, under our incentive compensation plan. Messrs. Bender, Jones and Fierro currently serve as members of our conflicts committee; Mr. Bender is the committee chair.

Governance Guidelines

We have adopted governance guidelines to assist the Board in the exercise of its responsibilities. Our corporate governance guidelines provide that the non-management directors will meet periodically in executive sessions without management

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participation. At least annually, all of the independent directors of our general partner meet in executive sessions without management participation or participation by non-independent directors. Currently, Dr. Goodfellow, the Chairman of the Board, presides at the executive sessions of the non-management directors, and Mr. Jones, the Chairman of the audit committee, presides at the executive sessions of the independent directors.

Compensation Committee Interlocks and Insider Participation

The listing rules of the NYSE do not require us to maintain, and we do not maintain, a compensation committee.

Code of Conduct and Code of Ethics

We have adopted a Code of Conduct applicable to all employees, directors and officers, as well as a Code of Ethics applicable to our general partner’s chief financial officer. Our Code of Conduct covers topics including, but not limited to, conflicts of interest, insider dealing, competition, discrimination and harassment, confidentiality, bribery and corruption, sanctions and compliance procedures. Our Code of Ethics covers topics including, but not limited to, conflicts of interest, gifts and disclosure controls. Our Code of Conduct and Code of Ethics are posted on the “Corporate Governance” section of our website.

Delinquent Section 16(a) Reports

Section 16(a) of the Exchange Act requires directors and executive officers of our general partner, and persons who own more than 10% of a registered class of our equity securities, to file reports of ownership and changes in ownership of our common units with the SEC and the NYSE, and to furnish us with copies of the forms they file. To our knowledge, based solely upon a review of the copies of such reports furnished to us and written representations of our officers and directors, during 2021, all Section 16(a) reports applicable to our officers and directors were filed on a timely basis.

Item 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Neither we nor our general partner employ any of the individuals who serve as executive officers of our general partner and are responsible for managing our business. Our general partner does not have a compensation committee. We are managed by our general partner, the executive officers of which are employees of Shell. We and our general partner have entered into the 2019 Omnibus Agreement (as defined below) with SPLC pursuant to which, among other matters:

•SPLC makes available to our general partner the services of Shell employees who will serve as the executive officers of our general partner; and

•we pay SPLC an annual administrative fee, currently $10 million, to cover, among other things, the services provided to us by the executive officers of our general partner.

These officers and all other personnel necessary for our business to function are employed and compensated by Shell, subject to the administrative services fee in accordance with the terms of the 2019 Omnibus Agreement. Under the 2019 Omnibus Agreement, none of Shell’s long-term incentive compensation expense is allocated directly to us. We are responsible for paying the long-term incentive compensation expense, if any, associated with our long-term incentive plan described below. The executive officers of our general partner continue to participate in employee benefit plans and arrangements sponsored by Shell, including plans that may be established in the future. Our general partner has not entered into any employment agreements with any of its executive officers. We did not grant any awards under our long-term incentive plan to our officers or directors, nor do we have a current intent to do so. Our long-term incentive plan is described below under “—Long-Term Incentive Plan.”

Responsibility and authority for compensation-related decisions for executive officers of our general partner reside with Shell’s human resources function and the Shell Management Development Committee, as applicable. Other than compensation under our long-term incentive plan, which requires action by the Board, any such compensation decisions are not subject to any approvals by the Board or any committees thereof. Our Named Executive Officers (“NEOs”) consist of our general partner’s principal executive officer, principal financial officer, the three most highly compensated executive officers other than its principal executive officer and principal financial officer as of December 31, 2021, and two former officers who would have been amongst those in the foregoing group but for the fact that such individuals were not serving as executive officers of our general partner as of December 31, 2021 being:

•Steven C. Ledbetter, Chief Executive Officer and President

•Shawn J. Carsten, Vice President and Chief Financial Officer

•Lori M. Muratta, Vice President, General Counsel and Secretary

•Gregory T. Mouras, Vice President, Operations

•Sean Guillory, Vice President, Commercial

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•Kevin M. Nichols, Chief Executive Officer and President (retired effective March 1, 2021)

•Jesse C. H. Stanley, Vice President, Operations (resigned effective July 31, 2021)

Each of Mr. Ledbetter, Mr. Carsten, Ms. Muratta, Mr. Mouras and Mr. Guillory devotes, and during their tenure Mr. Nichols and Ms. Stanley devoted, a significant portion of his or her time to his or her roles in Shell and spends time or spent time, as needed, directly managing our business and affairs. Pursuant to the terms of the 2019 Omnibus Agreement, we pay a fixed administrative fee to SPLC, which covers, among other things, the services provided to us by our NEOs. None of Mr. Ledbetter, Mr. Carsten, Ms. Muratta, Mr. Mouras and Mr. Guillory receive, nor did Mr. Nichols or Ms. Stanley receive, any separate amounts of compensation for their services to our business or as executive officers of our general partner and, except for the fixed administrative fee we paid SPLC, we did not otherwise pay or reimburse any compensation amounts to or for them.

Summary Compensation Table

The following summarizes the total compensation paid to our NEOs for their services in relation to our business in 2021, 2020 and 2019:


Name and Principal Position (1)	Year	Salary	Bonus	Unit Awards	Option Awards	Non-Equity Incentive Compensation Plan	Change in Pension Value and Nonqualified Deferred Compensation Earnings	All Other Compensation	Total
Steven C. Ledbetter, President and Chief Executive Officer (2)	2021 2020 2019	— — —	— — —	— — —	— — —	— — —	— — —	— — —	— — —
Kevin M. Nichols, President and Chief Executive Officer (2)	2021 2020 2019	— — —	— — —	— — —	— — —	— — —	— — —	— — —	— — —
Shawn J. Carsten, Vice President and Chief Financial Officer	2021 2020 2019	— — —	— — —	— — —	— — —	— — —	— — —	— — —	— — —
Lori M. Muratta, Vice President, General Counsel and Secretary	2021 2020 2019	— — —	— — —	— — —	— — —	— — —	— — —	— — —	— — —
Alton G. Smith, Vice President, Operations (3)	2021 2020 2019	— — —	— — —	— — —	— — —	— — —	— — —	— — —	— — —
Jesse C. H. Stanley, Vice President, Operations (4)	2021 2020 2019	— — —	— — —	— — —	— — —	— — —	— — —	— — —	— — —
Gregory T. Mouras, Vice President, Operations (5)	2021 2020 2019	— — —	— — —	— — —	— — —	— — —	— — —	— — —	— — —
Sean Guillory, Vice President, Commercial (6)	2021 2020 2019	— — —	— — —	— — —	— — —	— — —	— — —	— — —	— — —

(1) Mr. Ledbetter, Mr. Nichols, Mr. Carsten, Ms. Muratta, Mr. Smith, Ms. Stanley, Mr. Mouras and Mr. Guillory devoted a significant portion of their overall working time to our business during their respective tenures. Except for the fixed management fee we paid to SPLC under the Omnibus Agreement then in effect, we did not pay or reimburse any compensation amounts to or for our named executive officers in 2021, 2020 or 2019.

(2) Effective as of March 1, 2021, Kevin M. Nichols elected to retire from his role as President, Chief Executive Officer and Director, and was replaced by Steven C. Ledbetter.

(3) Mr. Smith retired from his position as Vice President, Operations effective as of July 1, 2020.

(4) Ms. Stanley served as Vice President, Operations from July 22, 2020 until she resigned from her position effective as of July 31, 2021.

(5) Mr. Mouras became Vice President, Operations effective as of October 15, 2021. Mr. Mouras was not an NEO in 2020 or 2019.

(6) Effective as of March 1, 2021, Mr. Guillory was elected to the role of Vice President, Commercial, replacing Mr. Ledbetter. Mr. Guillory was not an NEO in 2020 or 2019.

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Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure

Compensation by Shell

Shell provides compensation to its executives in the form of base salaries, annual cash incentive awards, long-term equity incentive awards and participation in various employee benefit plans and arrangements, including broad based and supplemental defined contribution and defined benefit retirement plans. In addition, although our NEOs have not entered into employment agreements with Shell, Mr. Nichols had an end of employment arrangement with Shell under which he received separation payments and benefits from Shell based on termination at the employer’s initiative or on mutually agreed terms. In the future, Shell may provide different or additional compensation components, benefits or perquisites to our NEOs.

The following sets forth a more detailed explanation of the elements of Shell’s executive compensation program.

Base Compensation

Our NEOs earn a base salary for their services to Shell and its affiliates, which amounts are paid by Shell or its affiliates other than us. We incur only a fixed expense per month under the 2019 Omnibus Agreement with respect to the compensation paid by Shell to each of our NEOs.

Annual Cash Bonus Payments

Our NEOs are eligible to earn cash payments from Shell under Shell’s annual incentive bonus program and other discretionary bonuses that may be awarded by Shell. Any bonus payments earned by the NEOs will be paid by Shell and will be determined solely by Shell without input from us or our general partner or its board of directors. The amount of any bonus payment made by Shell will not result in changes to the contractually fixed fee for executive management services that we pay to Shell under the 2019 Omnibus Agreement.

Share-Based Compensation

Shell’s incentive compensation programs primarily consist of share awards, restricted share awards or cash awards (any of which may be a performance award). Conditional awards of Shell plc (“Shell”) shares are made under the terms of the Performance Share Plan (“PSP”) on a selective basis to senior personnel each year. The extent to which the awards vest is determined over a three-year performance period. Half of the award is linked to the key performance indicators, averaged over the period. The other half of the award is linked to a comparison with four main competitors of Shell over the period on the basis of four relative performance measures. All shares that vest are increased by an amount equal to the notional dividends accrued on those shares during the period from the award date to the vesting date. None of the awards result in beneficial ownership until the shares are delivered. Shares are awarded subject to a three-year vesting period.

Certain SPLC and Shell employees supporting our operations as well as other Shell operations were historically granted awards under the PSP. Share-based compensation expense is included in general and administrative expenses in the accompanying consolidated statements of income. These costs for 2021, 2020 and 2019 were immaterial.

Long-Term Equity-Based Incentive Compensation

Shell maintains a long-term incentive program pursuant to which it grants equity based awards in Shell plc to certain of its executives and employees. Our NEOs may receive awards under Shell’s equity incentive plan from time to time as may be determined by the Shell Management Development Committee. The amount of any long-term incentive compensation made by Shell will not result in changes to the contractually fixed fee for executive management services that we will pay to Shell under the 2019 Omnibus Agreement.

Retirement, Health, Welfare and Additional Benefits

Our NEOs are eligible to participate in the employee benefit plans and programs that Shell offers to its employees, subject to the terms and eligibility requirements of those plans. Our NEOs are also eligible to participate in Shell’s tax-qualified defined contribution and defined benefit retirement plans to the same extent as all other Shell employees. Shell also has certain supplemental retirement plans in which its executives and key employees participate.

Director Compensation

Officers or employees of Shell or its affiliates who also serve as directors of our general partner do not receive additional compensation for such service. Our general partner’s directors who are not also officers or employees of Shell receive compensation for service on the board of directors and its committees. We currently pay each of such directors $150,000 annually. We currently pay the audit committee chairman an additional $15,000 annually and the conflicts committee chairman

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an additional $15,000 annually. In addition, each such director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board and committee meetings. We currently pay meeting fees to each of such directors in the amount of $2,000 for each in-person board meeting, $2,000 for each in-person committee meeting, $1,000 for each telephonic board meeting and $1,000 for each telephonic committee meeting. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our Partnership Agreement.

Non-Employee Director Compensation Table

The following summarizes the compensation for our non-employee directors for 2021:


Name	Fees Earned or Paid in Cash		Unit Awards		Option Awards		Non-Equity Incentive Plan Compensation		Non-Qualified Compensation		Deferred Earnings		All Other Compensation		Total
James J. Bender	$	191,000	$	—	$	—	$	—	$	—	$	—	$	—	$	191,000
Carlos A. Fierro	175,000		—		—		—		—		—		—		175,000
Rob L. Jones	191,000		—		—		—		—		—		—		191,000

Pay Ratio Disclosure

We do not have any employees. The officers and all other personnel necessary for our business are employed and compensated by Shell, subject to the administrative services fee in accordance with the terms of the 2019 Omnibus Agreement and our operating agreements. Therefore, we are unable to provide an estimate of the relationship of the median of the annual total compensation of our employees and the annual total compensation of our chief executive officer.

Long-Term Incentive Plan

Our general partner has adopted the Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan (“LTIP”) for officers, directors and employees of our general partner or its affiliates, and any consultants, affiliates of our general partner or other individuals who perform services for us. Our general partner may issue our executive officers and other service providers long-term equity based awards under the LTIP, which awards would compensate the recipients thereof based on the performance of our common units and their continued employment during the vesting period, as well as align their long-term interests with those of our unit holders. Our general partner has not issued, and does not currently intend to issue, any awards under the LTIP.

We are responsible for the cost of awards granted under our LTIP and all determinations with respect to awards, if any, to be made under our LTIP will be made by the Board or any committee thereof that may be established for such purpose or by any delegate of the Board, subject to applicable law, which we refer to as the plan administrator. We currently expect that the Board or a committee thereof will be designated as the plan administrator. The following description reflects the principal terms that are currently expected to be included in the LTIP.

General

The LTIP permits the Board or any applicable committee or delegate thereof, in its discretion, subject to applicable law, from time to time to grant unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards, if any, under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. The LTIP limits the number of units that may be delivered pursuant to vested awards to 6,000,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited or otherwise terminated without delivery of the common units are generally available for delivery pursuant to other awards, as provided in the LTIP.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, on a deferred basis, upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of

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specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

Unit Options and Unit Appreciation Rights

The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.

Profits Interest Units

Awards may consist of profits interest units to the extent contemplated by our Partnership Agreement. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other Unit-based Awards

The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of any other unit-based award may be based on a grantee’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, any other unit-based award may be paid in cash and/or in units (including restricted units) or any combination thereof as the administrator of the LTIP may determine.

Source of Common Units

Common units to be delivered with respect to awards may be newly issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

Anti-Dilution Adjustments and Change in Control

If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the administrator of the LTIP has the discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number and kind of units subject to outstanding awards, the terms and conditions of any outstanding awards and the grant or exercise price per unit for outstanding awards under the LTIP. Furthermore, in connection with a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) permit awards to be surrendered in exchange for a cash payment, (iii) cause awards then outstanding to be assumed or substituted for other rights by the surviving entity in the change in control, (iv) provide for either

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(A) the termination of any award in exchange for a payment of the amount that would have been received upon the exercise of such award or realization of the grantee’s rights under such award or (B) the replacement of an award with other rights or property selected by the administrator having an aggregate value not exceeding the amount that could have been received upon the exercise of such award or realization of the grantee’s rights had such award been currently exercisable or payable or fully vested, (v) provide that an award be assumed by the successor or survivor entity, or be exchanged for similar options, rights or awards covering the equity of the successor or survivor, with appropriate adjustments thereto, (vi) make adjustments in the number and type of units subject to outstanding awards, the number and kind of outstanding awards, the terms and conditions of, and/or the vesting and performance criteria included in, outstanding awards, (vii) provide that an award will vest or become exercisable or payable and/or (viii) provide that an award cannot be exercised or become payable after such event and will terminate upon such event.

Termination of Employment

The LTIP provides the administrator with the discretion to determine in each award agreement the effect of a termination of a grantee’s employment, membership on our general partner’s Board or other service arrangement on the grantee’s outstanding awards.

Amendment or Termination of LTIP

The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP automatically terminates on the tenth anniversary of the date it was initially adopted by our general partner. The administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Internal Revenue Code.

Compensation Committee Report

We do not have a compensation committee. Accordingly, the Compensation Committee Report required by Item 407(e)(5) of Regulation S-K is given by the Board. The Board has reviewed and discussed the Compensation Discussion and Analysis presented above with management and, based on such review and discussions, the Board has approved the inclusion of the Compensation Discussion and Analysis in this Annual Report on Form 10-K.

Members of the Board of Directors of Shell Midstream Partners GP LLC:

Paul R. A. Goodfellow

Steven C. Ledbetter

Shawn J. Carsten

James J. Bender

Carlos A. Fierro

Rob L. Jones

Anne C. Anderson

Cynthia V. Hablinski

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth the beneficial ownership of common units of Shell Midstream Partners, L.P. held by beneficial owners of 5% or more of the common units, by each director, director nominee and named executive officer of our general partner and by the directors, director nominees and executive officers of our general partner as a group. The percentage of units beneficially owned is based on 393,289,537 common units outstanding as of February 24, 2022.

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Name of Beneficial Owner (1)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned
Shell Pipeline Company LP (2)	269,457,304	68.5	%
James J. Bender	35,000	—	%
Rob L. Jones	30,000	—	%
Shawn J. Carsten	18,700	—	%
Lori M. Muratta (3)	15,270	—	%
Kevin M. Nichols	8,500	—	%
Steven C. Ledbetter	4,000	—	%
Carlos A. Fierro	3,000	—	%
Sean Guillory	1,399	—	%
Anne C. Anderson	—	—	%
Paul R. A. Goodfellow	—	—	%
Cynthia V. Hablinski	—	—	%
Gregory T. Mouras	—	—	%
Directors and executive officers as a group (12 persons)	115,869	—	%

(1) The address for all beneficial owners in this table, except as noted in the table, is 150 N. Dairy Ashford, Houston, Texas 77079.

(2) Shell Pipeline Company LP owns Shell Midstream LP Holdings LLC, which owns the common units presented above. Shell Pipeline Company LP may be deemed to beneficially own the units held by Shell Midstream LP Holdings LLC.

(3) The number of common units presented for Ms. Muratta includes 2,310 units held jointly under a retirement account in the name of Ms. Muratta’s spouse.

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth information about all existing equity compensation plans as of December 31, 2021.


Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (1))
Equity compensation plans approved by security holders (1)	—	—	6,000,000
Equity compensation plans not approved by security holders	—	—	—
Total	—	—	6,000,000

(1) The amounts shown represent common units available under the LTIP as of December 31, 2021. No awards have been made under the LTIP.

Item 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE

As of February 24, 2022, SPLC’s wholly owned subsidiary, Shell Midstream LP Holdings LLC (“LP Holdings”) owned 269,457,304 common units, representing a 68.5% limited partner interest in us. The Partnership also had 50,782,904 of Series A Preferred Units outstanding, which are entitled to receive a quarterly distribution of $0.2363 per unit and all of which are owned by LP Holdings.

See Part III, Item 10. Directors, Executive Officers and Corporate Governance – Management of Shell Midstream Partners, L.P. in this report for additional information regarding director independence.

Distributions and Payments to Our General Partner and Its Affiliates

132

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operation and upon liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Operational Stage


Distributions of available cash to our general partner and its affiliates						We generally make cash distributions to the common unitholders pro rata, including SPLC, as holder of an aggregate of 269,457,304 common units (61% of all units outstanding) and 50,782,904 preferred units (11% of all units outstanding).

Payments to our general partner and its affiliates						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, we pay an annual fee, currently $10 million, to SPLC for general and administrative services. In addition, we reimburse our general partner and SPLC, as applicable, pursuant to our management agreement and operational and administrative management agreement for Pecten, Sand Dollar and Triton.

Withdrawal or removal of our general partner						If our general partner withdraws or is removed, its non-economic general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation Stage

Liquidation						Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements with Shell

We have entered into various agreements with Shell, as described in detail below. These agreements were negotiated in connection with, among other things, the formation of the Partnership, our Initial Public Offering and our acquisitions from Shell. These agreements address, among other things, the acquisition of assets and the assumption of liabilities by us. These agreements were not the result of arm’s length negotiations and, as such, they or underlying transactions may not be based on terms as favorable as those that could have been obtained from unaffiliated third parties.

Omnibus Agreement

On February 19, 2019, we, our general partner, SPLC and the Operating Company entered into a new Omnibus Agreement effective February 1, 2019 (the “2019 Omnibus Agreement”).

The 2019 Omnibus Agreement addresses, among other things, the following matters:

•our payment of an annual administrative fee, currently $10 million, for the provision of certain services by SPLC;

•our obligation to reimburse SPLC for certain direct or allocated costs and expenses incurred by SPLC on our behalf; and

•SPLC’s obligation to indemnify us for certain environmental and other liabilities, and our obligation to indemnify SPLC for certain environmental and other liabilities related to our assets to the extent SPLC is not required to indemnify us.

So long as SPLC controls our general partner, the 2019 Omnibus Agreement will remain in full force and effect. If SPLC ceases to control our general partner, either party may terminate the 2019 Omnibus Agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms. During 2021 and 2020, neither we nor SPLC made any claims for indemnifications under the 2019 Omnibus Agreement. For additional information, see Note 4 — Related Party Transactions in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this report.

Trade Marks License Agreement

133

information, see Note 4 — Related Party Transactions in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this report.

Operating Agreements

For amounts paid under these agreements, see Note 4 — Related Party Transactions in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this report.

Joint Venture and Subsidiary Governing Agreements

We are a party to the governing agreements of the entities in which we own equity interests. The governing agreements of such entities govern the ownership and management of the applicable entity. Our ability to influence decisions with respect to the operation of certain of the entities in which we own interests varies depending on the amount of control we exercise under the applicable governing agreement.

The governing agreements generally include provisions related to cash distributions, capital calls, transfer restrictions and termination of the applicable entity. For example, 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 provided for in the applicable governing agreement over the cash reserves made by certain of these entities. Additionally, 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.

Voting Agreements

Tax Sharing Agreement

134

effective for all tax periods ending before December 31, 2017. Reimbursements settled in the years ended December 31, 2021, 2020 and 2019 were not material to our consolidated statements of income.

Procedures for Review, Approval or Ratification of Transactions with Related Parties

The Board has adopted a written policy for the review, approval and ratification of transactions with related persons. For the purposes of the policy, a “related person” is any director or executive officer of our general partner, any unitholder known to us to be the beneficial owner of more than 5% of our common units and any immediate family member (as defined under SEC rules) of any such person, and a “related person transaction” is generally a transaction in which we are, or our general partner or any of our subsidiaries is, a participant, the amount involved exceeds $120,000, and a related person has a direct or indirect material interest. Transactions resolved under the conflicts provision of the Partnership Agreement are not required to be reviewed or approved under the policy.

The policy sets forth certain categories of transactions that are deemed to be pre-approved by the audit committee of the Board under the policy. After applying these categorical standards and weighing all of the facts and circumstances, the audit committee of the Board must then either approve or reject the transaction in accordance with the terms of the policy.

In accordance with the policy, a director is expected to bring to the attention of the Board any conflict or potential conflict of interest that may arise between the director or any immediate family member of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the Board, be determined by a majority of the disinterested directors.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for professional services performed by our independent registered public accounting firm, Ernst & Young LLP, for 2021 and 2020:


(in millions of dollars)	2021		2020
Fees
Audit fees (1)	$	2	$	3
Audit-related fees	—		—
Tax fees	—		—
All other fees	—		—
Total	$	2	$	3

(1) Fees for audit services related to the fiscal year consolidated audit, quarterly reviews and services that were provided in connection with registration statements, statutory and regulatory filings.

The audit committee has adopted a pre-approval policy that provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by the independent registered public accounting firm to the Partnership. All of the fees in the table above were approved in accordance with this policy. The policy (a) identifies the guiding principles that must be considered by the audit committee in approving services to ensure that the independent registered public accounting firm’s independence is not impaired; (b) describes the audit, audit-related, tax and other services that may be provided and the non-audit services that are prohibited; and (c) sets forth pre-approval requirements for all permitted services. Under the policy, all services to be provided by the independent registered public accounting firm must be pre-approved by the audit committee. The audit committee has delegated authority to approve permitted services to the audit committee’s Chair. Such approval must be reported to the entire audit committee at the next scheduled audit committee meeting.

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

1. Financial Statements and Supplementary Data

The financial statements and supplementary information listed in the Index to Financial Statements, which appears in Part II, Item 8, are filed as part of this Annual Report.

2. Financial Statement Schedules

The following financial statement schedules are included pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09):


Mars Oil Pipeline Company LLC			Financial Statements as of and for the three years ended December 31, 2021 (audited)
Amberjack Pipeline Company LLC			Financial Statements as of and for the three years ended December 31, 2021 (audited)

All other financial statement schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the financial statements or the notes to consolidated financial statements.

3. Exhibits

The exhibits listed in the Index to Exhibits are filed as part of this Annual Report.

136

SHELL MIDSTREAM PARTNERS, L.P.

INDEX TO EXHIBITS

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

Exhibit

Number

Filing Date

SEC File

No.

3.1

Amended and Restated Certificate of Limited Partnership of Shell Midstream Partners, L.P.

S-1

3.1

06/18/2014

333-196850

3.2

Second Amended and Restated Agreement of Limited Partnership of Shell Midstream Partners, L.P., dated as of April 1, 2020

8-K

3.1

4/2/2020

001-36710

3.3

Amended and Restated Certificate of Formation of Shell Midstream Partners GP LLC

S-1

3.3

06/18/2014

333-196850

3.4

First Amended and Restated Limited Liability Company Agreement of Shell Midstream Partners GP LLC, dated as of November 3, 2014

8-K

3.2

11/03/2014

001-36710

4.1*

Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934

10.1#

Shell Midstream Partners GP LLC 2014 Long-Term Incentive Plan

8-K

10.4

11/03/2014

001-36710

10.2

Shell Midstream Partners Revolving Credit Facility Agreement, dated as of December 1, 2017, between Shell Midstream Partners, L.P., as the Borrower, and Shell Treasury Center (West) Inc., as Lender

8-K

10.1

12/05/2017

001-36710

10.3

Shell Midstream Partners, L.P. Fixed Credit Facility, dated August 1, 2018, between Shell Midstream Partners, L.P., as the as the Borrower, and Shell Treasury Center (West) Inc., as the Lender

8-K

10.1

08/02/2018

001-36710

10.4

Shell Midstream Partners, L.P. Third Amended and Restated Credit Facility Agreement, dated as of August 1, 2018, between Shell Midstream Partners, L.P., as the as the Borrower, and Shell Treasury Center (West) Inc., as the Lender

8-K

10.2

08/02/2018

001-36710

10.5

Omnibus Agreement dated effective February 1, 2019 by and among Shell Pipeline Company LP, Shell Midstream Partners, L.P., Shell Midstream Partners GP LLC and Shell Midstream Operating LLC

10-K

10.18

02/21/2019

001-36710

10.6

Trade Marks License Agreement dated effective February 1, 2019 by and among Shell Trademark Management Inc, Shell Pipeline Company LP, Shell Midstream Partners, L.P. and Shell Midstream Partners GP LLC

10-K

10.19

02/21/2019

001-36710

10.7

Shell Midstream Partners, L.P. Credit Facility, dated as of June 4, 2019, between Shell Midstream Partners, L.P., as the Borrower, and Shell Treasury Center (West) Inc., as the Lender

8-K

10.1

06/06/2019

001-36710

10.8

Revolving Loan Facility Agreement, dated as of August 6, 2019, between Zydeco Pipeline Company LLC, as the Borrower, and Shell Treasury Center (West) Inc., as the Lender

10-Q

10.3

08/02/2019

001-36710

10.9

Purchase and Sale Agreement, dated as of February 27, 2020, by and among Shell Pipeline Company LP, Shell GOM Pipeline Company LLC, Shell Chemical LP, Equilon Enterprises LLC d/b/a Shell Oil Products US, Shell Midstream Partners, L.P. and Triton West LLC

8-K

10.1

02/28/2020

001-36710

10.10

Partnership Interests Restructuring Agreement, dated as of February 27, 2020, by and between Shell Midstream Partners, L.P., Shell Midstream Partners GP LLC

8-K

10.2

02/28/2020

001-36710

10.11

Shell Midstream Partners, L.P. Loan Facility Agreement, dated March 16, 2021, between Shell Midstream Partners, L.P., as the Borrower, and Shell Treasury Center (West) Inc., as the Lender

8-K

10.1

03/16/2021

001-36710

10.12

Sale and Purchase Agreement, dated as of April 28, 2021, between Triton West LLC and Shell Pipeline Company LP

10-Q

10.1

04/30/2021

001-36710

10.13

Termination of Voting Agreement, dated as of April 28, 2021, between Shell Midstream Partners, L.P. and Shell Pipeline Company LP

10-Q

10.2

04/30/2021

001-36710

21*

List of Subsidiaries

23.1*

Consent of Ernst & Young LLP

23.2*

Consent of Ernst & Young LLP

23.3*

Consent of Ernst & Young LLP

31.1*

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

31.2*

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

32.1**

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350

32.2**

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

137

99.1*

Financial Statements of Mars Oil Pipeline Company LLC for the three years ended December 31, 2021 (audited) pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09)

99.2*

Financial Statements of Amberjack Oil Pipeline Company LLC for the three years ended December 31, 2021 (audited) pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09)

101.INS*

XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH*

XBRL Taxonomy Extension Schema

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase

101.DEF*

XBRL Taxonomy Extension Definition Linkbase

101.LAB*

XBRL Taxonomy Extension Label Linkbase

104*

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* Filed herewith.

** Furnished herewith.

# Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 15(b).

138

Item 16. FORM 10-K SUMMARY

Not applicable.

139

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


			SHELL MIDSTREAM PARTNERS, L.P.

			By: Shell Midstream Partners GP LLC, its general partner

February 24, 2022			/s/ Shawn J. Carsten
			Shawn J. Carsten Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 24, 2022, by the following persons on behalf of the registrant and in the capacities indicated.


Signature						Title

/s/ Steven C. Ledbetter						Director, President and Chief Executive Officer Shell Midstream Partners GP LLC (principal executive officer)
Steven C. Ledbetter

/s Shawn J. Carsten						Director, Vice President and Chief Financial Officer Shell Midstream Partners GP LLC (principal accounting officer and principal financial officer)
Shawn J. Carsten

/s/ Paul R.A. Goodfellow						Chairman of the Board of Directors Shell Midstream Partners GP LLC
Paul R.A. Goodfellow

/s/ Rob L. Jones						Director Shell Midstream Partners GP LLC
Rob L. Jones

/s/ James J. Bender						Director Shell Midstream Partners GP LLC
James J. Bender

/s/ Carlos A. Fierro						Director Shell Midstream Partners GP LLC
Carlos A. Fierro

/s/ Anne C. Anderson						Director Shell Midstream Partners GP LLC
Anne C. Anderson
/s/ Cynthia V. Hablinski						Director Shell Midstream Partners GP LLC
Cynthia V. Hablinski

140