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 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 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 Partnership's Annual Report on Form 10-K for the fiscal year endedDecember 31, 2020 .
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.
Merger Transactions Take Private Proposal OnAugust 4, 2021 , the board of directors ofBP Midstream Partners GP LLC , aDelaware limited liability company and the general partner of our Partnership (the "General Partner") received a non-binding preliminary proposal letter fromBP Pipelines , through its wholly-owned subsidiaryBP Midstream Partners Holdings LLC , to acquire all of our issued and outstanding common units not already owned byBP Pipelines or its affiliates at a to-be-determined fixed exchange ratio.
Merger Agreement
OnDecember 19, 2021 ,BP Midstream Partners LP ,BP Midstream Partners GP LLC , BP p.l.c.,BP Midstream Partners Holdings LLC , ("Holdings"), andBP Midstream RTMS LLC ("Merger Sub"), entered into an Agreement and Plan of Merger (the "Merger Agreement"), pursuant to which Merger Sub will merge with and into the Partnership, with the Partnership surviving as an indirect, wholly owned subsidiary of BP (the "Merger"). Under the terms of the Merger Agreement, at the effective time of the Merger, (i) each outstanding common unit other than those owned by BP and its subsidiaries (each, a "Public Common Unit") will be converted into the right to receive 0.575BP American Depositary Shares ("ADSs") each representing six ordinary shares of BP (the "Merger Consideration" and such ratio, the "Exchange Ratio"). In connection with the Merger, (i) any partnership interests that are owned by the Partnership or any of the Partnership's subsidiaries will be cancelled; and (ii) the common units owned by Parent and its subsidiaries, the General Partner's general partner interest and the incentive distribution rights in the Partnership will not be cancelled, will not be converted into the right to receive Merger Consideration and will remain outstanding following the Merger. The Partnership has entered into a Support Agreement, dated as ofDecember 19, 2021 (the "Support Agreement"), with Holdings, pursuant to which Holdings has irrevocably and unconditionally agreed to deliver a written consent covering all of the Partnership Common Units beneficially owned by it in favor of the Merger, the approval of the Merger Agreement and the transactions contemplated by the Merger Agreement and any other matter necessary or desirable for the consummation of the transactions contemplated by the Merger Agreement (the "Support Written Consent"), within two business days following the effectiveness of the registration statement.
Registration Statement
A registration statement on Form F-4 registering 165,164,448 shares of
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Common Units was filed by BP on January 31, 2022 , as amended (Registration No.
333-262425) (the "Registration Statement") and declared effective by the
Securities and Exchange Commission (the "SEC") on March 4, 2022 . Completion of
the transaction is expected in the second quarter, subject to customary closing
conditions. Upon completion, the Partnership Common Units will cease to be
listed on the New York Stock Exchange ("NYSE") and will be subsequently
deregistered under the Securities Exchange Act of 1934, as amended. For more
information, see the risks and uncertainties discussed in Part I, Item 1A. Risk
Factors-Risks Related to the Merger in this Annual Report.
Business Environment, Market Conditions and Outlook
The impacts to the energy industry from the decline and subsequent volatility in demand for petroleum and petroleum-based products resulting from the response to the global outbreak of COVID-19 have been unprecedented. Management continues to monitor the uneven macro environment. For risks associated with COVID-19, hurricanes and other factors, refer to " Item 1A. Risk Factors " in this Annual Report. In the year endedDecember 31, 2021 , we experienced a reduction in volumes on our onshore pipelines compared to 2020. On Diamondback andRiver Rouge , we experienced lower throughput due to reduced demand from shippers. With respect to BP2, there was a slight increase in volumes as a result of lower apportionment during the fourth quarter on the Enbridge mainline and refinery feedstock optimization. The impacts of this reduction in volumes are partially offset by$4.0 million of deficiency revenue recorded under our MVCs.
Weather Impacts and Hurricane Ida
TheAtlantic hurricane season this year was the third-most active on record in terms of the number of storms in a single season. During the third and fourth quarters of 2021, the operations of our Offshore Pipelines were disrupted by multiple weather events in theGulf of Mexico . Such events have been material, and are reasonably likely in the future to 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. In lateAugust 2021 , Hurricane Ida formed and threatened catastrophic damage to theU.S. Gulf Coast along its path. In response, producers in theGulf of Mexico , including BP, suspended production at platforms and evacuated offshore workers. Additionally, operators performed impact assessments when it was safe to do so. Caesar, Cleopatra, Proteus and Endymion were able to return to normal operating service at different points inSeptember 2021 . While no damage was directly incurred by any of the assets held by the Mars joint venture that we have an interest in, damage to theWest Delta -143 facility was discovered after a comprehensive damage assessment and resulted in the facility remaining offline for repairs. OnNovember 5, 2021 , theWest Delta -143 offshore facilities safely re-started operations. With the facilities now operational, theMars Oil Pipeline resumed normal operations. Shippers provided notice that, effective as ofAugust 29, 2021 , Hurricane Ida constituted an event of force majeure under their current contracts, which has since been cancelled consistent with the resumption of normal operations of theMars Oil Pipeline . We estimate that this outage caused a reduction of approximately$8 million to$10 million to our cash available for distribution for the year endedDecember 31, 2021 relative to our financial outlook. For more information, refer to our risk factor titled "Hurricanes and other severe weather conditions, natural disasters or other adverse events or conditions could damage our pipeline systems or disrupt the operations of our customers, which could adversely affect our operations and financial condition."
COVID-19
Uncertainties related to COVID-19 continue to affect the oil and gas industry, including the possibility of renewed restrictions on various commercial, social, and economic activities, thereby impacting the demand for crude oil, natural gas, and refined products. To limit the impact of COVID-19,BP Pipelines , as operator of our assets under the omnibus agreement, 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 volatility or the inability 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. 58 --------------------------------------------------------------------------------BP Pipelines and the third-party operators of our assets have taken steps and continue to actively work 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. However, there is no certainty that the measures we take will be ultimately sufficient.
Climate Change
In the bp Energy Outlook 2020, which is not incorporated into and does not form a part of this Annual Report or any other filings we make with theSEC , our Parent describes the potential implications of climate change and the energy transition on both primary energy demand and the energy system over the next 30 years, through three long-term scenarios. These scenarios are complex and subject to substantial uncertainty due to the many factors and assumptions involved in them, which are not detailed in this Form 10-K. BP2,River Rouge and Diamondback are operated byBP Pipelines personnel under the omnibus agreement. Any judgments and assumptions taken by our Parent could potentially result in adverse impacts on demand for our services, for which we cannot predict the speed or intensity of any such impacts at this time. For more information, see our risk factor "Increasing attention to ESG matters and conservation matters may impact our business."
How We Generate Revenue
Onshore Assets
We generate revenue on our onshore pipeline assets through published tariffs
(regulated by
We have entered into throughput and deficiency agreements withBP Products with respect to volumes transported on BP2,River Rouge and Diamondback that expireDecember 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. 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. 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 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 revenues on these pipelines are 59 -------------------------------------------------------------------------------- generated by 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 orFERC jurisdiction under certain circumstances in the future. Endymion generates the majority of its revenues from contractual fees applied to the transportation of oil into storage and from fees applied to per barrel movements of oil out of storage (including volume incentive discounts for 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.
Ursa is a crude oil gathering pipeline system that provides gathering and
transportation services under a joint tariff extending from the Ursa Tension Leg
Platform at Mississippi
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 and Mars 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, Mars is 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 and Environmental Safety
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;
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•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 KM
Phoenix'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.
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, 2021 and 2020, is shown in the table below: Years Ended December 31, 2021 2020 (in millions of dollars) Wholly Owned Assets Maintenance expenses $ 3.4$ 3.8 Maintenance capital expenditures 3.6
2.1
Maintenance capital recovery (1) (2.5)
(1.1)
Total Maintenance Spend - Wholly Owned Assets $ 4.5
(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.
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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 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. The ultimate magnitude and duration of the COVID-19 pandemic, resulting governmental restrictions on the mobility of consumers and the related impact on demand and theU.S. and global economy and capital markets is uncertain. As of the date of this Annual Report, all of our assets remain operational.
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 . 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 62 -------------------------------------------------------------------------------- commencingJuly 1, 2021 ("December 2020 Order"). Requests for rehearing of theDecember 2020 Order were filed withFERC . OnJanuary 20, 2022 ,FERC issued an order on rehearing that reverses itsDecember 2020 Order on the five-year review of the oil pipeline rate index.FERC lowered the index from PPI-FG plus 0.78% to PPI-FG minus 0.21%. The rehearing order also directs oil pipelines to recompute their rate ceiling levels forJuly 1, 2021 throughJune 30, 2022 , based upon the index of PPI-FG minus 0.21%, to be effectiveMarch 1, 2022 . Additionally,FERC issued a notice that adjusts the annual change in the oil pipeline rate index for the periodJuly 1, 2021 throughJune 30, 2022 , to implement the PPI-FG minus 0.21% index, explaining that oil pipelines must multiply theirJuly 1, 2020 throughJune 30, 2021 index ceiling levels by positive 0.984288 to recompute theirJuly 1, 2021 throughJune 30, 2022 index ceiling levels. OnMay 27, 2021 , theDepartment of Homeland Security's Transportation Security Administration ("TSA") announced Security Directive Pipeline-2021-01 that requires us, as a critical pipeline owner, to report confirmed and potential cybersecurity incidents to theDHS Cybersecurity and Infrastructure Security Agency ("CISA") and to designate a Cybersecurity Coordinator. It also requiresBP Pipelines and the third-party operators of our assets to review current practices as well as to identify any gaps and related remediation measures to address cyber-related risks and report the results toTSA and CISA within 30 days. We designated a Cybersecurity Coordinator, developed a plan to comply with mandatory reporting timeframes and completed the vulnerability assessment required under this directive onJune 25, 2021 . OnJuly 20, 2021 , theTSA issued a second Security Directive. We have evaluated the impacts of this second directive to our pipeline business and have made significant progress in compliance.
Financing
We expect to fund future capital expenditures from a mixture of sources, including cash on hand, cash flow from operations and borrowings available under our credit facility.
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). However, the Merger Agreement contains a provision that, during the period fromDecember 19, 2021 until consummation of the Merger, in no event will any regular quarterly cash distribution declared or paid to unitholders be less than$0.3475 per unit.
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. We have incurred$0.3 million ,$0.4 million , and$1.6 million in response expenses during the years endedDecember 31, 2021 , 2020, and 2019 respectively. Reimbursable costs associated with the incident were offset with an insurance receivable. We received$2.5 million and$2.9 million of insurance proceeds during the years endedDecember 31, 2021 and 2020, respectively. Future proceeds from insurance claims would be recognized as a gain. 63 --------------------------------------------------------------------------------
Results of Operations
The following tables and discussion contain a summary of our consolidated
results of operations for the years ended
Years Ended December 31,
2021 2020
(in millions of dollars)
Revenue $ 119.9 $ 128.9
Costs and expenses
Operating expenses 20.5 19.6
Maintenance expenses 3.4 3.8
General and administrative 20.2 16.9
Depreciation 2.8 2.5
Property and other taxes 0.8 0.7
Total costs and expenses 47.7 43.5
Operating income 72.2 85.4
Income from equity method investments 106.5 110.8
Interest expense, net 4.3 7.9
Net income 174.4 188.3
Less: Net income attributable to non-controlling
interests 22.3 19.9
Net income attributable to the Partnership $ 152.1 $ 168.4
Adjusted EBITDA(1) $ 196.7 $ 213.2 Less: Adjusted EBITDA attributable to non-controlling interests
27.3 24.3
Adjusted EBITDA attributable to the Partnership(1) $ 169.4
$ 188.9
(1) See Reconciliations of Non-GAAP Measures below.
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Years Ended December 31,
Pipeline throughput (thousands of barrels per day)(1) 2021 2020
BP2 287 276
Diamondback 44 63
River Rouge 60 69
Total Wholly Owned Assets 391 408
Mars 431 490
Caesar 173 161
Cleopatra(2) 20 18
Proteus 228 214
Endymion 228 214
Mardi Gras Joint Ventures 649 607
Ursa 59 78
Average revenue per barrel ($ per barrel)(3)
Total Wholly Owned Assets $ 0.81 $ 0.77
Mars 1.26 1.35
Mardi Gras Joint Ventures 0.59 0.59
Ursa 0.89 0.90
(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 decreased by
•Decrease of$9.2 million from the recognition of deficiency revenue compared to the prior period, in part reflecting the lower volume threshold in the MVC agreement. •Decrease of$6.5 million in tariff revenue driven by a$5.4 million decrease onRiver Rouge , and a$3.7 million decrease on Diamondback, partially offset by a$2.6 million increase on BP2. •Increase of$6.7 million in FLA revenue from BP2 driven by an increase in throughput volume and an increase in FLA prices realized. •Throughput volume decreased by 6.9 millions barrels driven by a 3.3 million barrels decrease onRiver Rouge , a 7.2 million barrels decrease on Diamondback, partially offset by an increase of 3.6 million barrels on BP2.
Operating expenses increased by
Maintenance expenses decreased by
General and administrative expenses increased by$3.3 million or 19.5% in the year endedDecember 31, 2021 , compared to the year endedDecember 31, 2020 , primarily driven by a$1.9 million increase in merger-related expenditures and a$1.4 million increase in the omnibus agreement annual fee. 65 -------------------------------------------------------------------------------- Income from equity method investments decreased by$4.3 million , or 3.9%, in the year endedDecember 31, 2021 compared to the year endedDecember 31, 2020 primarily due to the impacts of Hurricane Ida on Mars, offset by an increase in earnings from theMardi Gras Joint Ventures . Interest expense, net decreased by$3.6 million in the year endedDecember 31, 2021 compared to the year endedDecember 31, 2020 due to lower interest rates tied to LIBOR. Net income attributable to non-controlling interests increased by$2.4 million or 12.1% in the year endedDecember 31, 2021 compared to the year endedDecember 31, 2020 , due to the increase in earnings from Mardi Gras in the period.
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,
2021 2020
(in millions of dollars)
Reconciliation of Adjusted EBITDA and Cash Available for
Distribution to Net Income
Net income $ 174.4 $ 188.3
Add:
Depreciation 2.8 2.5
Interest expense, net 4.3 7.9
Cash distributions received from equity method investments 121.7 125.3
Less:
Income from equity method investments 106.5 110.8 Adjusted EBITDA 196.7 213.2
Less:
Adjusted EBITDA attributable to non-controlling interests 27.3 24.3 Adjusted EBITDA attributable to the Partnership 169.4 188.9
Add:
Maintenance capital recovery(1) 2.5 1.1
Less:
Net interest paid/(received) 4.3 11.3 Maintenance capital expenditures 3.6 2.1 Cash reserves(2) (0.1) (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,
2021 2020
(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
$ 188.1 $ 190.4 Add: Interest expense, net 4.3 7.9
Distribution in excess of earnings from equity method investments
14.6 13.0
Less:
Change in other assets and liabilities 10.0 (2.1) Non-cash adjustments 0.3 0.2 Adjusted EBITDA 196.7 213.2 Less: Adjusted EBITDA attributable to non-controlling interests 27.3 24.3 Adjusted EBITDA attributable to the Partnership 169.4 188.9
Add
Maintenance capital recovery(1) 2.5 1.1
Less:
Net interest paid/(received) 4.3 11.3 Maintenance capital expenditures 3.6 2.1 Cash reserves(2) (0.1) (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).
Capital Resources and Liquidity
Currently, we expect our primary ongoing sources of liquidity to be cash generated from operations (including distributions 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. We currently have no transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities or impact our liquidity.
Based upon current expectations for the fiscal year 2022, we believe that our
cash on hand and cash flow from operations will be sufficient to fund our
operations for 2022. As of
The existing credit facility, which as ofDecember 31, 2021 has$132 million available for borrowing, will terminate onOctober 30, 2022 . Our relationship with the affiliate of BP is stable and management has the intent and believes the Partnership will have the ability to amend the credit facility, if necessary. 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. Our relationship with the affiliate of BP is stable and management has the intent and believes the Partnership will have the ability to consummate a refinance, if necessary. If a refinance is not consummated, the$468 million principal will need to be paid on or beforeFebruary 24, 2025 .
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 of December 67 --------------------------------------------------------------------------------
31, 2021. 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 the 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 an 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, 2021 , 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$188.1 million in cash flow from operating activities in the year endedDecember 31, 2021 , compared to the$190.4 million generated in the year endedDecember 31, 2020 . The$2.3 million decrease in cash flows from operations primarily resulted from a$14.4 million decrease in net income and distributions of earnings received from equity method investments, offset by net increases from working capital changes of approximately$12.1 million . Changes in working capital were principally driven by a$6.3 million decrease in prepaid insurance expenses combined with a$4.0 million increase in current liabilities. Investing Activities. Our cash flows used in investing activities were$0.4 million in the year endedDecember 31, 2021 and cash flows generated by investing activities were$12.4 million in the year endedDecember 31, 2020 . The$12.8 million decrease in cash inflows from investing activities is primarily due to an increase of$13.7 million in funds used for capital expenditures, primarily related to the River Rouge onshore capacity increase project, a decrease of$0.7 million from proceeds from insurance claims related toGriffith Station incident, partially offset by an increase of$1.6 million in distribution in excess of earnings from equity method investments. Financing Activities. Our cash flows used in financing activities were$177.7 million in the year endedDecember 31, 2021 and$174.7 million in the year endedDecember 31, 2020 . The$3.0 million increase in cash outflows used in financing activities is due to distributions to non-controlling interests in Mardi Gras.
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
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--------------------------------------------------------------------------------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, 2021 and 2020, is shown in the table below: Years Ended December 31, 2021 2020 (in millions of dollars) Cash spent on expansion capital expenditures $ 13.6$ 1.4 Cash spent on maintenance capital expenditures 3.6 2.1 Increase in accrued capital expenditures 0.1 3.9
(Decrease) Increase in capital expenditures reimbursable to our (0.3)
0.3
Parent
Total capital expenditures incurred $ 17.0$ 7.7 In the year 2021, we incurred$12.9 million expansion capital expenditures for the River Rouge onshore capacity increase project and$4.1 million maintenance capital expenditures primarily associated with the Griffith Station Electrical and Controls project. In the year 2020, we incurred$4.1 million expansion capital expenditures for the River Rouge onshore capacity increase project and$3.6 million maintenance capital expenditures. The maintenance capital expenditures were primarily associated with BP2 motor purchase and installation, andGriffith Station recovery which included a building, lighting, power, relay and PLC panels.
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 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. 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, 2021 , the Partnership's equity method investments balance was$504.7 million , and for the year endedDecember 31, 2021 , the Partnership's income from equity method investments was$106.5 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, 2021 and 2020, there were no indicators of an other-than-temporary impairment identified. 69 --------------------------------------------------------------------------------
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 toBP Products for deficiency volumes under its minimum volume commitments, if any, are recorded in deferred revenues and credits on our consolidated balance sheets, asBP Products has the right to make up the deficiency volumes within the measurement period specified by the agreements. We consider this deferred revenue as breakage revenue and evaluate applicable accounting guidance to determine 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 timing of recognition of breakage revenue requires management to make judgements that primarily impact our interim financial statements since our most significant MVC contracts have a 12-month measurement period that coincides with the calendar year. 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.
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