SHELL MIDSTREAM PARTNERS Management's Discussion and Analysis of Financial Condition and Results of Operations are the analysis of our financial performance, financial condition and significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report. It should also be read together with "Risk factors" and "Cautionary Statement Regarding Forward-Looking Statements" in this report. OnJanuary 1, 2019 , we adopted Topic 842, Leases ("the lease standard") by applying the modified retrospective approach. Results for reporting periods beginning afterJanuary 1, 2019 and balances atDecember 31, 2019 are presented in accordance with the lease standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historical accounting under previous generally accepted accounting principles inthe United States ("GAAP"). See Note 9 - Leases in the Notes to Consolidated Financial Statements included in Part II, Item 8. Partnership Overview We own, operate, develop and acquire pipelines and other midstream assets and logistic assets. As ofDecember 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 toGulf Coast and Midwest refining markets and deliver refined products from those markets to major demand centers and (b) storage tanks and financing receivables that are secured by pipelines, storage tanks, docks, truck and rail racks and other infrastructure used to stage and transport intermediate and finished products. Our assets also include interests in entities that own natural gas and refinery gas pipelines that transport offshore natural gas to market hubs and deliver refinery gas from refineries and plants to chemical sites along theGulf Coast . For a description of our assets, please see Part I, Item 1 - Business and Properties of this report. 2020 developments include: -Purchase and Sale Agreement. OnApril 1, 2020 , we closed the following transactions (collectively referred to as the "April 2020 Transaction") pursuant to the Purchase and Sale Agreement dated as ofFebruary 27, 2020 (the "Purchase and Sale Agreement") by and among the Partnership,Triton West LLC ("Triton"), SPLC,Shell GOM Pipeline Company LLC ("SGOM"),Shell Chemical LP ("Shell Chemical") andEquilon Enterprises LLC d/b/aShell Oil Products US ("SOPUS"): i.We acquired 79% of the issued and outstanding membership interests inMattox Pipeline Company LLC from SGOM (the "Mattox Transaction"). ii.SOPUS and Shell Chemical transferred to Triton, as a designee of the Partnership, certain logistics assets at theShell Norco Manufacturing Complex located inNorco, Louisiana , which are comprised of crude, chemicals, intermediate and finished product pipelines, storage tanks, docks, truck and rail racks and supporting infrastructure (such assets, the "Norco Assets" and such transaction, the "Norco Transaction"). -Partnership Interests Restructuring Agreement. OnApril 1, 2020 , simultaneously with the closing of the transactions contemplated by the Purchase and Sale Agreement, we also closed the transactions contemplated by the Partnership Interests Restructuring Agreement with our general partner, dated as ofFebruary 27, 2020 (the "Partnership Interests Restructuring Agreement"), eliminating all incentive distribution rights ("IDRs") and converting the economic general partner interest in the Partnership into a non-economic general partner interest (the "GP/IDR Restructuring"). As consideration for the transactions contemplated by the Purchase and Sale Agreement and the Partnership Interests Restructuring Agreement, SPLC received 160,000,000 newly issued common units, plus 50,782,904 Series A perpetual convertible preferred units (the "Series A Preferred Units"). Our general partner (or its assignee) has also agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of theApril 2020 Transaction, in an amount of$20 million per quarter for four consecutive fiscal quarters, beginning with the distribution made with respect to the second quarter of 2020. Refer to Note 3 - Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements included in Part II, Item 8 for more details. We generate revenue from the transportation, terminaling and storage of crude oil, refined products, and intermediate and finished products through our pipelines, storage tanks, docks, truck and rail racks, generate income from our equity and other investments, and generate interest income from financing receivables on the Norco Assets. Our revenue is generated from customers in the same industry, our Parent's affiliates, integrated oil companies, marketers and independent exploration, production and refining companies primarily within theGulf Coast region ofthe United States . We generally do not own any of the crude oil, refinery gas or refined petroleum products we handle, nor do we engage in the trading of these commodities. We 52 --------------------------------------------------------------------------------
therefore have limited direct exposure to risks associated with fluctuating commodity prices, although these risks indirectly influence our activities and results of operations over the long-term.
Notable 2020 and certain anticipated 2021 impacts to net income and cash available for distribution ("CAFD") include:
•Hurricanes. As a result of several hurricanes, we incurred an impact of approximately$20 million to net income and CAFD in the latter half 2020. Certain producers in theGulf of Mexico elected to shut-in and evacuate as a safety precaution, while others were forced to shut-in or curtail production due to onshore closures. Further, certain onshore assets were impacted by power outages related to the storms. There was no material impact to our people or assets as a result of the storms. •Planned Turnarounds. Certain connected producers had planned turnarounds during 2020. As a result, the impact to net income and CAFD from this turnaround activity was approximately$15 million for the year ended 2020. Further, we anticipate an impact of approximately$10 million to net income and CAFD from planned turnaround activity in 2021. The broader market environment for our customers was challenging in 2019 and continued to be challenging during 2020 given the continuing effects of the COVID-19 pandemic, which has impacted worldwide demand for oil and gas and increased downward pressure on oil prices. The responses of oil and gas producers to the lower demand for, and price of, oil and natural gas are constantly evolving and remain uncertain. The master limited partnership ("MLP") market has also changed significantly, as capital for high growth fueled by dropdown activity continues to be constrained. We are fortunate to have the support of RDS, who has provided us favorable loan and equity terms, allowing us flexibility to acquire high quality assets from our affiliates. While we expect to retain this flexibility, we anticipate continuing to moderate inorganic growth in our asset base and focusing on the sustainable operation of our core assets, cash preservation and the organic growth of our business in 2021. Executive Overview Net income was$556 million and net income attributable to the Partnership was$543 million in 2020. We generated cash from operations of$650 million . As ofDecember 31, 2020 , we had cash and cash equivalents of$320 million , total debt of$2,692 million and unused capacity under our revolving credit facilities of$896 million . Our 2020 operations and strategic initiatives demonstrated our continuing focus on our business strategies: •Maintain operational excellence through prioritization of safety, reliability and efficiency; •Enhanced focus on cash optimization and reduced discretionary project spend; •Focus on advantageous commercial agreements with creditworthy counterparties to enhance financial results and deliver reliable distribution growth over the long-term; and •Optimize existing assets and pursue organic growth opportunities. How We Evaluate Our Operations Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) revenue (including pipeline loss allowance ("PLA") from contracted capacity and throughput); (ii) operations and maintenance expenses (including capital expenses); (iii) Adjusted EBITDA (defined below); and (iv) CAFD. Contracted Capacity and Throughput The amount of revenue our assets generate primarily depends on our transportation and storage services agreements with shippers and the volumes of crude oil, refinery gas and refined products that we handle through our pipelines, terminals and storage tanks. 53 -------------------------------------------------------------------------------- The commitments under our transportation, terminaling and storage services agreements with shippers and the volumes we handle in our pipelines and storage tanks are primarily affected by the supply of, and demand for, crude oil, refinery gas, natural gas and refined products in the markets served directly or indirectly by our assets. This supply and demand is impacted by the market prices for these products in the markets we serve. The COVID-19 pandemic continues to cause significant disruptions in theU.S. economy and financial and energy markets, including substantial demand destruction in the oil and gas markets. Responses of oil and gas producers to the lower demand for, and price of, oil and natural gas are constantly evolving and unpredictable, but further or continued decreases in demand (including due to renewed economic shutdowns and restrictions in response to increased COVID-19 infection rates) could force producers to shut-in certain wellheads or otherwise cease or curtail their operations. It also could reduce the volumes running through our pipelines and terminals.
We utilize the commercial arrangements we believe are the most prudent under the market conditions to deliver on our business strategy. The results of our operations will be impacted by our ability to:
•maintain utilization of and rates charged for our pipelines and storage facilities; •utilize the remaining uncommitted capacity on, or add additional capacity to, our pipeline systems; •increase throughput volumes on our pipeline systems by making connections to existing or new third-party pipelines or other facilities, primarily driven by the anticipated supply of, and demand for, crude oil and refined products; and •identify and execute organic expansion projects.
Operations and Maintenance Expenses
Our operations and maintenance expenses consist primarily of:
•labor expenses (including contractor services);
•insurance costs (including coverage for our consolidated assets and operated
joint ventures);
•utility costs (including electricity and fuel);
•repairs and maintenance expenses; and
•major maintenance costs (related to the terminaling service agreements of the
Norco Assets, which are expensed as incurred because the Partnership does not
own the related assets).
Certain costs naturally fluctuate based on throughput volumes and the grades of
crude oil and types of refined products we handle, whereas other costs generally
remain stable across broad ranges of throughput and storage volumes, but can
vary depending upon the level of both planned and unplanned maintenance activity
in the particular period. Our maintenance activity can be impacted by events
such as turnarounds, asset integrity work and storms.
Our management seeks to maximize our profitability by effectively managing
operations and maintenance expenses. For example, our property and business
interruption insurance is provided by a wholly owned subsidiary of Shell, which
results in cost savings and improved coverage. Further, we, along with our
Parent, are currently undertaking an initiative to reduce operational costs. We
expect that some of these activities, such as re-scoping and/or deferring
projects, evaluating third-party service contracts and reducing the use of
contractors, will directly benefit our assets and their contribution to our net
income. Other activities, such as the streamlining of structure and processes at
the Parent level, will result in a reduction of certain costs and fees for which
we reimburse and pay SPLC. While cost effectiveness has always been a focus of
the business, it is of increased importance given the current operating
environment.
Adjusted EBITDA and Cash Available for Distribution
Adjusted EBITDA and CAFD have important limitations as analytical tools because
they exclude some, but not all, items that affect net income and net cash
provided by operating activities. You should not consider Adjusted EBITDA or
CAFD in isolation or as a substitute for analysis of our results as reported
under GAAP. Additionally, because Adjusted EBITDA and CAFD may be defined
differently by other companies in our industry, our definition of Adjusted
EBITDA and CAFD may not be comparable to similarly titled measures of other
companies, thereby diminishing their utility.
The GAAP measures most directly comparable to Adjusted EBITDA and CAFD are net
income and net cash provided by operating activities. Adjusted EBITDA and CAFD
should not be considered as an alternative to GAAP net income or net cash
provided by operating activities. Please refer to "Results of Operations -
Reconciliation of Non-GAAP Measures" for the reconciliation of GAAP measures net
income and cash provided by operating activities to non-GAAP measures Adjusted
EBITDA and CAFD.
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We define Adjusted EBITDA as net income before income taxes, net interest
expense, gain or loss from dispositions of fixed assets, allowance oil reduction
to net realizable value, loss from revision of asset retirement obligation, and
depreciation, amortization and accretion, plus cash distributed to us from
equity method investments for the applicable period, less equity method
distributions included in other income and income from equity method
investments. We define Adjusted EBITDA attributable to the Partnership as
Adjusted EBITDA less Adjusted EBITDA attributable to noncontrolling interests
and Adjusted EBITDA attributable to Parent.
We define CAFD as Adjusted EBITDA attributable to the Partnership less
maintenance capital expenditures attributable to the Partnership, net interest
paid by the Partnership, cash reserves, income taxes paid and Series A Preferred
Unit distributions, plus net adjustments from volume deficiency payments
attributable to the Partnership, reimbursements from Parent included in
partners' capital, principal and interest payments received on financing
receivables and certain one-time payments received. CAFD will not reflect
changes in working capital balances.
The definition of CAFD was updated for the second quarter of 2020 due to the
closing of the April 2020 Transaction, which resulted in part in the transfer of
the Norco Assets to be accounted for as a failed sale leaseback under the lease
standard. As a result, the Partnership recognized financing receivables from
SOPUS and Shell Chemical. These assets impact CAFD since principal payments on
the financing receivables are not included in net income. As a result, such
principal and interest payments on the financing receivables have been included
as an adjustment to CAFD since the second quarter of 2020. Also as partial
consideration for the April 2020 Transaction, SPLC received 50,782,904 Series A
Preferred Units. The distributions on these Series A Preferred Units have been
deducted from CAFD since the second quarter of 2020.
We believe that the presentation of these non-GAAP supplemental financial
measures provides useful information to management and investors in assessing
our financial condition and results of operations.
Adjusted EBITDA and CAFD are non-GAAP supplemental financial measures that
management and external users of our consolidated financial statements, such as
industry analysts, investors, lenders and rating agencies, may use to assess:
•our operating performance as compared to other publicly-traded partnerships in
the midstream energy industry, without regard to historical cost basis or, in
the case of Adjusted EBITDA, financing methods;
•the ability of our business to generate sufficient cash to support our decision
to make distributions to our unitholders;
•our ability to incur and service debt and fund capital expenditures; and
•the viability of acquisitions and other capital expenditure projects and the
returns on investment of various investment opportunities.
Factors Affecting Our Business and Outlook
We believe key factors that impact our business are the supply of, and demand
for, crude oil, natural gas, refinery gas and refined products in the markets in
which our business operates. We also believe that our customers' requirements,
competition and government regulation of crude oil, refined products, natural
gas and refinery gas play an important role in how we manage our operations and
implement our long-term strategies. In addition, acquisition opportunities,
whether from Shell or third parties, and financing options, will also impact our
business. These factors are discussed in more detail below.
Changes in Crude Oil Sourcing and Refined Product Demand Dynamics
To effectively manage our business, we monitor our market areas for both
short-term and long-term shifts in crude oil and refined products supply and
demand. Changes in crude oil supply such as new discoveries of reserves,
declining production in older fields, operational impacts at producer fields and
the introduction of new sources of crude oil supply affect the demand for our
services from both producers and consumers. In addition, general economic, broad
market and worldwide health considerations, including the continuing effects of
the COVID-19 pandemic, can also affect sourcing and demand dynamics for our
services.
One of the strategic advantages of our crude oil pipeline systems is their
ability to transport attractively priced crude oil from multiple supply markets
to key refining centers along the Gulf Coast . Our crude oil shippers
periodically change the relative mix of crude oil grades delivered to the
refineries and markets served by our pipelines. They also occasionally choose to
store crude longer term when the forward price is higher than the current price
(a "contango market"). While these changes in the sourcing patterns of crude oil
transported or stored are reflected in changes in the relative volumes of crude
oil by type handled by our pipelines, our total crude oil transportation revenue
is primarily affected by changes in overall crude oil supply and demand
dynamics, including the demand destruction resulting from the COVID-19 pandemic,
as well as U.S. exports.
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Similarly, our refined products pipelines have the ability to serve multiple
major demand centers. Our refined products shippers periodically change the
relative mix of refined products shipped on our refined products pipelines, as
well as the destination points, based on changes in pricing and demand dynamics.
While these changes in shipping patterns are reflected in relative types of
refined products handled by our various pipelines, our total product
transportation revenue is primarily affected by changes in overall refined
products supply and demand dynamics, including the continuing effects of the
COVID-19 pandemic. Demand can also be greatly affected by refinery performance
in the end market, as refined products pipeline demand will increase to fill the
supply gap created by refinery issues.
We can also be constrained by asset integrity considerations in the volumes we
ship. We may elect to reduce cycling on our systems to reduce asset integrity
risk, which in turn would likely result in lower revenues.
As these supply and demand dynamics shift, we anticipate that we will continue
to actively pursue projects that link new sources of supply to producers and
consumers and to create new services or capacity arrangements that meet customer
requirements. For example, production from Shell's Appomattox platform in the
Gulf of Mexico , which came online during 2019, tied into our existing Proteus
and Endymion systems to bring crude onshore. Similarly, we expect to continue
extending our corridor pipelines to provide developing growth regions in the
Gulf of Mexico with access via our existing corridors to onshore refining
centers and market hubs. By way of example, in the latter part of 2019 we
announced a solicitation of interest for a potential expansion of the Mars
system to address growing production volumes in the Gulf of Mexico regions
served by Mars. It is expected that the project would be fully operational with
incremental growth volumes arriving into the Mars system in 2022. We believe
this strategy will allow our offshore business to grow profitably throughout
demand cycles.
Changes in Customer Contracting
We generate a portion of our revenue under long-term transportation service
agreements with shippers, including ship-or-pay agreements and life-of-lease
transportation agreements, some of which provide a guaranteed return, and
storage service agreements with marketers, pipelines and refiners. Historically,
the commercial terms of these long-term transportation and storage service
agreements have substantially mitigated volatility in our financial results by
limiting our direct exposure to reductions in volumes due to supply or demand
variability. Our business could be negatively affected if we are unable to renew
or replace our contract portfolio on comparable terms, by sustained downturns or
sluggishness in commodity prices, or the economy in general (as with the
continuing effects of the COVID-19 pandemic, including the impacts on the demand
for oil and gas), and is impacted by shifts in supply and demand dynamics, the
mix of services requested by the customers of our pipelines, competition and
changes in regulatory requirements affecting our operations. Our business can
also be impacted by asset integrity or customer interruptions and natural
disasters or other events that could lead customers to invoke force majeure or
other defenses to avoid contractual performance.
During the second quarter of 2019, Zydeco recontracted previously expired
volumes under certain of its throughput and deficiency agreements ("T&D
agreements"). Although we replaced the volumes, the rates under the new T&D
agreements were lower than those previously contracted. Two of these T&D
agreements expired in the fourth quarter of 2020, and have not been replaced.
The T&D agreements that expired accounted for less than 10% of our revenue for
2020. There are several ways in which this revenue could be replaced in the
future, such as through re-contracting or spot shipments, the outcome of which
will be dependent on market and customer dynamics.
The market environment at any given time will dictate the rates, terms and
duration of agreements that shippers are willing to enter into, as well as the
contracts that best satisfy the needs of our business. As we have grown and
diversified our business over the past several years, and as recently as the
second quarter of 2020 with the April 2020 Transaction, we have benefited from
shifting reliance away from the results of any one asset. While Zydeco continues
to serve an important market, and we strive to maximize the long-term value of
the system to both shippers and the pipeline, we will continue to diversify our
risk across products, customers and geographies.
Changes in Commodity Prices and Customers' Volumes
Crude oil prices have fluctuated significantly over the past few years, often
with drastic moves in relatively short periods of time. During 2020, the demand
for, and price of, oil and natural gas decreased significantly due to the
continuing effects of the COVID-19 pandemic and the resulting governmental
regulations and travel restrictions aimed at slowing the spread of the virus.
The current global geopolitical and economic uncertainty continues to contribute
to future volatility in financial and commodity markets. Our direct exposure to
commodity price fluctuations is limited to the PLA provisions in our tariffs.
Indirectly, global demand for refined products and chemicals could impact our
terminal operations and refined products and refinery gas pipelines, as well as
our crude pipelines that feed U.S. manufacturing demand. Likewise, changes in
the global market for crude oil could affect our crude oil pipeline and
terminals and require expansion capital expenditures to reach
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growing export hubs. Demand for crude oil, refined products and refinery gas may
decline in the areas we serve as a result of decreased production by our
customers, depressed commodity prices, decreased third-party investment in the
industry, increased competition and other adverse economic factors such as the
current COVID-19 pandemic, which affect the exploration, production and refining
industries. Although we have seen the earlier depressed demand due to the
pandemic for crude oil and refined products level off, further increases in
COVID-19 infection rates could have additional negative impacts on demand. This
could force producers to shut-in certain wellheads or otherwise cease or curtail
their operations. It also could reduce the volumes running through our pipelines
and terminals. However, fixed contracts with volume minimums and demand for
tanks for storage are expected to moderate any impact on our terminaling and
storage service revenue.
Certain of our assets benefit from long-term fee-based arrangements and are
strategically positioned to connect crude oil volumes originating from key
onshore and offshore production basins to the Texas and Louisiana refining
markets, where demand for throughput has remained strong. Historically, we have
not experienced a material decline in throughput volumes on our crude oil
pipeline systems as a result of lower crude oil prices. However, if crude oil
prices remain at lower levels for a sustained period due to the continuing
effects of the COVID-19 pandemic or other factors, we will continue to see a
reduction in our transportation volumes if production coming into our systems is
deferred and our associated allowance oil sales decrease. Our customers may also
experience liquidity and credit problems or other unexpected events, which could
cause them to defer development or repair projects, avoid our contracts in
bankruptcy, invoke force majeure clauses or other defenses to avoid contractual
performance or renegotiate our contracts on terms that are less attractive to us
or impair their ability to perform under our contracts.
Our throughput volumes on our refined products pipeline systems depend primarily
on the volume of refined products produced at connected refineries and the
desirability of our end markets. These factors in turn are driven by refining
margins, maintenance schedules and market differentials. Refining margins depend
on the cost of crude oil or other feedstocks and the price of refined products,
which have decreased significantly during 2020. These margins are affected by
numerous factors beyond our control, including the domestic and global supply of
and demand for crude oil and refined products. Our refined products pipelines
are continuing to experience demand destruction in the near term due to the
COVID-19 pandemic, which has resulted in a significant decrease in consumer
demand for refined products such as gasoline and jet fuel.
Other Changes in Customers' Volumes
Onshore crude transportation volumes were down in 2020 versus 2019 due to demand
destruction resulting from the COVID-19 pandemic.
Offshore crude transportation volumes were down in 2020 versus 2019 due to
planned maintenance activities, storm activity in the
Onshore terminaling and storage volumes were down in 2020 versus 2019 due to lower volume throughput from our customers as a result of the demand destruction due to the COVID-19 pandemic. Major Maintenance Projects At the end of 2019, we finalized a directional drill project on the Zydeco pipeline system to address soil erosion over a two-mile section of our 22-inch diameter pipeline under theAtchafalaya River and Bayou Shaffer inLouisiana (the "directional drill project"). Zydeco incurred approximately$42 million in maintenance capital expenditures for the total directional drill project. In connection with the acquisitions of additional interests in Zydeco, SPLC agreed to reimburse us against our proportionate share of certain costs and expenses with respect to this project. Costs incurred and reimbursed during 2020 were not material. During 2020, we incurred costs related to theBessie Heights project ("Bessie Heights "), which is a directional drill project on the Zydeco pipeline system to replace an exposed and suspended 22-inch diameter pipe in the low-lying marsh area betweenBird Island andBridge City, Texas , as well as to replace lap welded pipe below theNeches River . Zydeco incurred approximately$13 million in maintenance capital expenditures in 2020 to complete the project. Any remaining spend in the first quarter of 2021 is not expected to be material. For expected capital expenditures in 2020, refer to Capital Resources and Liquidity - Capital Expenditures and Investments. Major Expansion Projects On Mars, we announced in the latter part of 2019 a solicitation of interest for a potential expansion of the system. Letters of intent are in place, and we are now progressing definitive agreements with producers and expect to complete them by the end of the first quarter of 2021. SPLC has elected to fund the installation of the equipment necessary to enable greater throughput 57 -------------------------------------------------------------------------------- volumes on the system, but the revenue associated with increased throughput volumes will benefit Mars. It is expected that the project would be fully operational with incremental growth volumes arriving into the Mars system in 2022. Customers We transport and store crude oil, refined products, natural gas and refinery gas for a broad mix of customers, including producers, refiners, marketers and traders, and are connected to other crude oil and refined products pipelines. In addition to serving directly-connectedU.S. Gulf Coast markets, our crude oil and refined products pipelines have access to customers in various regions ofthe United States through interconnections with other major pipelines. Our customers use our transportation and storage services for a variety of reasons. Refiners typically require a secure and reliable supply of crude oil over a prolonged period of time to meet the needs of their specified refining diet and frequently enter into long-term firm transportation agreements to ensure a ready supply of crude oil, rate surety and sometimes sufficient transportation capacity over the life of the contract. Similarly, chemical sites require a secure and reliable supply of refinery gas to crackers and enter into long-term firm transportation agreements to ensure steady supply. Producers of crude oil and natural gas require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity. Marketers and traders generate income from buying and selling crude oil and refined products to capitalize on price differentials over time or between markets. Our customer mix can vary over time and largely depends on the crude oil and refined products supply and demand dynamics in our markets. Refer to Note 14 - Transactions with Major Customers and Concentration of Credit Risk in the Notes to the Consolidated Financial Statements included in Part II, Item 8 for additional information. Competition Our pipeline systems compete primarily with other interstate and intrastate pipelines and with marine and rail transportation. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. For example, newly constructed transportation systems in the onshoreGulf of Mexico region may increase competition in the markets where our pipelines operate. In addition, future pipeline transportation capacity could be constructed in excess of actual demand in the market areas we serve, which could reduce the demand for our services, and could lead to the reduction of the rates that we receive for our services. While we do see some variation from quarter-to quarter resulting from changes in our customers' demand for transportation, this risk has historically been mitigated by the long-term, fixed rate basis upon which we have contracted a substantial portion of our capacity. Our storage terminal competes with surrounding providers of storage tank services. Some of our competitors have expanded terminals and built new pipeline connections, and third parties may construct pipelines that bypass our location. These, or similar events, could have a material adverse impact on our operations. Our refined products terminals generally compete with other terminals that serve the same markets. These terminals may be owned by major integrated oil and gas companies or by independent terminaling companies. While fees for terminal storage and throughput services are not regulated, they are subject to competition from other terminals serving the same markets. However, our contracts provide for stable, long-term revenue, which is not impacted by market competitive forces. Regulation Our assets are subject to regulation by various federal, state and local agencies; for example, our interstate common carrier pipeline systems are subject to economic regulation byFERC . Intrastate pipeline systems are regulated by the appropriate state agency. InMay 2020 , Zydeco, Mars,LOCAP and Colonial filed withFERC to increase rates subject toFERC's indexing adjustment methodology by approximately 2.0% starting onJuly 1, 2020 . Rate complaints are currently pending atFERC inDocket Nos . OR18-7-002, et al. challenging Colonial's tariff rates, its market power and its practices and charges related to transmix and product volume loss. While certain procedural deadlines have been extended as a result of the impact of the COVID-19 pandemic, an initial decision by the administrative law judge in this proceeding is currently scheduled forAugust 2021 . AFERC decision is anticipated by spring 2022. OnMay 21, 2020 ,FERC issued a Policy Statement resolving the Notice of Inquiry ("NOI") in Docket No. PL19-4-000. The Policy Statement revisesFERC'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 58 -------------------------------------------------------------------------------- refile their 2019 FERC Form No. 6 either revising their ROE to include the CAPM model or stating that they used the DCF model. OnJuly 18, 2018 ,FERC issued Order No. 849, which adopts procedures to address the impact of the federal legislation passed onDecember 22, 2017 known as the "Tax Cuts and Jobs Act" ("TCJA") andFERC's Revised Policy Statement on Treatment of Income Taxes in Docket No. PL17-1-000, issued onMarch 15, 2018 (the "Revised Policy Statement").FERC contemporaneously issued the Order on Rehearing in Docket No. PL17-1-000, which affirmsFERC's position in the Revised Policy Statement that eliminated the recovery of an income tax allowance by MLP oil and gas pipelines in cost-of-service-based rates. In Order No. 849, however,FERC has clarified its general disallowance of MLP income tax allowance recovery by providing that an MLP will not be precluded in a future proceeding from making a claim that it is entitled to an income tax allowance.FERC will permit an MLP to demonstrate that its recovery of an income tax allowance does not result in a "double recovery of investors' income tax costs."FERC affirmed Order No. 849 on rehearing onApril 18, 2019 . Parties sought judicial review of the Revised Policy Statement, and that challenge, initially filed inMarch 2019 , was denied by theU.S. Court of Appeals for the D.C. Circuit onAugust 14, 2020 . No further petitions are outstanding on this matter. As was the case with the Revised Policy Statement,FERC did not propose any industry-wide action regarding review of rates for crude oil and liquids pipelines in itsJuly 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 byFERC in the order on the five-year review that was issued onDecember 17, 2020 , althoughFERC 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. OnJune 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 inJuly 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 byAugust 17, 2020 , and reply comments were filed bySeptember 11, 2020 . After reviewing the comments and reply comments by interested parties,FERC issued an order onDecember 17, 2020 adopting a new formula of PPI-FG plus 0.78% for the next five-year period commencing onJuly 1, 2021 . This order is subject to rehearing and possible judicial review. We believe that the recent issuances fromFERC , including the Revised Policy Statement and issuances inJuly 2018 , will not have a material impact on our operations and financial performance. SinceFERC 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 byFERC's decision. For ourFERC -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 toFERC's approval, which are below the cost-of-service rates established byFERC . As such, neither our negotiated nor market-based rate revenue for ourFERC -regulated assets would be subject to the income tax recovery disallowance. Additionally, we have evaluated the impact ofFERC'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. OnOctober 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 ofFERC's Form No. 6. OnFebruary 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 withFERC's simplified and streamlined indexing regime. No further updates are expected on this matter. OnOctober 1, 2019 , PHMSA issued three new final rules. One rule establishes procedures to implement the expanded emergency order enforcement authority set forth in anOctober 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 59 -------------------------------------------------------------------------------- Areas ("MCAs"). It also includes requirements to reconfirm maximum allowable operating pressure ("MAOP"), report MAOP exceedances, consider seismicity as a risk factor in integrity management and use certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events and adds a requirement to make all onshore lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. There are new MCAs on some of our gas transmission lines; however, these lines are already fully inspected due to HCAs on the lines, so these new areas do not impact inspection or maintenance programs on the lines. On the liquids side, all onshore lines have leak detection and are currently inspected under our Integrity Management Program, so there are no new inspections required. Some of our product lines may need to be made piggable; however, the full evaluations of those lines have not been completed to understand potential cost implications. Acquisition Opportunities We may pursue acquisitions of complementary assets from Shell, as well as from third parties. We also may pursue acquisitions jointly with Shell. Given the size and scope of Shell's footprint and its significant ownership interest in us, we expect acquisitions from Shell will be a growth mechanism for the foreseeable future. However, Shell and its affiliates are under no obligation to sell or offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any additional assets from them or to pursue any joint acquisitions with them. We will continue to focus our acquisition strategy on transportation and midstream assets. We believe that we would be well positioned to acquire midstream assets from Shell, as well as from third parties, should such opportunities arise. Identifying and executing acquisitions is a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms or if we incur a substantial amount of debt in connection with the acquisitions, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our available cash. Our ability to obtain financing or access capital markets may also directly impact our ability to continue to pursue strategic acquisitions. The level of current market demand for equity issued by MLPs may make it more challenging for us to fund our acquisitions with the issuance of equity in the capital markets. However, we believe our balance sheet offers us flexibility, providing us other financing options such as hybrid securities, purchases of common units by RDS and debt. While we expect to retain this flexibility, in 2021 we anticipate continuing to moderate inorganic growth in our asset base and focusing on the sustainable operation of our core assets, cash preservation and organic growth of our business. 60 --------------------------------------------------------------------------------
Results of Operations
2020 2019 2018
Revenue $ 481 $ 503 $ 525
Costs and expenses
Operations and maintenance 162 124 162
Cost of product sold 24 36 32
Loss (gain) from revision of ARO and disposition
of fixed assets - 2 (3)
General and administrative 56 60 60
Depreciation, amortization and accretion 50 49 46
Property and other taxes 20 17 16
Total costs and expenses 312 288 313
Operating income 169 215 212
Income from equity method investments 417 373 235
Dividend income from other investments - 14 67
Other income 40 36 31
Investment, dividend and other income 457 423 333
Interest income 23 4 2
Interest expense 93 96 64
Income before income taxes 556 546 483
Income tax expense - - 1
Net income 556 546 482
Less: Net income attributable to noncontrolling
interests 13 18 18
Net income attributable to the Partnership
528$ 464 Preferred unitholder's interest in net income attributable to the Partnership 36 - - General partner's interest in net income attributable to the Partnership 55 147 134 Limited Partners' interest in net income attributable to the Partnership's common unitholders$ 452 $ 381 $ 330 Adjusted EBITDA attributable to the Partnership (1)$ 767 $ 730 $ 616 Cash available for distribution attributable to the Partnership's common unitholders (1)$ 658 $
619
(1) For a reconciliation of Adjusted EBITDA and CAFD attributable to the Partnership to their most comparable GAAP measures, please read "-Reconciliation of Non-GAAP Measures."
61
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Pipeline throughput (thousands of barrels per day) (1) 2020 2019 2018
Zydeco - Mainlines 577 657 623
Zydeco - Other segments 142 267 249
Zydeco total system 719 924 872
Amberjack total system 326 362 324
Mars total system 490 546 516
Bengal total system 429 511 539
Poseidon total system 290 265 235
Auger total system 74 77 58
Delta total system 211 258 228
Na Kika total system 40 39 42
Odyssey total system 119 145 115
Colonial total system 2,349 2,617 2,616
Explorer total system 474 650 649
Mattox total system (2) 71 62 N/A (3)
LOCAP total system 960 1,172 1,228
Other systems 427 348 344
Terminals (4) (5)Revenue per barrel ($ per barrel)
Zydeco total system (6)$ 0.49 $ 0.52 $ 0.74 Amberjack total system (6) 2.37 2.37 2.50 Mars total system (6) 1.35 1.31 1.19 Bengal total system (6) 0.41 0.41 0.34 Auger total system (6) 1.28 1.43 1.34 Delta total system (6) 0.59 0.58 0.57 Na Kika total system (6) 0.91 0.80 0.79 Odyssey total system (6) 0.94 0.92 0.88 Lockport total system (7) 0.23 0.22 0.21 Mattox total system (8) 1.52 N/A (9) N/A (9) (1) Pipeline throughput is defined as the volume of delivered barrels. For additional information regarding our pipeline and terminal systems, refer to Part I, Item I - Business and Properties - Our Assets and Operations. (2) The actual delivered barrels for Mattox are disclosed in the above table for the comparative periods. However, Mattox is billed by monthly minimum quantity per dedication and transportation agreements entered into inApril 2020 . Based on the contracted volume determined in the agreements, the thousands of barrels per day (for revenue calculation purposes) for Mattox are 162 thousands of barrels per day for 2020. (3) Mattox came online during the second quarter of 2019 and therefore there are no volumes presented for 2018. (4) Terminaling throughput is defined as the volume of delivered barrels and storage is defined as the volume of stored barrels. (5) Refinery Gas Pipeline and our refined products terminals are not included above, as they generate revenue under transportation and terminaling service agreements, respectively, that provide for guaranteed minimum throughput. (6) Based on reported revenues from transportation and allowance oil divided by delivered barrels over the same time period. Actual tariffs charged are based on shipping points along the pipeline system, volume and length of contract. (7) Based on reported revenues from transportation and storage divided by delivered and stored barrels over the same time period. Actual rates are based on contract volume and length. (8) Mattox is billed at a fixed rate of$1.52 per barrel for the monthly minimum quantity in accordance with the terms of dedication and transportation agreements entered into inApril 2020 . (9) Mattox is billed at a fixed rate (see note above) per dedication and transportation agreements. The rates for 2019 and 2018 are not applicable, as we only entered into these agreements inApril 2020 . These agreements do not apply to 2019 and 2018. 62
-------------------------------------------------------------------------------- Reconciliation of Non-GAAP Measures The following tables present a reconciliation of Adjusted EBITDA and CAFD to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated.
Please read "-Adjusted EBITDA and Cash Available for Distribution" for more information.
2020 2019 2018
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income Net income
$ 556 $ 546 $ 482 Add: Loss (gain) from revision of ARO and disposition of fixed assets - 2 (3) Allowance oil reduction to net realizable value 8 1 5 Depreciation, amortization and accretion 61 49 46 Interest income (23) (4) (2) Interest expense 93 96 64 Income tax expense - - 1 Cash distribution received from equity method investments 541 466 301
Less:
Equity method distributions included in other income 37 33 24 Income from equity method investments 417 373 235 Adjusted EBITDA 782 750 635
Less:
Adjusted EBITDA attributable to noncontrolling interests 15 20 19 Adjusted EBITDA attributable to the Partnership 767 730 616
Less:
Series A Preferred Units distribution 36 - - Net interest paid by the Partnership (1) 93 92 62 Income taxes paid attributable to the Partnership - - - Maintenance capex attributable to the Partnership 20 28 25
Add:
Principal and interest payments received on financing receivables
23 - -
Net adjustments from volume deficiency payments
attributable to the Partnership 17 (10) (4)
Reimbursements from Parent included in partners'
capital - 19 11
Cash available for distribution attributable to the Partnership's common unitholders
$ 658 $
619
(1) Amount represents both paid and accrued interest attributable to the period.
63
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2020 2019 2018
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities Net cash provided by operating activities
$ 650 $ 597 $ 507 Add: Interest income (23) (4) (2) Interest expense 93 96 64 Income tax expense - - 1 Return of investment 91 66 48 Less: Change in deferred revenue and other unearned income 24 (11) (4) Non-cash interest expense 1 1 1 Allowance oil reduction to net realizable value 8 1 5 Change in other assets and liabilities (4) 14 (19) Adjusted EBITDA 782 750 635
Less:
Adjusted EBITDA attributable to noncontrolling interests 15 20 19 Adjusted EBITDA attributable to the Partnership 767 730 616
Less:
Series A Preferred Units distribution 36 - - Net interest paid by the Partnership (1) 93 92 62 Income taxes paid attributable to the Partnership - - - Maintenance capex attributable to the Partnership 20 28 25
Add:
Principal and interest payments received on financing receivables
23 - -
Net adjustments from volume deficiency payments
attributable to the Partnership 17 (10) (4)
Reimbursements from Parent included in partners'
capital - 19 11
Cash available for distribution attributable to the Partnership's common unitholders
$ 658
(1) Amount represents both paid and accrued interest attributable to the period.
64-------------------------------------------------------------------------------- The following discussion includes a comparison of our Results of Operations and Capital Resources and Liquidity - Cash Flows from Our Operations for 2020 and 2019. A discussion of changes in our Results of Operations and Capital Resources and Liquidity - Cash Flows from Our Operations from 2018 to 2019 has been omitted from the Form 10-K, but may be found in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year endedDecember 31, 2019 , filed with theSEC onFebruary 20, 2020 . 2020 Compared to 2019 Revenues Total revenue decreased by$22 million in 2020 as compared to 2019, comprised of decreases of$53 million in transportation services revenue,$12 million in allowance oil revenue and$21 million attributable to product revenue, partially offset by increases of$63 million attributable to terminaling services revenue and$1 million in lease revenue. 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
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.
Costs and Expenses Total costs and expenses increased$24 million in 2020 primarily due to the increases of$38 million in operations and maintenance expenses,$3 million in property taxes and$1 million of depreciation expense. These increases were partially offset by decreases of$12 million in cost of products sold,$4 million in general and administrative expenses and$2 million of loss from the revision of asset retirement obligations and disposition of assets incurred in 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
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. Investment, Dividend and Other Income Investment, dividend and other income increased$34 million in 2020 as compared to 2019. Income from equity method investments increased by$44 million , primarily as a result of the equity earnings associated with the acquisition of additional interests in Explorer and Colonial inJune 2019 , as well as the acquisition of an interest in Mattox inApril 2020 . These increases were partially offset by a decrease in dividend income from other investments of$14 million due to the change in accounting for Explorer and Colonial as equity method investments in 2020 rather than other investments in 2019 following the acquisition of additional interests in these entities inJune 2019 . We were entitled to distributions from Explorer and Colonial with respect to the period beginningApril 1, 2019 , as these were paid after the acquisition date and were no longer considered dividend income. Additionally, Other income increased by$4 million related to higher distributions from Poseidon in 2020. 65 -------------------------------------------------------------------------------- Interest Income and Expense Interest income was$19 million higher mainly due to interest income related to the financing receivables recorded in 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. Capital Resources and Liquidity We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our credit facilities and our ability to access the capital markets. We believe this access to credit along with cash generated from operations will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements, and to make quarterly cash distributions. However, we cannot accurately predict the effects of the continuing COVID-19 pandemic on our capital resources and liquidity due to the current significant level of uncertainty. Our liquidity as ofDecember 31, 2020 was$1,216 million consisting of$320 million cash on hand and$896 million available capacity under our revolving credit facilities. OnApril 1, 2020 , we closed the transactions contemplated by the Partnership Interests Restructuring Agreement, which included the elimination of all the IDRs, the conversion of the economic general partner interest into a non-economic general partner interest and the establishment of the rights and preferences of the Series A Preferred Units in the Partnership's Second Amended and Restated Agreement of Limited Partnership, effective as ofApril 1, 2020 . Pursuant to the Partnership Interests Restructuring Agreement, our general partner (or its assignee) has agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of theApril 2020 Transaction, in an amount of$20 million per quarter for four consecutive fiscal quarters, beginning with the distribution made with respect to the second quarter of 2020. Refer to Note 3 - Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements included in Part II, Item 8 for more details. OnAugust 1, 2019 , Zydeco entered into a senior unsecured revolving loan facility agreement withShell Treasury Center (West) Inc. ("STCW"), effectiveAugust 6, 2019 (the "2019 Zydeco Revolver"). The 2019 Zydeco Revolver has a borrowing capacity of$30 million and matures onAugust 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. OnJune 4, 2019 , we entered into the Ten Year Fixed Facility, which bears an interest rate of 4.18% per annum and matures onJune 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 onJune 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 onJune 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 effectiveJuly 31, 2018 . The Seven Year Fixed Facility was fully drawn onAugust 1, 2018 , and the borrowings were used to partially repay borrowings under the Five Year Revolver dueDecember 2022 . Additionally, onAugust 1, 2018 , we amended and restated the Five Year Revolver dueOctober 2019 such that the facility will now mature onJuly 31, 2023 and is now referred to as the Five Year Revolver dueJuly 2023 . 66 -------------------------------------------------------------------------------- Credit Facility Agreements As ofDecember 31, 2020 , we have entered into the following credit facilities: Total Capacity Current Interest Rate Maturity Date Ten Year Fixed Facility $ 600 4.18 % June 4, 2029 Seven Year Fixed Facility 600 4.06 % July 31, 2025 Five Year Revolver due July 2023 760 1.20 % July 31, 2023 Five Year Revolver due December December 1, 2022 2022 1,000 1.21 % Five Year Fixed Facility 600 3.23 % March 1, 2022 2019 Zydeco Revolver (1) 30 0.86 % August 6, 2024 (1) EffectiveAugust 6, 2019 , the senior unsecured revolving credit facility agreement between Zydeco and STCW, datedAugust 6, 2014 , expired. In its place, Zydeco entered into the 2019 Zydeco Revolver. See above for additional information. Borrowings under the Five Year Revolver dueJuly 2023 , the Five Year Revolver dueDecember 2022 and the 2019 Zydeco Revolver bear interest at the three-month LIBOR rate plus a margin or, in certain instances (including if LIBOR is discontinued) at an alternate interest rate as described in each respective revolver. Over the next few years, LIBOR will be discontinued globally, and as such, a new benchmark will take its place. We are in discussion with our Parent to further clarify the reference rate(s) applicable to our revolving credit facilities once LIBOR is discontinued, and we are evaluating any potential impact on our facilities. Our weighted average interest rate for 2020 and 2019 was 3.3% and 3.8%, respectively. The weighted average interest rate includes drawn and undrawn interest fees, but does not consider the amortization of debt issuance costs or capitalized interest. A 1/8 percentage point (12.5 basis points) increase in the interest rate on the total variable rate debt of$894 million as ofDecember 31, 2020 would increase our consolidated annual interest expense by approximately$1 million . We will need to rely on the willingness and ability of our related party lender to secure additional debt, our ability to use cash from operations and/or obtain new debt from other sources to repay/refinance such loans when they come due and/or to secure additional debt as needed.
As of
For definitions and additional information on our credit facilities, refer to Note 8 - Related Party Debt in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report. Equity Issuances As consideration for theApril 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. OnJune 6, 2019 , in connection with theJune 2019 Acquisition, we issued 9,477,756 common units toShell Midstream LP Holdings LLC , an indirect subsidiary of Shell. In connection with the issuance of the common units, we issued 193,424 general partner units to our general partner in order to maintain its 2% general partner interest in us. The non-cash equity consideration from this issuance was valued at$200 million pursuant to theMay 2019 Contribution Agreement and was used to partially fund theJune 2019 Acquisition. OnFebruary 6, 2018 , we completed the sale of 25,000,000 common units in a registered public offering for approximately$673 million net proceeds. Additionally, we completed the sale of 11,029,412 common units in a private placement withShell Midstream LP Holdings LLC , an indirect subsidiary of Shell, for an aggregate purchase price of$300 million . See Note 11 - (Deficit) Equity in the Notes to Consolidated Financial Statements included in Part II, Item 8 for additional information. Cash Flows from Our Operations Operating Activities. We generated$650 million in cash flow from operating activities in 2020 compared to$597 million in 2019. The increase in cash flows was primarily driven by an increase in equity investment income related to the acquisition of 67 -------------------------------------------------------------------------------- an interest in Mattox inApril 2020 and additional interests in Explorer and Colonial inJune 2019 , as well as an increase related to deferred revenue in 2020. These increases were partially offset by the timing of certain prepaid expenses in 2020. Investing Activities. Our cash flow provided by investing activities was$64 million in 2020 compared to$87 million used in investing activities in 2019. The increase in cash flow provided by investing activities was primarily due to no cash acquisition from Parent, no contributions to investment, lower capital expenditures and higher return of investment in 2020 compared to 2019. Financing Activities. Our cash flow used in financing activities was$684 million in 2020 compared to$428 million in 2019. The increase in cash flow used in financing activities was primarily due to increased distributions paid to the unitholders and our general partner, no borrowings under credit facilities and lower other contributions from Parent in 2020 compared to 2019. These increases were partially offset by there being no capital distributions to our general partner in 2020. Capital Expenditures and Investments Our operations can be capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements consist of maintenance capital expenditures and expansion capital expenditures. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, expansion capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire new systems or facilities. We regularly explore opportunities to improve service to our customers and maintain or increase our assets' capacity and revenue. We may incur substantial amounts of capital expenditures in certain periods in connection with large maintenance projects that are intended to only maintain our assets' capacity or revenue. We incurred capital expenditures of$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 theHouma 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:
2020 2019 2018
Expansion capital expenditures $ 1 $ 10 $ 25
Maintenance capital expenditures 26 28 24
Total capital expenditures paid 27 38 49
(Decrease) increase in accrued capital expenditures (5) (3) 2
Total capital expenditures incurred $ 22 $ 35 $ 51
Contributions to investment $ - $ 25 $ 28 We expect total capital expenditures and investments to be approximately
Expected Capital Actual Capital Expenditures Expenditures 2020 2021
Expansion capital expenditures
Triton $ 1 $ -
Total expansion capital expenditures incurred 1 -
Maintenance capital expenditures
Zydeco 19 11
Pecten 1 2
Triton 1 4
Total maintenance capital expenditures incurred 21 17
Contributions to investment - 4
Total capital expenditures and investments $ 22 $ 21
68
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Expansion and Maintenance Expenditures
Zydeco's maintenance capital expenditures for 2020 were $19 million , primarily
for Bessie Heights , as well as an upgrade of the motor control center at Houma
and various other maintenance projects. We expect Zydeco's maintenance capital
expenditures to be approximately $11 million for 2021, of which $6 million is
related to an upgrade of the motor control center at Houma , $2 million is
related to Houma tank maintenance projects and $1 million is for replacement of
a loading arm at the Houma dock facility. The remaining spend is related to
routine maintenance.
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. Capital Contributions In accordance with the Member Interest Purchase Agreement datedOctober 16, 2017 pursuant to which we acquired a 50% interest inPermian Basin , we will make capital contributions for our pro rata interest inPermian Basin to fund capital and other expenditures, as approved by supermajority (75%) vote of the members. We made no capital contributions in 2020, and expect to make capital contributions of$4 million in 2021. Contractual Obligations A summary of our contractual obligations as ofDecember 31, 2020 is shown in the table below: Total Less than 1 year Years 2 to 3 Years 4 to 5 More than 5 years Operating leases for land and platform space$ 7 $ - $ 1 $ 1 $ 5 Finance leases (1) 56 5 10 10 31 Other agreements (2) 36 6 12 12 6 Debt obligation (3) 2,694 - 1,494 600 600 Interest payments on debt (4) 374 81 118 89 86 Total$ 3,167 $ 92$ 1,635 $ 712 $ 728 (1) Finance leases includePort Neches storage tanks andGarden Banks 128 "A" platform. Finance leases include$24 million in interest,$24 million in principal and$8 million in executory costs. (2) Includes a joint tariff agreement and Odyssey tie-in agreement. (3) See Note 8 - Related Party Debt in the Notes to Consolidated Financial Statements included in Part II, Item 8 for additional information. (4) Interest payments were calculated based on rates in effect atDecember 31, 2020 for variable rate borrowings. OnApril 1, 2020 , as partial consideration for theApril 2020 Transaction, we issued 50,782,904 Series A Preferred Units to SPLC at a price of$23.63 per preferred unit. Our Series A Preferred Units are contractually entitled to receive cumulative quarterly distributions. For the year endedDecember 31, 2020 , cumulative preferred distributions paid to our Series A Preferred Unitholders were$36 million . However, subject to certain conditions, we or the holders of the Series A Preferred Units may convert the Series A Preferred Units into common units at certain anniversary dates after the issuance date. Due to the uncertain timing of any potential conversion, distributions related to the Series A Preferred Units were not included in the contractual obligations table above. Odyssey entered into an operating lease datedMay 12, 1999 with a third party for usage of offshore platform space atMain Pass 289C. Additionally, Odyssey entered into a tie-in agreement effectiveJanuary 2012 with a third party, which allowed 69 -------------------------------------------------------------------------------- producers to install the tie-in connection facilities and tying into the system. The agreements will continue to be in effect until the continued operation of the platform is uneconomic. OnDecember 1, 2014 , we entered into a terminal services agreement with a related party in which we were to take possession of certain storage tanks located inPort Neches, Texas , effectiveDecember 1, 2015 . OnOctober 26, 2015 , the terminal services agreement was amended to provide for an interim in-service period for the purposes of commissioning the tanks in which we paid a nominal monthly fee. Our capitalized costs and related capital lease obligation commenced effectiveDecember 1, 2015 , and the storage tanks were placed in-service onSeptember 1, 2016 . Under this agreement, in the eighteenth month after the in-service date, actual fixed and variable costs could be compared to premised costs. If the actual and premised operating costs differ by more than 5%, the lease would be adjusted accordingly, and this adjustment will be effective for the remainder of the lease. No adjustment has been made to date. The imputed interest rate on the capital portion of the lease is 15%. OnSeptember 1, 2016 , which is the in-service date of the capital lease for thePort Neches storage tanks, a joint tariff agreement with a third party became effective. The tariff will be reviewed annually and the rate updated based onFERC's indexing adjustment to rates effectiveJuly 1 of each year. EffectiveJuly 1, 2020 there was an approximate 2% increase to this rate based onFERC's indexing adjustment. The initial term of the agreement is ten years with automatic one-year renewal terms with the option to cancel prior to each renewal period. Off-Balance Sheet Arrangements We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities. Critical Accounting Policies and Estimates Critical accounting policies are those that are important to our financial condition and require management's most difficult, subjective or complex judgments. Different amounts would be reported under different operating conditions or under alternative assumptions. We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with GAAP. Our more critical accounting policies include those related to long-lived assets, equity method investments and revenue recognition. Inherent in such policies are certain key assumptions and estimates. We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. Our significant accounting policies are summarized in Note 2 - Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report. We believe the following to be our most critical accounting policies applied in the preparation of our financial statements. Long-Lived Assets Key estimates related to long-lived assets include useful lives, recoverability of carrying values and existence of any retirement obligations. Such estimates could be significantly modified. The carrying values of long-lived assets could be impaired by significant changes or projected changes in supply and demand fundamentals of oil, natural gas, refinery gas or refined products (which could have a negative impact on operating rates or margins), new technological developments, new competitors, adverse changes associated with theU.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 estimated useful lives of long-lived assets range from five to 40 years. Depreciation of these assets under the straight-line method over their estimated useful lives totaled$50 million ,$49 million and$46 million for 2020, 2019 and 2018, respectively. If the useful lives of the assets were found to be shorter than originally estimated, depreciation charges would be accelerated. Additional information concerning long-lived assets and related depreciation and amortization appears in Note 6 - Property, Plant and Equipment in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report. Equity Method Investments 70 -------------------------------------------------------------------------------- We account for investments where we have the ability to exercise significant influence, but not control, under the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value. Based on our updated forecast and expectations of market conditions, we determined that there was a triggering event as ofDecember 7, 2020 for ourPermian Basin equity method investment that required us to update our impairment evaluation. The updated forecast had reductions in forecasted volumes gathered and processed byPermian Basin . We utilized the services of an independent valuation specialist to assist in the fair value appraisal of our investment inPermian Basin . Based on our evaluation, we determined that the fair value of our investment inPermian Basin was in excess of the carrying value as ofDecember 7, 2020 , and, therefore, there was no other-than-temporary impairment. The fair value of thePermian 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. Revenue Recognition OnJanuary 1, 2018 , we adopted Topic 606, Revenue from Contracts with Customers, and all related Accounting Standard Updates to this Topic (collectively, "the revenue standard"). See Note 12 - Revenue Recognition in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for additional information. We recognize revenue when we transfer promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. We recognize revenue through the application of a five-step model, which includes: identification of the contract; identification of the performance obligations; determination of the transaction price; allocation of the transaction price to the performance obligations; and recognition of revenue as the entity satisfies the performance obligations. We generate a portion of our revenue under long-term agreements by charging fees for the transportation, terminaling and storage of crude oil and refined products, intermediate and finished products through our pipelines, storage tanks, docks, truck and rail racks, and for the transportation of refinery gas through our assets. Contract obligations are billed monthly. Transportation revenue is billed as services are rendered, and we accrue revenue based on nominations for that accounting month. We estimate this revenue based on contract data, regulatory information and preliminary throughput and allocation measurements, among other items. Additionally, we refer to our transportation services agreements and throughput and deficiency agreements as "ship-or-pay" contracts. As a result ofFERC 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 ofDecember 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. Certain transportation and terminaling services agreements with related parties are considered operating leases under GAAP. Revenues from these agreements are recorded within Lease revenue-related parties in the accompanying consolidated statement of income. See Note 12 - Revenue Recognition in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report. 71 --------------------------------------------------------------------------------April 2020 Transaction Fair Value In connection with theApril 2020 Transaction, we utilized the services of independent valuation specialists to determine the fair value of the total consideration, as well as the fair values of the Mattox Transaction, theNorco Transaction, and the GP/IDR Restructuring as ofApril 1, 2020 . Because the components of theApril 2020 Transaction were entered in contemplation of each other and were transactions among entities under common control, the fair values of theApril 2020 Transaction were used solely for the purpose of allocating a portion of the total consideration on a relative fair value basis to theNorco Transaction. The Partnership issued 50,782,904 Series A Preferred Units and 160,000,000 newly issued common units to SPLC as consideration for theApril 2020 Transaction. See Note 3 - Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for additional details. As further described in Note 3 - Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report, we acquired the Mattox equity interests from SGOM as a part of the Mattox Transaction. The acquisition was accounted for as a transaction among entities under common control on a prospective basis as an asset acquisition. As a part of the Norco Transaction, SOPUS and Shell Chemical transferred certain logistics assets at theShell Norco Manufacturing Complex to Triton, as designee of the Partnership. The transfer of the Norco Assets combined with the terminaling service agreements was accounted for as a failed sale leaseback under the lease standard, as control of the assets did not transfer to the Partnership. As a result, the transaction was treated as financing arrangement. We also recorded contract assets as ofApril 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 theApril 2020 Transaction. The common units were valued using a market approach based on the market opening price of the Partnership's common units as ofApril 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 theApril 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 theApril 2020 Transaction are individually and in the aggregate reasonable; however, our estimates and assumptions are highly judgmental in nature. Further, there are inherent uncertainties related to these estimates and assumptions, and our judgment in applying them, to determine the fair values. While we believe we have made reasonable estimates and assumptions to calculate the fair values, changes in any one of the estimates, assumptions or a combination of estimates and assumptions, could result in changes to the estimated fair values utilized to determine the relative stand-alone fair value of the Norco Transaction. Fair value of consideration The following table summarized the fair valuation approaches and key assumptions underlying those approaches to value the different components of the consideration of theApril 2020 Transaction: Valuation Technique Key assumptions Discount for lack of marketability; waiver Common Units Market Approach discount Volatility rate; expected term; yield and Series A Preferred Units Income Approach conversion price
Fair value of business enterprise value
The following table summarizes the fair valuation approaches and key assumptions
underlying those approaches to obtain the business enterprise value of the
different components of the
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Valuation Technique Key assumptions
Discount rates; revenue growth rates; terminal
Mattox Transaction Income Approach growth rates; cash flow projections
Discount rates; revenue growth rates; terminal
Norco Transaction Income Approach growth rates; cash flow projections
Discount rates; revenue growth rates; terminal
GP/IDR Restructuring Income Approach growth rates; projected CAFD
Relative Stand -Alone Selling Price
We allocate the arrangement consideration between the components based on the
relative stand-alone selling price ("SASP") of each component in accordance with
ASC Topic 606, Revenue from Contracts with Customers. The Partnership
established the stand-alone selling price for the financing components based off
an expected return on the assets being financed. The Partnership established the
SASP for the service components using an expected cost-plus margin approach
based on the Partnership's forecasted costs of satisfying the performance
obligations plus an appropriate margin for the service. The SASP is used to
allocate the annual terminaling service agreement payments between the principal
payments and interest income on the financing receivables (financing components)
and terminaling service revenue (service components). The key assumptions
include forecasts of the future operation and maintenance costs and major
maintenance costs and the expected margin with respect to the service components
and the expected return on the assets with respect to the financing components.
Recent Accounting Pronouncements
Please read Note 2 - Summary of Significant Accounting Policies - Recent
Accounting Pronouncements included in Part II, Item 8 of this report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and
prices.
Commodity Price Risk
With the exception of buy/sell arrangements on some of our offshore pipelines
and our allowance oil retained, we do not take ownership of the crude oil or
refined products that we transport and store for our customers, and we do not
engage in the trading of any commodities. We therefore have limited direct
exposure to risks associated with fluctuating commodity prices.
Our long-term transportation agreements and tariffs for crude oil shipments
include PLA. The PLA provides additional revenue for us at a stated factor per
barrel. If product losses on our pipelines are within the allowed levels, we
retain the benefit, otherwise we are required to compensate our customers for
any product losses that exceed the allowed levels. We take title to any excess
product that we transport when product losses are within allowed level, and we
sell that product several times per year at prevailing market prices. This
allowance oil revenue, which accounted for approximately 4%, 6% and 6% of our
total revenue in 2020, 2019 and 2018, respectively, is subject to more
volatility than transportation revenue, as it is directly dependent on our
measurement capability and commodity prices. As a result, the income we realize
under our loss allowance provisions will increase or decrease as a result of
changes in the mix of product transported, measurement accuracy and underlying
commodity prices. We do not intend to enter into any hedging agreements to
mitigate our exposure to decreases in commodity prices through our loss
allowances.
Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result
of variable rate borrowings under our revolving credit facilities. To the extent
that interest rates increase, interest expense for these revolving credit
facilities will also increase. As of both December 31, 2020 and December 31,
2019 , the Partnership had $894 million in outstanding variable rate borrowings
under these revolving credit facilities. A hypothetical change of 12.5 basis
points in the interest rate of our variable rate debt would impact the
Partnership's annual interest expense by approximately $1 million for both 2020
and 2019. We do not currently intend to enter into any interest rate hedging
agreements, but will continue to monitor interest rate exposure.
Our fixed rate debt does not expose us to fluctuations in our results of operations or liquidity from changes in market interest rates. Changes in interest rates do affect the fair value of our fixed rate debt. See Note 8 -Related Party Debt in the accompanying Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for further discussion of our borrowings and fair value measurements.
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--------------------------------------------------------------------------------Other Market Risks
We may also have risk associated with changes in policy or other actions taken byFERC . Please see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting our Business and Outlook - Regulation" for additional information. 74
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