shlx-20211231

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:

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.

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.

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.


	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	%

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.

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.

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.

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.


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	—

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

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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

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

Air Emissions and Climate Change. Our operations are subject to the Clean Air Act and its regulations and comparable state and local statutes and regulations in connection with air emissions from our operations. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. These permits may require controls on our air emission sources, and we may become subject to more stringent regulations requiring the installation of additional emission control technologies.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 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:

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

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.

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.

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 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.

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 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.

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.

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

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.

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.

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.

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.

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:

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 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.

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.

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:

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 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.

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.

•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;

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.

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.

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.

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:

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.

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 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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

•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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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 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

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


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)


	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


	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

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.

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.

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 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”).

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 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.

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,

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 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.

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.

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

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

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

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)

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.

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.

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.

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.

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 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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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:

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.


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	— — —	— — —	— — —	— — —	— — —	— — —	— — —	— — —

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.

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.

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.

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.

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.

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

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.

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

(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.

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.

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.

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.

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.

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

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 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.

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)


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


Delaware						46-5223743
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)


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



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


	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)


	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


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


	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


			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


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

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


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


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


	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


	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


	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


	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


	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


		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


	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


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


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


	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)


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


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


(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	—


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


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


	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


	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


	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


	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)


		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


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