BP MIDSTREAM PARTNERS LP Unless otherwise stated or the context otherwise indicates, all references to "we," "our," "us," or similar expressions refer to the legal entityBP Midstream Partners LP (the "Partnership"). The term "our Parent" refers toBP Pipelines (North America), Inc. ("BP Pipelines "), any entity that wholly ownsBP Pipelines , indirectly or directly, includingBP America Inc. and BP p.l.c. ("BP"), and any entity that is wholly owned by the aforementioned entities, excludingBP Midstream Partners LP . Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information included under Part I, Item 1 and 2. Business and Properties, Part I, Item 1A. Risk Factors and Part II, Item 8. Financial Statements and Supplementary Data. It should also be read together with "Cautionary Note Regarding Forward-Looking Statements" in this report. This section of this Form 10-K generally discusses 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of the Partnerships's Annual Report on Form 10-K for the fiscal year endedDecember 31, 2019 . 50 --------------------------------------------------------------------------------
Partnership Overview
We are a fee-based, growth-oriented master limited partnership formed by
Business and Basis of Presentation in the Notes to Consolidated Financial Statements.
Business Environment, Market Conditions and Outlook
The impact to the energy industry from the decline in demand for petroleum and petroleum-based products resulting from the response to the global outbreak of COVID-19 have been unprecedented. Additionally, the operations of Mars,Ursa , Caesar, Proteus and Endymion, our offshore crude oil pipeline systems, and Cleopatra, our offshore natural gas pipeline ("Offshore Pipelines"), have been impacted by a record number of storms in a single season. Although our assets have remained operational, the record storm season has negatively impacted our third and fourth quarter results. Management continues to monitor the challenging macro environment. For risks associated with these and other factors, refer to " Item 1A. Risk Factors " in this Annual Report. Management continues to work closely withBP Pipelines , as operator of our assets under the Omnibus Agreement, to ensure appropriate practices are adopted for continued functioning of our assets as well as mitigation strategies for any office or worksite where COVID-19 may be detected.
COVID-19
In the first quarter of 2020, the COVID-19 outbreak spread across the globe. Federal, state and local governments mobilized to implement containment mechanisms and minimize impacts to their populations and economies. Various containment measures, which included the quarantining of cities, regions and countries, have resulted in a significant drop in general economic activity and a resulting decrease in demand for petroleum and petroleum-based products. In the second and third quarters of 2020, as COVID-19 appeared to decrease or stabilize in certain areas, certain local, regional and national authorities began to loosen such containment measures and restrictions in various locations in an effort to begin economic recovery, among other purposes. While this relaxation of containment measures initially led to an increased demand for petroleum and petroleum-based products through improved general economic conditions, there was also a resurgence of COVID-19 cases in the third quarter. This resurgence continued into the fourth quarter and resulted in the reinstatement of containment measures and restrictions, which has lowered demand for petroleum and petroleum-based products.
Decline in Demand and Potential Impact to Our Operations
The unprecedented supply and demand dynamics created by demand decreases resulting from COVID-19 and supply increases resulting from recent periods of increased production by members of theOrganization of Petroleum Exporting Countries and other countries, includingRussia ("OPEC+"), beginning inMarch 2020 , have resulted in declines in commodity prices and created volatility, uncertainty, and turmoil in the oil and gas industry. Despite OPEC+ agreeing to cut production inApril 2020 , such production cuts have yet to offset the decrease in demand resulting from the COVID-19 pandemic and related economic repercussions. As a result, available storage and transportation capacity for production have been limited. It is uncertain whether capital and production cuts will continue and, if so, whether they will be sufficient to offset the continued low demand resulting from the COVID-19 pandemic. Demand and prices may again decline due to the resurgence of the outbreak across theU.S. and other locations across the world and the related social distancing guidelines, travel restrictions, and stay-at-home orders, although the extent of the additional impact on our industry and our business cannot be reasonably predicted at this time. In the year endedDecember 31, 2020 , we experienced a reduction in volumes on our onshore pipelines as a result of reduced demand. The impacts of this as well as other operational drivers are offset by$13.2 million of deficiency revenue recorded under our MVCs on all onshore pipelines, which extend throughDecember 31, 2023 (and for certain volumes on Diamondback throughJune 30, 2022 ).BP Products has executed new MVC agreements for a three-year term which continues to provide downside protection to the Partnership, however the minimum volume thresholds were reduced from 2020 levels for BP2 and Diamondback. As a result, we could experience a negative financial impact if volumes shipped on our pipelines remain below such minimum commitments beyond 2020 as a result of reduced consumer demand due to the response to the COVID-19 pandemic. 51 -------------------------------------------------------------------------------- For our offshore joint ventures, we expect demand to be resilient, as offshore projects are larger capital projects planned over many years and less impacted by temporary changes in capital investment. We experienced a decline in volumes on our offshore pipelines throughout 2020; and such decline was primarily due to the short term weather impacts in theGulf of Mexico and planned maintenance activities. To limit the impact of COVID-19, BP and our other customers, as well as third-party operators of our pipelines, have implemented various protocols for both onshore and offshore personnel; however, these protocols may not prove to be successful. There is risk of decreased volumes with respect to our offshore operations if operators take actions to reduce operations in response to demand declines or increasingly limited storage availability or are unable to control COVID-19 infections on platforms and are required to shut-in. Additionally, we expect the shippers on our offshore pipelines to continue to find buyers for their production; however, they may not be successful. We have taken steps and continue to actively work to mitigate the evolving challenges and continuing impact of both the COVID-19 pandemic and the industry downturn on our operations and our financial condition. We have also worked withBP Pipelines and the third-party operators of our assets to ensure that COVID-19 response and business continuity plans have been implemented across all of our assets and operations. BP employees, includingBP Pipelines personnel, have been working from home sinceMarch 16, 2020 , except those deemed critical to the functioning of owned and managed assets. For those that are critical and are required to be on-site, protocols have been implemented to protect those employees. Thus far, the need for BP employees to work remotely has not significantly impacted our operations, including use of financial reporting systems, nor has it significantly impacted our internal control environment. We have not incurred, and in the future do not expect to incur, significant expenses related to business continuity. However, our continuing operations and the management of the immediate and contingent safety measures would likely become increasingly difficult if a significant number of BP employees are infected by COVID-19 and the practical difficulties of social distancing impact productivity. We also continue to monitor our liquidity position. As ofDecember 31, 2020 , we had available capacity of$132 million under our unsecured revolving credit facility with an affiliate of BP and$126.9 million in cash and cash equivalents; our only outstanding indebtedness is$468 million under the term loan, with no principal payments due until 2025. We experienced a decline in the price of our common units in 2020, a condition that is consistent across our sector and may impact our ability to access capital markets. We do not have any debt covenants or other lending arrangements that depend upon our unit price. We are in compliance with the covenants contained in both our revolving credit facility and term loan, both of which include the requirement to maintain a consolidated leverage ratio, which is calculated as total indebtedness to consolidated EBITDA, not to exceed 5.0 to 1.0, subject to a temporary increase in such ratio to 5.5 to 1.0 in connection with certain material acquisitions. For additional information, refer to "Capital Resources and Liquidity" and
Note 9 - Debt in the Notes to Consolidated Financial Statements.
We are unable to reasonably predict when, or to what extent, demand for petroleum and petroleum-based products and the overall markets and global economy will stabilize, and the pace of any subsequent recovery for the oil and gas industry. Further, to what extent these events do ultimately impact our business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous evolving factors that cannot be predicted, including the duration of the pandemic. As noted above,BP Pipelines and the third-party operators of our assets have taken steps and continue to actively work to mitigate the evolving challenges and continuing impact of both the COVID-19 pandemic and the industry downturn on our operations and financial condition. However, given the tremendous uncertainty and turmoil, there is no certainty that the measures we take will be ultimately sufficient. Weather Impacts TheAtlantic hurricane season this year reached an all-time record in terms of the number of storms in a single season, and during the third and fourth quarters of 2020, the operations of our Offshore Pipelines were disrupted by multiple weather events in theGulf of Mexico , including Hurricanes Laura, Sally, Delta and Zeta. We estimate the gross impact on operations was in the range of 150,000 to 200,000 barrels of oil equivalent per day or$8 million to$10 million to our cash available for distribution, driven primarily by these weather events. Such events have been, and may in the future be material and may cause a serious business disruption or serious damage to our pipeline systems which could affect such systems' ability to transport crude oil and natural gas. 52 --------------------------------------------------------------------------------
How We Generate Revenue
Onshore Assets
We generate revenue on our onshore pipeline assets through published tariffs
(regulated by
We have entered into a throughput and deficiency agreement with our affiliateBP Products North America, Inc. ("BP Products "), an indirect wholly owned subsidiary of BP, for transporting diluent on the Diamondback pipeline under a joint tariff agreement and a dedication agreement with a third-party carrier. These agreements include a minimum volume requirement, under whichBP Products has committed to pay us an incentive rate for a fixed minimum volume during the twelve-month running period fromJuly 1, 2017 and each successive twelve-month period thereafter throughJune 30, 2022 , whether or not such volumes are physically shipped through Diamondback. The parties have the option to allow the two agreements to renew annually for one additional year by not sending written notice of termination six months prior to the expiration date. OnNovember 3, 2020 , the Partnership entered into throughput and deficiency agreements withBP Products with respect to volumes transported on BP2,River Rouge and Diamondback. These new agreements have a term of three years beginningJanuary 1, 2021 and expiringDecember 31, 2023 . Under these fee-based agreements, we provide transportation services toBP Products , in exchange for BP Products' commitment to pay us the applicable tariff rates for the minimum monthly volumes, whether or not such volumes are physically shipped byBP Products through our pipelines. KMPhoenix has terminals located acrossthe United States within key product trading hubs and highly strategic markets that support BP's refining, trading and marketing businesses. KMPhoenix has terminals located near key product trading hubs inNew York ,Chicago and theSan Francisco Bay area. KMPhoenix serves gasoline and diesel needs forNew York ,Chicago ,San Francisco ,St Louis ,Atlanta ,Baltimore ,Indianapolis ,Cincinnati andDayton, Ohio . KMPhoenix provides storage for production from BP's three refineries. Seven of KMPhoenix's terminals are supplied directly by BP's refineries with four terminals directly supplied from BP's Whiting Refinery . KMPhoenix generates revenue primarily from truck rack throughput, tank leasing, butane blending and pipeline transshipments. Offshore Assets Many of the contracts supporting our offshore assets include fee-based life-of-lease transportation dedications and require producers to transport all production from the specified fields connected to the pipeline for the life of the related oil lease without a minimum volume commitment. This agreement structure means that the dedicated production cannot be transported by any other means, such as barges or another pipeline. The Mars system has a combination ofFERC -regulated tariff rates, intrastate rates, and contractual rates that apply to throughput movements and inventory management fees for excess inventory, and certain of those rates may be indexed with theFERC rate. Two of the Mars agreements also include provisions to guarantee a return to the pipeline to enable the pipeline to recover its investment, despite the uncertainty in production volumes, by providing for an annual transportation rate adjustment over a fixed period of time to achieve a fixed rate of return. The calculation for the fixed rate of return is based on actual project costs and operating costs. At the end of the fixed period, the rate will be locked in at a rate no greater than the last calculated rate and adjusted annually thereafter at a rate no less than zero percent and no greater than theFERC index. The Proteus and Caesar pipelines have an order from theFERC declaring them to be contract carriers with negotiated rates and services. On Proteus and Caesar, the fees for the anchor shippers, which account for a majority of the volumes dedicated to Proteus and Caesar, respectively, were set for the life of the lease over the original lease volumes dedicated to Proteus and Caesar, and are not subject to annual escalation under their oil transportation contracts. The shippers have firm space that varies annually corresponding to their requested maximum daily quantity forecasts. The majority of our revenues on these pipelines are generated by our anchor shippers based on the specified fee for all transported volumes covered by oil transportation contracts with each shipper. Contracts entered into in connection with later connections to Proteus and Caesar may have different terms than the anchor shippers, including rates that vary with inflation. Cleopatra is also a contract carrier. Each shipper on Cleopatra has a contract with negotiated rates. The rates are fixed for the anchor shippers' dedicated leases, are not subject to annual escalation and generate the majority of Cleopatra's revenues. Contracts for field connections for other shippers contain a variety of rate structures.
Endymion is currently a contract carrier. However, it could be subject to
intrastate or
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larger shippers using storage). The rates are fixed for the anchor shippers'
agreements, are not subject to annual escalation and generate the majority of
Endymion's revenues. Agreements for other shippers may have different terms than
the anchor shippers, including rates that may vary with inflation.
Fixed Loss Allowance and Inventory Management Fees
The tariffs applicable to BP2 and Mars include a fixed loss allowance ("FLA").
An FLA factor per barrel, a fixed percentage, is a separate fee under the crude
oil tariffs to cover evaporation, crude viscosity, temperature differences and
other losses in transit. As crude oil is transported, we earn additional income
based on the applicable FLA factor and the volume transported by the customer
and the applicable prices. Under the tariff applicable to BP2 and Mars,
allowance oil related revenue is recognized using the average market price for
the relevant type of crude oil during the month the product is transported.
In addition, we are entitled to inventory management fees for
How We Evaluate Our Operations
Partnership management uses a variety of financial and operating metrics to analyze performance. These metrics are significant factors in assessing operating results and profitability and include: (i) safety and environmental metrics, (ii) revenue (including FLA) from throughput and utilization; (iii) operating expenses and maintenance spend; (iv) Adjusted EBITDA (as defined below); and (v) cash available for distribution (as defined below).
Preventative Safety and Environmental Metrics
We are committed to maintaining and improving the safety, reliability and efficiency of Partnership operations. As noted above, we have worked withBP Pipelines and the third-party operators of our assets to ensure that COVID-19 response and business continuity plans have been implemented across all of our assets and operations. We have implemented reporting programs requiring all employees and contractors of our Parent who provide services to us to record environmental and safety related incidents. The Partnership's management team uses these existing programs and data to evaluate trends and potential interventions to deliver on performance targets. We integrate health, occupational safety, process safety and environmental principles throughout Partnership operations to reduce and eliminate environmental and safety related incidents. Throughput We have historically generated substantially all of our revenue under long-term agreements orFERC -regulated generally applicable tariffs by charging fees for the transportation of products through our pipelines. The amount of revenue we generate under these agreements depends in part on the volumes of crude oil, natural gas, refined products and diluent on our pipelines. Volumes on pipelines are primarily affected by the supply of, and demand for, crude oil, natural gas, refined products and diluent in the markets served directly or indirectly by Partnership assets. Results of operations are impacted by our ability to: •utilize any remaining unused capacity on, or add additional capacity to, Partnership pipeline systems; •increase throughput volumes on Partnership 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, natural gas, refined products and diluent; •identify and execute organic expansion projects; and •increase throughput volumes via acquisitions. Storage Utilization Storage utilization is a metric that we use to evaluate the performance of the Partnership's storage and terminalling assets. We define storage utilization as the percentage of the contracted capacity in barrels compared to the design capacity of the tank. 54 --------------------------------------------------------------------------------
Operating Expenses and Total Maintenance Spend
Operating Expenses
Management seeks to maximize profitability by effectively managing operating expenses. These expenses are comprised primarily of labor expenses (including contractor services), general materials, supplies, minor maintenance, utility costs (including electricity and fuel) and insurance premiums. Utility costs fluctuate based on throughput volumes and the grades of crude oil and types of refined products we handle. Other operating expenses generally remain relatively stable across broad ranges of throughput volumes, but can fluctuate from period to period depending on the mix of activities performed during that period.
Total Maintenance Spend - Wholly Owned Assets
We calculate Total Maintenance Spend as the sum of maintenance expenses and maintenance capital expenditures, excluding any reimbursable maintenance capital expenditures. We track these expenses on a combined basis because it is useful to understanding our total maintenance requirements. Total Maintenance Spend for the years endedDecember 31, 2020 and 2019, is shown in the table below: Years Ended December 31, 2020 2019 (in millions of dollars) Wholly Owned Assets Maintenance expenses $ 3.8$ 1.7 Maintenance capital expenditures 2.1
1.1
Maintenance capital recovery (1) (1.1)
(0.3)
Total Maintenance Spend - Wholly Owned Assets $ 4.8
(1)Relates to the portion of maintenance capital for the Griffith Station Incident reimbursable by insurance.
The Partnership seeks to maximize profitability by effectively managing maintenance expenses, which consist primarily of safety and environmental integrity programs. We seek to manage maintenance expenses on owned and operated pipelines by scheduling maintenance over time to avoid significant variability in maintenance expenses and minimize impact on cash flows, without compromising our commitment to safety and environmental stewardship. Maintenance expenses represent the costs we incur that do not significantly extend the useful life or increase the expected output of property, plant and equipment. These expenses include pipeline repairs, replacements of immaterial sections of pipelines, inspections, equipment rentals and costs incurred to maintain compliance with existing safety and environmental standards, irrespective of the magnitude of such compliance expenses. Maintenance expenses may vary significantly from period to period because certain expenses are the result of scheduled safety and environmental integrity programs, which occur on a multi-year cycle and require substantial outlays. Maintenance capital expenditures represent expenditures to sustain operating capacity or operating income over the long term. Examples of maintenance capital expenditures include expenditures made to purchase new or replacement assets or extend the useful life of existing assets. These expenditures includes repairs and replacements of storage tanks, replacements of significant sections of pipelines and improvements to an asset's safety and environmental standards.
Adjusted EBITDA and Cash Available for Distribution
The Partnership defines Adjusted EBITDA as net income before net interest
expense, income taxes, gain or loss from disposition of property, plant and
equipment, and depreciation and amortization, plus cash distributed to the
Partnership from equity method investments for the applicable period, less
income from equity method investments. The Partnership defines Adjusted EBITDA
attributable to the Partnership as Adjusted EBITDA less Adjusted EBITDA
attributable to non-controlling interests. We present these financial measures
because we believe replacing our proportionate share of our equity method
investments' net income with the cash received from such equity method
investments more accurately reflects the cash flow from our business, which is
meaningful to our investors.
We compute and present cash available for distribution and define it as Adjusted
EBITDA attributable to the Partnership less maintenance capital expenditures
attributable to the Partnership, net interest paid/received, cash reserves,
income taxes paid and
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--------------------------------------------------------------------------------net adjustments from volume deficiency payments attributable to the Partnership. Cash available for distribution does not reflect changes in working capital balances.
Adjusted EBITDA and cash available for distribution are non-GAAP supplemental financial measures, which are metrics that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess: •operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or financing methods; •ability to generate sufficient cash to support decisions to make distributions to our unitholders; •ability to incur and service debt and fund capital expenditures; and •viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities. We believe that the presentation of Adjusted EBITDA and cash available for distribution provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and cash available for distribution are net income and net cash provided by operating activities, respectively. Adjusted EBITDA and cash available for distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and cash available for distribution 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 cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Please read "Reconciliation of Non-GAAP Measures" section below for the reconciliation of net income and cash provided by operating activities to Adjusted EBITDA and cash available for distribution.
Factors Affecting Our Business
Partnership business can be negatively affected by sustained downturns or slow growth in the economy in general 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 customers' operations. For example, as discussed earlier, in March of 2020, demand for many refined petroleum products declined sharply causing refineries to curtail output. The ultimate magnitude and duration of the COVID-19 pandemic, resulting governmental restrictions on the mobility of consumers and the related impact on crude oil prices and theU.S. and global economy and capital markets is uncertain. We did experience some reduction in volumes on our pipelines throughout 2020, which could continue. The uncertain future impacts of COVID-19 and swift shifts in the demand for oil may negatively impact our financial position, particularly our cash flows and liquidity. As of the date of this Annual Report, all of our assets remain operational.
Changes in Crude Oil and Natural Gas Sourcing and Refined Product and Diluent Demand Dynamics
To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in crude oil, natural gas, refined products and diluent supply and demand. Changes in crude oil and natural gas supply such as new discoveries of reserves, declining production in older fields and the introduction of new sources of crude oil and natural gas supply, investment programs of our shippers to maintain or increase production, along with global supply and demand fundamentals such as the strength of theU.S. dollar, weather conditions and competition among oil producing countries for market share, affect the demand for our services from both producers and consumers. One of the strategic advantages of our crude oil pipeline system is its ability to transport attractively priced crude oil from multiple supply sources. Our crude oil shippers periodically change the relative mix of crude oil grades delivered to the refineries and markets served by our pipelines. While these changes in the sourcing patterns of crude oil transported are reflected in changes in the relative volumes of crude oil by type handled by our pipelines, our crude oil transportation revenue is primarily affected by changes in overall crude oil supply and demand dynamics.
Similarly, our refined products pipeline system has the ability to serve multiple demand centers. Our refined products shippers periodically change the relative mix of refined products shipped on our refined products pipeline system, as well as the destination points, based on changes in pricing and demand dynamics. While these changes in shipping patterns are reflected in
56
--------------------------------------------------------------------------------relative types of refined products handled by our pipeline, our total product transportation revenue is primarily affected by changes in overall refined products and diluent supply and demand dynamics.
Further, the volumes of crude oil that we transport on our BP2 system and refined products and diluent that we distribute on ourRiver Rouge and Diamondback systems depend substantially on the economics of available crude supply for theWhiting Refinery and the economics for refined products and diluent demand in the markets that the pipelines serve. These economics are affected by numerous factors beyond our control, including apportionment on the Enbridge mainline (which offers all of its capacity on an uncommitted basis). In addition, events such as ongoing maintenance at theWhiting Refinery and apportionment on a third-party pipeline, such as the Enbridge mainline, can cause lower throughput on our BP2 system. Volumes are also affected by maintenance and corridor shutdowns due to tie-ins, among other things. 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. Similarly, as demand dynamics change, we anticipate that we will create new services or capacity arrangements that meet customer requirements.
Changes in Commodity Prices
We do not engage in the marketing and trading of any commodities. We do not take ownership of crude oil, natural gas, refined products or diluent. As a result, our exposure to commodity price fluctuations is limited to the FLA provisions in our tariffs, which are only applicable to certain of our crude oil pipelines. We also have indirect exposure to commodity price fluctuations to the extent such fluctuations affect the shipping patterns of our customers.
Customers
For more information, refer to Item 1 and 2 - Business and Properties-Customers.
Regulation
Interstate common carrier pipelines are subject to regulation by various federal, state and local agencies including theFERC , theEnvironmental Protection Agency and theDepartment of Transportation . OnJune 18, 2020 ,FERC issued a Notice of Inquiry requesting comments on a proposed oil pipeline index using the PPI-FG plus 0.09% as the index level, and requested comments on whether and how the index should reflect changes toFERC's policies regarding income tax costs and return on equity. OnDecember 17, 2020 , in Docket No. RM20-14-000,FERC issued an order establishing a new index level of PPI-FG plus 0.78% for the five-year period commencingJuly 1, 2021 . However, requests for rehearing of theDecember 2020 order establishing this indexing amount were filed withFERC , and those requests remain pending, with rehearing granted for purposes of extending the timeFERC has to review these requests.FERC's final application of its indexing rate methodology for the next five-year term of index rates may impact our revenues associated with any transportation services we may provide pursuant to rates adjusted by theFERC oil pipeline index.
Acquisition Opportunities
The Partnership plans to pursue acquisitions of complementary assets from BP as well as third parties subject to market conditions (including the ongoing effects of COVID-19) and our ability to obtain attractive financing. We may also pursue acquisitions jointly withBP Pipelines .BP Pipelines has granted us a right of first offer with respect to its retained ownership interest inMardi Gras and all of its interests in midstream pipeline systems and assets related thereto in the contiguousUnited States and offshoreGulf of Mexico that were owned byBP Pipelines when we were established. Neither BP nor any of its affiliates are under any obligation, however, 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 focus our acquisition strategy on transportation and midstream assets within the crude oil, natural gas and refined products sectors. We believe that we are well positioned to acquire midstream assets from BP, and particularlyBP Pipelines , as well as third parties, should such opportunities arise. Identifying and executing acquisitions will be a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our available cash.
Financing
We expect to fund future capital expenditures primarily from external sources,
including borrowings under our credit facility and potential future issuances of
equity and debt securities.
57
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We intend to make cash distributions to unitholders at a minimum distribution
rate of $0.2625 per unit per quarter ($1.05 per unit on an annualized basis).
Based on the terms of our cash distribution policy, we expect that we will
distribute to unitholders and the general partner, as the holder of IDRs, most
of the cash generated by operations.
Griffith Station Incident
OnJune 13, 2019 , a building fire occurred at theGriffith Station on BP2. Management performed an evaluation of the assets and determined that an impairment was required. A charge of$4.4 million for the impairment was recorded under "Impairment and other, net" on our consolidated statements of operations for the year endedDecember 31, 2019 . In addition, we incurred$1.6 million as a response expense for the year endedDecember 31, 2019 . Our assets are insured with a deductible of$1.0 million per incident. We accrued an offsetting insurance receivable of$5.0 million resulting in a net charge of$1.0 million to "Impairment and other, net" for the year endedDecember 31, 2019 . The insurance receivable was recorded as$4.3 million under "Other current assets" and$0.7 million under "Other assets" on our consolidated balance sheet as ofDecember 31, 2019 . During the year endedDecember 31, 2020 , we incurred$0.4 million for response expense and received$2.9 million of insurance proceeds. The proceeds have been recorded under "Proceeds from insurance claims" in our consolidated statements of cash flows for the year endedDecember 31, 2020 , leaving a balance of$2.5 million recorded under "Other current assets" on our consolidated balance sheets as ofDecember 31, 2020 , for insurance proceeds expected to be received in 2021. In the event that insurance proceeds exceed the receivable balance, such amounts would be recognized as a gain.
Results of Operations
The following tables and discussion contain a summary of our consolidated
results of operations for the years ended
As mentioned above in Item 7 - COVID-19, during 2020, our results of operations were negatively impacted by the COVID-19 pandemic and multiple weather events in theGulf of Mexico . Years Ended December 31, 2020 2019 (in millions of dollars) Revenue $ 128.9 $ 128.5 Costs and expenses Operating expenses 19.6 20.0 Maintenance expenses 3.8 1.8 General and administrative 16.9 16.9 Depreciation 2.5 2.6 Impairment and other, net - 1.0 Property and other taxes 0.7 0.7 Total costs and expenses 43.5 43.0 Operating income 85.4 85.5 Income from equity method investments 110.8 116.7 Interest expense, net 7.9 15.1 Net income 188.3 187.1 Less: Net income attributable to non-controlling interests 19.9 19.2 Net income attributable to the Partnership $ 168.4 $ 167.9 Adjusted EBITDA(1) $ 213.2
$ 219.5 Less: Adjusted EBITDA attributable to non-controlling interests
24.3 23.2
Adjusted EBITDA attributable to the Partnership(1) $ 188.9
$ 196.3
(1) See Reconciliations of Non-GAAP Measures below.
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Years Ended December 31,
Pipeline throughput (thousands of barrels per day)(1) 2020 2019
BP2 276 300
Diamondback 63 63
River Rouge 69 73
Total Wholly Owned Assets 408 436
Mars 490 546
Caesar 161 194
Cleopatra(2) 18 24
Proteus 214 175
Endymion 214 175
Mardi Gras Joint Ventures 607 568
Ursa 78 107
Average revenue per barrel ($ per barrel)(3)
Total Wholly Owned Assets $ 0.77 $ 0.77
Mars 1.35 1.31
Mardi Gras Joint Ventures 0.59 0.65
Ursa 0.90 0.87
(1) Pipeline throughput is defined as the volume of delivered barrels.
(2) Natural gas is converted to oil equivalent at 5.8 million cubic feet per one thousand barrels.
(3) Based on reported revenues from transportation and allowance oil divided by delivered barrels
over the same period.
Year Ended
Total revenue increased by
•Increase of$7.6 million or 136.6% in deficiency revenue from our throughput and deficiency agreements with BP. •Decrease of$4.5 million or 43.5% in FLA revenue from BP2 driven by a decrease in in throughput volume and a decrease in FLA prices realized. •Decrease of$2.7 million in tariff revenue driven by a decrease of$3.1 million on BP2, a$0.5 million increase on Diamondback and a$0.1 million decrease onRiver Rouge . •Throughput volume decreased by 9.3 million barrels primarily driven by a 8.4 million decrease on BP2, a 0.3 million increase on Diamondback and a 1.2 million decrease onRiver Rouge .
Operating expenses decreased by
Maintenance expenses increased by$2.0 million , or 111.1%, in the year endedDecember 31, 2020 , compared to the year endedDecember 31, 2019 , primarily as a result of an increase from inspection costs and corrosion projects onRiver Rouge .
General and administrative expenses was flat in the year ended
Impairment expense decreased by
Income from equity method investments decreased by$5.9 million , or 5.1%, in the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 primarily due to lower earnings from Mars andUrsa driven by lower throughput volume, 59 -------------------------------------------------------------------------------- unplanned maintenance and producer shut-ins from hurricanes. Earnings from KMPhoenix were lower in the year endedDecember 31, 2020 compared to year endedDecember 31, 2019 .
Interest expense, net was
Reconciliation of Non-GAAP Measures
The following tables present a reconciliation of Adjusted EBITDA to net income
and to net cash provided by operating activities, the most directly comparable
GAAP financial measures, for each of the periods indicated.
Years Ended December 31,
2020 2019
(in millions of dollars)
Reconciliation of Adjusted EBITDA and Cash Available for
Distribution to Net Income
Net income $ 188.3 $ 187.1
Add:
Depreciation 2.5 2.6
Interest expense, net 7.9 15.1
Cash distributions received from equity method investments 125.3 131.4
Less:
Income from equity method investments 110.8 116.7 Adjusted EBITDA 213.2 219.5
Less:
Adjusted EBITDA attributable to non-controlling interests 24.3 23.2 Adjusted EBITDA attributable to the Partnership 188.9 196.3
Add:
Maintenance capital recovery(1) 1.1 0.3
Less:
Net interest paid/(received) 11.3 15.1 Maintenance capital expenditures 2.1 1.1 Cash reserves(2) (3.0) -
Cash available for distribution attributable to the Partnership
(1)Relates to the portion of maintenance capital for the Griffith Station Incident reimbursable by insurance. (2)Reflects cash reserved due to timing of interest payment(s).
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Years Ended December 31,
2020 2019
(in millions of dollars) Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities Net cash provided by operating activities
$ 190.4 $ 189.3 Add: Interest expense, net 7.9 15.1
Distribution in excess of earnings from equity method investments
13.0 11.5
Less:
Change in other assets and liabilities (2.1) (4.9) Non-cash adjustments 0.2 0.3 Impairment and other, net(1) - 1.0 Adjusted EBITDA 213.2 219.5 Less: Adjusted EBITDA attributable to non-controlling interests 24.3 23.2 Adjusted EBITDA attributable to the Partnership 188.9 196.3
Add
Maintenance capital recovery(2) 1.1 0.3
Less:
Net interest paid/(received) 11.3 15.1 Maintenance capital expenditures 2.1 1.1 Cash reserves(3) (3.0) -
Cash available for distribution attributable to the Partnership
(1)This includes$6.0 million of costs related to the Griffith Station Incident (impairment charge of$4.4 million and$1.6 million as a response expense), net of$5.0 million in offsetting insurance receivable. The net charge of$1.0 million reflects our insurance deductible. (2)Relates to the portion of maintenance capital for theGriffith Station Incident reimbursable by insurance. (3)Reflects cash reserved due to timing of interest payment(s).
Capital Resources and Liquidity
Currently, we expect our primary ongoing sources of liquidity to be cash generated from operations (including distribution from our equity method investments), and, as needed, borrowings under our existing credit facility. The entities in which we own an interest may also incur debt. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions. Based upon current expectations for the fiscal year 2021, we believe that our cash on hand, cash flow from operations and borrowings available under our credit facility will be sufficient to fund our operations for 2021. As ofDecember 31, 2020 , our liquidity was$258.9 million , consisting of$126.9 million of cash and$132 million available under our existing credit facility with BP. Our only debt outstanding is our$468 million borrowed under our term loan with an affiliate of BP, and there are no principal payments required with respect to that facility until 2025. During 2020, our results of operations were negatively impacted by the COVID-19 pandemic and multiple weather events in theGulf of Mexico . The MVC agreements executed onNovember 3, 2020 provide downside protection to the Partnership albeit at a lower level than in prior years on BP2 and Diamondback. Additionally, there is risk of decreased volumes with respect to the offshore operations if operators take actions to reduce operations in response to demand declines or increasingly limited storage availability or are unable to control COVID-19 infections on platforms and are required to shut-in. In the longer term, if reduced demand were to persist through 2021 or longer, we may not be able to continue to generate similar levels of operating cash flow and our liquidity and capital resources may not be sufficient to make our current levels of cash distributions to unitholders or even meet our minimum quarterly distribution. Although we continue to actively work to mitigate the evolving challenges and growing impact of both the COVID-19 pandemic and the industry downturn on our operations and our financial condition, there is no certainty that the measures we take will be ultimately sufficient. 61 --------------------------------------------------------------------------------
Cash Distributions
The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend to pay a minimum quarterly distribution of$0.2625 per unit per quarter, which equates to approximately$27.5 million per quarter, or$110.0 million per year in the aggregate, based on the number of common and subordinated units outstanding as ofDecember 31, 2020 . We intend to pay such distributions to the extent we have sufficient cash after the establishment of cash reserves and the payment of expenses, including payments to our general partner and its affiliates.
Revolving Credit Facility
OnOctober 30, 2017 , the Partnership entered into a$600.0 million unsecured revolving credit facility agreement with an affiliate of BP. The credit facility terminates onOctober 30, 2022 and provides for certain covenants, including the requirement to maintain a consolidated leverage ratio, which is calculated as total indebtedness to consolidated EBITDA (as defined in the credit facility), not to exceed 5.0 to 1.0, subject to a temporary increase in such ratio to 5.5 to 1.0 in connection with certain material acquisitions. In addition, the limited liability company agreement of our general partner requires the approval ofBP Holdco prior to the incurrence of any indebtedness that would cause our leverage ratio to exceed 4.5 to 1.0. The credit facility also contains customary events of default, such as (i) nonpayment of principal when due, (ii) nonpayment of interest, fees or other amounts, (iii) breach of covenants, (iv) misrepresentation, (v) cross-payment default and cross-acceleration (in each case, to indebtedness in excess of$75.0 million ) and (vi) insolvency. Additionally, the credit facility limits our ability to, among other things: (i) incur or guarantee additional debt, (ii) redeem or repurchase units or make distributions under certain circumstances; and (iii) incur certain liens or permit them to exist. Indebtedness under this facility bears interest at the 3-month London Interbank Offered Rate ("LIBOR") plus 0.85%. This facility includes customary fees, including a commitment fee of 0.10% and a utilization fee of 0.20%.
In connection with our acquisition in the fourth quarter of 2018, we borrowed
Term Loan Facility Agreement
OnFebruary 24, 2020 , the Partnership entered into a$468.0 million Term Loan Facility Agreement ("term loan") with an affiliate of BP. OnMarch 13, 2020 , proceeds were used to repay outstanding borrowings under the existing credit facility. The term loan has a final repayment date ofFebruary 24, 2025 , and provides for certain covenants, including the requirement to maintain a consolidated leverage ratio, which is calculated as total indebtedness to consolidated EBITDA, not to exceed 5.0 to 1.0, subject to a temporary increase in such ratio to 5.5 to 1.0 in connection with certain material acquisitions. Simultaneous with this transaction, we entered into a First Amendment to Short Term Credit Facility Agreement ("First Amendment") whereby the lender added a provision that indebtedness under both the term loan and credit facility shall not exceed$600.0 million . All other terms of the credit facility remain the same. As ofDecember 31, 2020 , the Partnership was in compliance with the covenants contained in the credit facility and term loan.
Cash Flows from Our Operations
Operating Activities. We generated$190.4 million in cash flow from operating activities in the year endedDecember 31, 2020 , compared to the$189.3 million generated in the year endedDecember 31, 2019 . The$1.1 million increase in cash flows from operations primarily resulted from a decrease in interest expense, offset by a decrease in distribution of earnings from equity method investments. Investing Activities. Our cash flows from investing activities were$12.4 million in the year endedDecember 31, 2020 , compared to$10.4 million in the year endedDecember 31, 2019 . The$2.0 million increase in cash inflows from investing activities is primarily due to an increase of$1.5 million distribution in excess of earnings from equity method investments, and an increase of$2.9 million from proceeds from insurance claims related toGriffith Station incident, partially offset by an increase of$2.4 million in funds used for capital expenditures. Financing Activities. Our cash flows used in financing activities were$174.7 million in the year endedDecember 31, 2020 and$157.9 million in the year endedDecember 31, 2019 . The$16.8 million increase in cash outflows used in financing activities is primarily due to distributions to unitholders and general partner and non-controlling interests. 62 --------------------------------------------------------------------------------
Capital Expenditures
Our operations can be capital intensive, requiring investment to 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, both as defined in our partnership agreement. We are required to distinguish between maintenance capital expenditures and expansion capital expenditures in accordance with our Partnership agreement. A summary of capital expenditures associated with ongoing projects related to the Wholly Owned Assets, for the years endedDecember 31, 2020 and 2019, is shown in the table below: Years Ended December 31, 2020 2019 (in millions of dollars) Cash spent on expansion capital expenditures $ 1.4 $ - Cash spent on maintenance capital expenditures 2.1 1.1 Increase in accrued capital expenditures 3.9 - Increase in capital expenditures reimbursable to our Parent 0.3 - Total capital expenditures incurred $ 7.7$ 1.1 In the year 2020, we incurred$4.1 expansion capital expenditures for an onshore capacity increase project and$3.6 maintenance capital expenditures primarily associated with the following projects: •BP2 motor purchase and installation; •Griffith Station recovery, including a building, lighting, power, relay and PLC panels.
In the year 2019, we incurred
•Projects to support critical equipment reliability forRiver Rouge ; •Densitometer installations atSouth Bend ,Jackson ,Dearborn , Buckeye Detroit andRiver Rouge ; and •Griffith Station recovery, including a building, lighting, power, relay and PLC panels.
We anticipate that our 2021 capital expenditures will be funded with cash from operations and borrowings under our credit facility.
Contractual Obligations
A summary of our contractual obligations atDecember 31, 2020 , is shown in the table below: (in millions of dollars) Total Less than 1 year Years 2 to 3 Years 4 to 5 More than 5 years Term Loan Facility(1)$ 486.7 $ 4.5 $ 9.0$ 473.2 $ - Credit Facility(2) 0.2 0.1 0.1 - - Rights-of-way 3.1 0.1 0.2 0.2 2.6 Operating leases 0.7 0.1 0.1 0.1 0.4 Total$ 490.7 $ 4.8 $ 9.4$ 473.5 $ 3.0 (1)Includes principal and interest expense, based on the current interest rate. Refer to Note 9 - Debt in the Notes to Consolidated Financial Statements. (2)Includes commitment fee on available facility. Refer to Note 9 - Debt in the Notes to Consolidated Financial Statements. Off-Balance Sheet Arrangements
The Partnership has not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.
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--------------------------------------------------------------------------------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 have evaluated the accounting policies used in the preparation of the consolidated financial statements of the Partnership and related notes thereto and believe those policies are reasonable and appropriate. 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 revenue recognition and common control transactions. 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. We believe the following to be our most critical accounting policies applied in the preparation of our financial statements.
Accounting for Equity Method Investments
The Partnership maintains investments in several joint ventures that are accounted for under the equity method of accounting. Under the equity method of accounting, investments are recorded at historical cost as an asset and adjusted for capital contributions, dividends received, and the Partnership's share of the investees' earnings or losses, which is recorded as a component of income from equity method investments. As ofDecember 31, 2020 , the Partnership's equity method investments balance was$519.9 million , and for the year endedDecember 31, 2020 , the Partnership's income from equity method investments was$110.8 million . The Partnership does not have a controlling interest in our investments in joint ventures; however, because of the significance of the investments to our financial statements our management exercises critical judgments when assessing the results of the joint ventures' operations and the accounting judgments made by the operators. This requires management to rely on their experience in the industry and their knowledge of the joint ventures involved in making final assessments on the recognition of operating results as reported to the Partnership by the operators. The Partnership assesses its equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value. For the yearsDecember 31, 2020 and 2019, there were no indicators of an other-than-temporary impairment identified.
Revenue Recognition
Our revenues are primarily generated from crude oil, refined products and diluent transportation services. We recognize revenue over time or at a point in time, depending on the nature of the performance obligations contained in the respective contract with customers. A performance obligation is our unit of account and it represents a promise in a contract to transfer goods or services to the customer. The contract transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is allocated to each performance obligation and recognized as revenue when or as the performance obligation is satisfied. We entered into multiple long-term fee-based transportation agreements withBP Products , an indirect wholly owned subsidiary of BP. Under these agreements,BP Products has committed to pay us the minimum volumes at the applicable rates for each of the twelve-month measurement periods specified by the applicable agreements whether or not such volumes are physically transported through our pipelines.BP Products is allowed to make up for shortfall volumes during each of the measurement periods. Contracts withBP Products , including the allowance oil arrangements discussed below, are accounted for as separate arrangements because they do not meet the criteria for combination. We record revenue for crude oil, refined products and diluent transportation over the period in which they are earned (i.e., either physical delivery of product has taken place, or the services designated in the contract have been performed). Revenue from transportation services is recognized upon delivery or receipt based on contractual rates related to throughput volumes. We accrue revenue based on services rendered but not billed for that accounting month.
Billings to
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the measurement period specified by the agreements. We consider this deferred
revenue as breakage revenue and considered three methods of determining when or
if to recognize the amounts into revenue. We recognize the breakage amount as
revenue when the likelihood of the customer exercising its remaining rights
becomes remote.
The unfulfilled obligations in our revenue contracts are our obligations to
transport certain volumes of crude or diluent molecules (throughput) for our
customers throughout the term of each contract. The terms of the contract
require the customer to deliver a specified quantity of molecules or minimum
volume each day with a right to make up any short fall within the 12 month
measurement period of each contract. At the end of each quarterly reporting
period we analyze the customer's actual shipments compared to their minimum
volume commitments to measure the level of fulfillment toward the contracted
minimum volume commitments. This analysis also includes the review of the
capacity of each pipeline available for the customer to deliver the required
volume to make up for any shortfall, current forecast of the customers' future
shipments, an assessment of whether management thinks the customers can make up
for the shortfall and any impact market conditions have on the probability of
customers making up the shortfall. If our assessment concludes that it is remote
that the customer will make up for volume shortfalls and require performance of
the unfulfilled obligations, the appropriate level of breakage is recognized
into revenue.
Common Control Transactions
Assets and businesses acquired from our Parent and its subsidiaries are
accounted for as common control transactions whereby the net assets acquired are
included in our consolidated balance sheets at their historical carrying value.
BP maintains its accounting records in accordance with International Financial
Reporting Standards, ("IFRS"), and therefore, the determination of historical
carrying cost of BP's investment in assets under accounting principles generally
accepted in the United States of America , ("US GAAP") required management to
make judgments, including assessing the impact of the joint venture formation
transaction under US GAAP and its impact on the carrying value of the asset in
the financial statements.
If any recognized consideration transferred in such a transaction exceeds the
historical carrying value of the net assets acquired, the excess is treated as a
capital distribution to our Parent, similar to a dividend. If the historical
carrying value of the net assets acquired exceeds any recognized consideration
transferred including, if applicable, the fair value of any limited partner
units issued, such excess is treated as a capital contribution from our Parent.
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