Shell Midstream Partners (SHLX) 10-K2020 FY Annual report

 

Unless the context otherwise requires, references in this report to “Shell Midstream Partners,” “the Partnership,” “us,” “our,” “we,” “SHLX” or similar expressions refer to Shell Midstream Partners, L.P. and its subsidiaries. References to “our general partner” refer to Shell Midstream Partners GP LLC, a wholly owned subsidiary of Shell Pipeline Company LP (“SPLC”). References to “RDS,” “Shell” or “Parent” refer collectively to Royal Dutch Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner.

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

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

We own, operate, develop and acquire pipelines and other midstream and logistics assets. As of December 31, 2020, our assets include interests in entities that own (a) crude oil and refined products pipelines and terminals that serve as key infrastructure to transport onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and deliver refined products from those markets to major demand centers and (b) storage tanks and financing receivables that are secured by pipelines, storage tanks, docks, truck and rail racks and other infrastructure used to stage and transport intermediate and finished products. The Partnership’s assets also include interests in entities that own natural gas and refinery gas pipelines that transport offshore natural gas to market hubs and deliver refinery gas from refineries and plants to chemical sites along the Gulf Coast.

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

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

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

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

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

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

T&D agreements, similar to transportation services agreements, require shippers to commit to a minimum volume for a fixed term. If the shipper falls below the minimum volume for the specified term, it is required to make a payment for the volume deficiency at the agreed transportation rate. Because this payment is due at the end of the specified payment term, the timing of

cash flows may be affected. Unlike transportation services agreements, T&D agreements do not offer shippers firm space on the pipeline in question, and, if a segment of the pipeline system is oversubscribed, space is prorated in accordance with applicable regulations.

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

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

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

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

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

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

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

Our logistics assets are comprised of crude, chemicals, intermediate and finished product pipelines, storage tanks, docks, truck and rail racks and supporting infrastructure. We generate revenue on these assets pursuant to terminaling services agreements with related parties, which are treated as a failed sale leaseback for accounting purposes.

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

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

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

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

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

 

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.

Under its current policy, FERC permits regulated interstate oil and gas pipelines to include an income tax allowance in their cost of service used to calculate cost-based transportation rates. The allowance is intended to reflect the tax liability attributable to the regulated entity’s operating income, regardless of the form of ownership. On July 1, 2016, in United Airlines, Inc. v. FERC, the United States Court of Appeals for the D.C. Circuit vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned by a master limited partnership (“MLP”) to include an income tax allowance in its cost-of-service rates. The D.C. Circuit held that FERC had failed to demonstrate that the inclusion of an income tax allowance in the pipeline’s rates would not lead to an over-recovery of costs attributable to regulated service. The D.C. Circuit instructed FERC on remand to fashion a remedy to ensure that the pipeline’s rates do not allow it to over-recover its costs. Following the D.C. Circuit’s decision, FERC issued its Revised Policy Statement on Treatment of Income Taxes in

Docket No. PL17-1-000 on March 15, 2018 (the “Revised Policy Statement”), which eliminates the recovery of an income tax allowance by MLP oil and gas pipelines in cost-of-service-based rates. FERC directed MLP oil pipelines to reflect the elimination of the income tax allowance in their Form No. 6, page 700 reporting, although FERC did not make an adjustment to pipeline industry costs to reflect the elimination of the income tax allowance in its December 17, 2020 order adopting a revised indexing adjustment for the five-year period starting July 1, 2021. FERC also stated that it would address income tax allowances for other “pass-through” entities that are not MLPs in future proceedings. On July 18, 2018, FERC clarified in Order No. 849, which was directed at gas pipelines, its general disallowance of MLP income tax allowance recovery by providing that an MLP will not be precluded in a future proceeding from making a claim that it is entitled to an income tax allowance based on a demonstration that its recovery of an income tax allowance does not result in a “double-recovery of investors’ income tax costs.” While FERC has not taken industry-wide action on oil pipeline rates, FERC could require oil pipelines to revise their rates in individual proceedings (including initial rate filing or complaint proceedings) or through other action. To the extent that we charge cost-of-service based rates, those rates could be affected by any changes in FERC’s income tax allowance policy to the extent our rates are subject to complaint or challenge by FERC acting on its own initiative, or to the extent that we propose new cost-of-service rates or changes to our existing rates.

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

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

Shippers can always file a complaint with FERC or a state agency challenging rates or conditions of services. If they were successful, FERC or a state agency could order reparations or service changes.

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

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

On July 1, 2020, two new final rules issued by PHMSA on October 1, 2019 became effective. The two rules impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond HCAs to pipelines in Moderate Consequence Areas (“MCAs”). It also includes requirements to reconfirm maximum allowable operating pressure (“MAOP”), report MAOP exceedances, consider seismicity as a risk factor in integrity management and use certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. There are new MCAs on some of our gas transmission lines; however, these lines are already fully inspected due to HCAs on the lines, so these new areas do not impact our inspection or maintenance programs on the lines. On the liquid side, all onshore lines have leak detection and are currently inspected under our Integrity Management Program, so there are no new inspections required. Some of our product lines may need to be made piggable; however, the full evaluations of those lines have not been completed to fully understand potential cost implications.

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

Certain aspects of our offshore pipeline operations, such as new construction and modification, are also regulated by BOEM, BSEE and the U.S. Coast Guard. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order

suspending new fossil fuel leasing and permitting on federal lands for 60 days, which may cover our offshore pipeline permits. In addition, on January 27, 2021, President Biden issued an Executive Order on climate directing the Department of the Interior to pause on entering into new oil and natural gas leases on public lands or offshore waters “to the extent possible” and launch a review of all existing leasing and permitting practices related to fossil fuel development on public lands and waters. If our customers are unable to secure leases, permits, sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our pipeline and terminal systems or reduced rates under renegotiated transportation or storage agreements. We are still evaluating the effects of the recent order on our operations and our customers’ operations, but our inability and our customers’ inability to secure required permits could adversely affect our business, financial condition, results of operation or cash flows, including our ability to make cash distributions to our unitholders.

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

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

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

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

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

RDS has publicly recognized that GHG emissions are contributing to the warming of the climate system and stated its support for the goals of the Paris Agreement. In 2017, Shell announced its “Net Carbon Footprint” ambition, and subsequently issued the Shell Energy Transition Report in 2018 and the Shell Sustainability Report in 2020, describing, among other things, Shell’s

approach to the energy transition and its plans to lower its overall carbon footprint through various measures. Shell is seeking cost-effective ways to manage GHG emissions in line with its “Net Carbon Footprint” ambition and intends to enable customers to make lower-carbon-intensity choices by bringing lower-carbon-intensity products to the market aligned with demand. Shell also aims to reduce the GHG intensity of its portfolio while continuing to work on improving the energy efficiency of its existing operations. Moreover, Shell has a climate change risk management structure in place, which is supported by standards, policies and controls, and actively monitors the GHG emissions of all its assets, including us, as well as the lifecycle of its products, to quantify future regulatory costs related to GHG or other climate-related policies. As a member of the RDS group of companies, we participate in and support these various measures, policies and initiatives and, as such, are evaluating the appropriate integration of these practices and procedures into our own operating framework.

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

In an April 15, 2020 ruling, amended May 11, 2020, the U.S. District Court for the District of Montana issued an order invalidating the U.S. Army Corps of Engineers (the “Corps”) 2017 reissuance of Nationwide Permit 12 (“NWP 12”), the general permit governing dredge-and-fill activities for pipeline and other utility line construction projects, to the extent it was used to authorize construction of new oil and gas pipelines. Environmental groups had alleged that the Corps failed to consult with federal wildlife agencies as required by the Endangered Species Act. The court’s decision vacated NWP 12 until the Corps completes consultation with the applicable federal wildlife agencies. On July 6, 2020, the U.S. Supreme Court granted in part and denied in part the Corps’ request to stay the U.S. District Court’s decision. The Supreme Court’s decision allows the use of NWP 12 as to construction of new oil and gas pipelines, pending the outcome of the appeal to the U.S. Court of Appeals for the Ninth Circuit and any subsequent petition for review to the U.S. Supreme Court. In addition, in January 2021, the EPA and the Corps issued a final rule reissuing and restricting NWP 12 to oil and gas pipelines. However, the NWP rulemaking is among the agency actions listed for review in accordance with the January 20, 2021 Executive Order: “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.” Limitations on the use of NWP 12 may make it more difficult to permit our projects and could cause us to lose potential and current customers and limit our growth and revenue.

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

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

response to economic re-openings, the efficacy and timely distributions of available vaccines and the extent and overall economic effects of the continuing governmental response to the pandemic, including any lockdowns, other restrictions or a general slowdown of the reopening process in the affected areas.

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

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

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

 

In general terms, the prices of crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors impacting crude oil prices include worldwide economic conditions (such as the continuing COVID-19 pandemic and its effects, including the response of various governments to the pandemic); weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported crude oil; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional basis differentials and premiums; actions by OPEC and other oil-producing nations; the price and availability of alternative energy, including alternative energy which may benefit from government subsidies; the effect of energy conservation measures; the strength of the U.S. dollar; the nature and extent of governmental regulation and taxation; and the anticipated future prices of crude oil and other commodities.

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

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.

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

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

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.

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

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

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

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

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

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

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

We 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.

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

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

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

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

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.

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.

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

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

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

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

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

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

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.

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

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

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

Notable 2020 and certain anticipated 2021 impacts to net income and cash available for distribution (“CAFD”) include:

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

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

Our operations and maintenance expenses consist primarily of:

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

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

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

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

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

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

During the second quarter of 2019, Zydeco recontracted previously expired volumes under certain of its throughput and deficiency agreements (“T&D agreements”). Although we replaced the volumes, the rates under the new T&D agreements were lower than those previously contracted. Two of these T&D agreements expired in the fourth quarter of 2020, and have not been replaced. The T&D agreements that expired accounted for less than 10% of our revenue for 2020. There are several ways in which this revenue could be replaced in the future, such as through re-contracting or spot shipments, the outcome of which will be dependent on market and customer dynamics.

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

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

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

Offshore crude transportation volumes were down in 2020 versus 2019 due to planned maintenance activities, storm activity in the Gulf of Mexico and delays to new wells or well work overs due to storm activity.

Onshore terminaling and storage volumes were down in 2020 versus 2019 due to lower volume throughput from our customers as a result of the demand destruction due to the COVID-19 pandemic.

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

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

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

refile their 2019 FERC Form No. 6 either revising their ROE to include the CAPM model or stating that they used the DCF model.

As was the case with the Revised Policy Statement, FERC did not propose any industry-wide action regarding review of rates for crude oil and liquids pipelines in its July 2018 issuances. MLP owned crude oil and liquids pipelines are required to report Page 700 information in their FERC Form 6 annual reports. Both the elimination of the income tax allowance, as well as the corporate income tax reduction enacted as part of the TCJA, were considered by FERC in the order on the five-year review that was issued on December 17, 2020, although FERC declined in that order to incorporate the effect of the income tax allowance elimination in setting the new indexing adjustment. FERC will also implement the elimination of the income tax allowance in proceedings involving review of initial cost-of-service rates, rate changes and rate complaints. For crude oil and liquids pipelines owned by non-MLP partnerships and other pass-through businesses, FERC will address such issues as they arise in subsequent proceedings.

On June 18, 2020, FERC issued a NOI as Docket No. RM20-14-000 regarding the five-year review of the oil pipeline rate index formula. FERC proposed a new formula of Producer Price Index for Finished Goods (“PPI-FG”) plus 0.09% based on its review of industry data provided in the annual FERC Form 6 reports from 2014 through 2019. The NOI proposal, which would take effect in July 2021, would change the current five-year formula from PPI-FG plus 1.23%. FERC invited comments regarding its proposal and any alternative methodologies for calculating the index level, including issues such as different data trimming methodologies and whether it should reflect the effects of any cost-of-service policy changes in the calculation of the index level. Comments on the NOI were filed by multiple parties by August 17, 2020, and reply comments were filed by September 11, 2020. After reviewing the comments and reply comments by interested parties, FERC issued an order on December 17, 2020 adopting a new formula of PPI-FG plus 0.78% for the next five-year period commencing on July 1, 2021. This order is subject to rehearing and possible judicial review.

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

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

On October 1, 2019, PHMSA issued three new final rules. One rule establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond HCAs to pipelines in Moderate Consequence

Areas (“MCAs”). It also includes requirements to reconfirm maximum allowable operating pressure (“MAOP”), report MAOP exceedances, consider seismicity as a risk factor in integrity management and use certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events and adds a requirement to make all onshore lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. There are new MCAs on some of our gas transmission lines; however, these lines are already fully inspected due to HCAs on the lines, so these new areas do not impact inspection or maintenance programs on the lines. On the liquids side, all onshore lines have leak detection and are currently inspected under our Integrity Management Program, so there are no new inspections required. Some of our product lines may need to be made piggable; however, the full evaluations of those lines have not been completed to understand potential cost implications.

 

Transportation services revenue decreased primarily due to the ongoing effects of the COVID-19 pandemic on the crude and refined products operating environment and related prices in 2020, as well as lower rates on the Zydeco committed contracts in 2020 as compared to 2019. Additionally, the impact from planned turnaround activities, as well as the impact of storms and the related shut-ins of production, was higher in 2020 than 2019. Further, deficiency credits were primarily deferred in 2020 as compared to deficiency credits being utilized and recognized in revenue in 2019. These decreases were partially offset by new volumes brought online at NaKika and Odyssey, as well as achieving regulatory approval for an increase in tariffs on Delta in 2020.

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

Lease revenue was relatively consistent in 2020 and 2019.

Product revenue decreased as a result of lower sales of allowance oil for certain of our onshore and offshore crude pipelines in 2020 as compared to 2019.

Operations and maintenance expenses increased mainly as a result of higher maintenance costs related to the Norco Assets

in 2020 as compared to 2019.

General and administrative expense decreased primarily due to reduced contractor spend in 2020 compared to 2019, partially offset by higher severance charges in 2020.

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

changes in property tax appraisal estimates.

Cost of product sold decreased as a result of lower sales of allowance oil coupled with the lower cost environment in 2020 as compared to 2019, which was partially offset by a higher net realizable value adjustment on allowance oil inventory in 2020.

connection with the Norco Assets. Interest expense decreased by $3 million due to lower interest rates in 2020 versus 2019 resulting from the ongoing effects of the COVID-19 pandemic on market interest rates, which was partially offset by additional borrowings outstanding under our credit facilities during 2020 versus 2019.

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

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

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

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

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

As of December 31, 2020 and 2019, we were in compliance with the covenants contained in our credit facilities, and Zydeco was in compliance with the covenants contained in the 2019 Zydeco Revolver.

We incurred capital expenditures of $22 million, $35 million and $51 million for 2020, 2019 and 2018, respectively. The decrease in capital expenditures from 2019 to 2020 is primarily due to completion of the Houma tank expansion and directional drill projects for Zydeco. Further, we had no contributions to investment in 2020.

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

Pecten’s maintenance capital expenditures for 2020 were $1 million, and we expect Pecten’s maintenance capital expenditures to be approximately $2 million in 2021 related to a Lockport tank maintenance project and various improvements on Delta.

Triton’s maintenance capital expenditures for 2020 were $1 million, and we expect Triton’s maintenance capital expenditures to be approximately $4 million in 2021. The expected 2021 spend is related to Des Plaines fire prevention and protection upgrades, Seattle terminal dock line repair and replacement and routine maintenance at the various terminals.

We do not expect any maintenance capital expenditures for Sand Dollar or Odyssey in 2021.

We anticipate that both maintenance and expansion capital expenditures for 2021 will be funded primarily with cash from operations.

 

On September 1, 2016, which is the in-service date of the capital lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective. The tariff will be reviewed annually and the rate updated based on FERC’s indexing adjustment to rates effective July 1 of each year. Effective July 1, 2020 there was an approximate 2% increase to this rate based on FERC’s indexing adjustment. The initial term of the agreement is ten years with automatic one-year renewal terms with the option to cancel prior to each renewal period.

Key estimates related to long-lived assets include useful lives, recoverability of carrying values and existence of any retirement obligations. Such estimates could be significantly modified. The carrying values of long-lived assets could be impaired by significant changes or projected changes in supply and demand fundamentals of oil, natural gas, refinery gas or refined products (which could have a negative impact on operating rates or margins), new technological developments, new competitors, adverse changes associated with the 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. Actual impairment losses incurred could vary significantly from amounts estimated. Long-lived assets assessed for impairment are grouped at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Additionally, future events could cause us to conclude that impairment indicators exist and that associated long-lived assets of our businesses are impaired. Any resulting impairment loss could have a material adverse impact on our financial condition and results of operations.

The fair value of the Permian Basin investment was determined based upon applying both the discounted cash flow method, which is an income approach, and a market approach. The discounted cash flow fair value estimate is based on known and knowable information at the measurement date. The significant assumptions that were used to develop the estimate of fair value under the discounted cash flow method include management's best estimates of the expected future cash flows, including prices and volumes, the weighted average cost of capital and the long-term growth rate. If the discount rate was increased by 1%, the concluded fair value would decrease by $5 million and would remain in excess of carrying value. If the long-term growth rate was decreased by 1%, the concluded fair value would decrease by $4 million and would remain in excess of carrying value. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

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

As a result of FERC regulations, revenues we collect may be subject to refund. We establish reserves for these potential refunds based on actual expected refund amounts on the specific facts and circumstances. We had no reserves for potential refunds as of December 31, 2020 and 2019.

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.

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.

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

 

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