All of our pipelines are operated via satellite, microwave and radio systems from our central control room located in Artesia, New Mexico. We also monitor activity at our terminals from this control room. The control center operates with state-of-the-art Supervisory Control and Data Acquisition, or SCADA, systems. Our control center is equipped with computer systems designed to continuously monitor operational data, including refined product and crude oil throughput, flow rates, and pressures. In addition, the control center monitors alarms and throughput balances. The control center operates remote pumps, motors, engines, and valves associated with the delivery of refined products and crude oil. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions outside of pre-established parameters occur, and provide for remote-controlled shutdown of pump stations on the pipelines.
Our refinery processing units are integrated in HFC's El Dorado, Kansas refinery and HFC's Woods Cross, Utah refinery and are used to support their daily operations, which chemically transform crude oil into various petroleum products, including gasoline, diesel, LPGs and asphalt.
The El Dorado units were first operational in the third and fourth quarters of 2015 and the Woods Cross units were first operational in the second quarter of 2016. These units operate on a daily basis until they are taken down for large-scale maintenance, which can be every two to four years and could last from two to four weeks. During this maintenance period (turnaround), the minimum feedstock throughput is adjusted so that HFC is not penalized for HEP's maintenance requirements.
HEP's revenue is primarily generated from the minimum throughput commitments, and HEP charges a tolling fee per barrel or thousand standard cubic feet of throughput. The tolling fee is meant to provide HEP with revenue that surpasses the amount of its expected operating costs, which include natural gas and maintenance. On any calendar month where the cost of natural gas exceeds what is included in the tolling fee, HEP will charge HFC for recovery of this additional cost. Additionally, if turnaround costs are more than expected after the first turnaround for each unit, the tolling fee will be permanently adjusted, one time, to recover these costs.
The feedstock used by the naphtha fractionation unit is desulfurized naphtha, which is produced by the refinery earlier in the refining process. Desulfurized naphtha is a key component in gasoline, and this unit is used to reduce the level of benzene precursors. This allows the resulting product to be processed further to produce gasoline that meets regulatory requirements. The unit's feedstock capacity is 50,000 bpd of desulfurized naphtha.
The hydrogen unit primarily uses natural gas as a feedstock to produce hydrogen gas that is used in HFC's operation of its El Dorado, Kansas refinery. This feedstock is supplied from purchased natural gas. The hydrogen unit's natural gas feedstock capacity is 6,100 thousand standard cubic feet per day.
The crude unit is comprised of several components, primarily an atmospheric distillation tower, a desalter and heat exchangers, together referred to as the crude unit. The crude unit uses black wax and other crudes as feedstock and is the first step in the refining process to separate crude into refined products. This process is accomplished by heating the crude until it is distilled into various intermediate streams. These intermediate streams are further refined downstream of the crude unit. The initial rejection of major contaminants is also performed by the crude unit. Its feedstock capacity is 15,000 bpd of crude oil.
The polymerization unit uses the LPGs, propylene and butylene, from the FCC unit and polymerizes them into high octane gasoline blendstock using heat and catalysts. This gasoline blendstock is combined with other blendstocks in the refinery to make finished gasoline. The polymerization unit's feedstock capacity is 2,500 bpd.
If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us the amount of any shortfall in cash by the last day of the month following the end of the quarter. Under certain of the agreements, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.
A significant reduction in revenues under these agreements could have a material adverse effect on our results of operations.
Furthermore, if new laws or regulations that affect terminals or pipelines are enacted that require us to make substantial and unanticipated capital expenditures at the pipelines or terminals, we will have the right after we have made efforts to mitigate their effects to negotiate a monthly surcharge on HFC for the use of the terminals or to file for an increased tariff rate for use of the pipelines to cover HFC’s pro rata portion of the cost of complying with these laws or regulations including a reasonable rate
of return. In such instances, we will negotiate in good faith with HFC to agree on the level of the monthly surcharge or increased tariff rate.
Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”), we pay HFC an annual administrative fee ($2.52.6 million in 2018)2021) for the provision by HFC or its affiliates of various general and administrative services to us. This fee includes expenses incurred by HFC to perform centralized corporate functions, such as executive management, legal, accounting, treasury, information technology and other corporate services, including the administration of employee benefit plans. This fee does not include the salaries of personnel employed by HFC who perform services for us on behalf of HLS or the cost of their employee benefits, which are separately charged to us by HFC. We also reimburse HFC and its affiliates for direct expenses they incur on our behalf. In addition, we also pay for our own direct general and administrative costs, including costs relating to operating as a separate publicly held entity, such as costs for preparation of partners’ K-1 tax information, SEC filings, directors’ compensation, and registrar and transfer agent fees.
Under HLS’s secondment agreement with HFC (the “Secondment Agreement”), certain employees of HFC are seconded to HLS, our ultimate general partner, to provide operational and maintenance services for certain of our processing, refining, pipeline and tankage assets, and HLS reimburses HFC for its prorated portion of the wages, benefits, and other costs of these employees for our benefit.
As a result of our physical integration with HFC’s refineries, our contractual relationship with HFC under the Omnibus Agreement and the HFC pipelines and terminals, tankage and throughput agreements, we believe that we will not face significant competition for barrels of crude oil transported to or refined products transported from HFC’s refineries, particularly during the terms of our long-term transportation agreements with HFC expiring between 20192022 and 2036. Additionally, under our throughput agreement with Delek expiring in 2020, we believe that we will not face significant competition for those barrels of refined products we transport from Delek’s Big Spring refinery.
However, we do face competition from other pipelines that may be able to supply the end-user markets of HFC or Delekother customers with refined products on a more competitive basis. Additionally, if HFC’s wholesale customers reduced their purchases of refined products due to the increased availability of cheaper product from other suppliers, decreased demand for refined products or for other reasons, the volumes transported through our pipelines could be reduced, which, subject to the minimum revenue commitments, could cause a decrease in cash and revenues generated from our operations.
The petroleum refining business is highly competitive. Among HFC’s competitors are some of the world’s largest integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems. HFC competes with independent refiners as well. Competition in particular geographic areas is affected primarily by the amounts of refined products produced by refineries located in such areas and by the availability of refined products and the cost of transportation to such areas from refineries located outside those areas.
In addition, we face competition from trucks that deliver product in a number of areas we serve. Although their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volumes in many areas we serve. The availability of truck transportation places some competitive constraints on us.
Our refined product terminals compete with other independent terminal operators as well as integrated oil companies based on terminal location, price, versatility and services provided. Our competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading arms. Historically, the significant majority of the throughput at our terminal facilities has come from HFC.
may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.
Our operation of pipelines, terminals, and associated facilities in connection with the transportation and storage of refined products and crude oil is subject to stringent and complex federal, state, and local laws and regulations governing the potential discharge of materials into the environment, or otherwise relating to the protection of human health and the environment and natural resources. These laws and regulations may require us to obtain permits for our operations or result in the imposition of strict requirements relating to air emissions, and characteristics and composition of gasoline and diesel fuels, biodiversity, wastewater discharges, waste management, orprocess safety and risk management, spill planning and prevention and the remediation of spills, leaks and other contamination. As with the industry generally, compliance with existing, changing, and anticipatednew laws, regulations, interpretations and regulationsguidance increases our overall cost of business, including our capital costs to construct, maintain, upgrade and upgradeoperate equipment and facilities. While theseThese laws and regulations affect our operations, maintenance, capital expenditures and net income, we believe that they do not affect our competitive position given that the operationsas well as those of our competitors are similarly affected. However, thesecompetitors. These existing and any new laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, and injunctions, and construction bans or delays.delays; delays in the permitting, development or expansion of projects; limitations or prohibitions on certain operations; and reputational harm. In addition, many environmental laws contain citizen suit provisions, allowing environmental groups to bring suits to enforce compliance with environmental laws. Environmental groups frequently challenge pipeline infrastructure projects. Moreover, a major discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including boththe cost of remediation and restoration of any damaged natural resources, the cost to comply with applicable laws and regulations, and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.
Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Some environmental laws impose liability without regard to fault or the legality of the original act on certain classes of persons that contributed to the releases of hazardous substances or petroleum hydrocarbon substances into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Site conditions, including soils and groundwater, are being evaluated at a few of our properties where operations may have resulted in releases of hydrocarbons and other wastes, none of which we believe will have a significant effect on our operations since the remediation of such releases would be covered under environmental indemnification agreements.
Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers.
We have an environmental agreement with Delek with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Delek in 2005, under which Delek will indemnify us subject to certain monetary and time limitations.
We may experience future releases into the environment from our pipelines and terminals or discover historical releases that were previously unidentified or not assessed. Although we maintain an extensive inspection and audit program designed, as applicable, to prevent, detect and address these releases promptly, damages and liabilities incurred due to any future environmental releases from our assets have the potential to substantially affect our business.
Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business operations. If any of the following risks were to actually occur, our business, financial condition, results of operations or treatment of unitholders could be materially and adversely affected.
The headings provided in this Item 1A. are for convenience and reference purposes only and shall not affect or limit the extent or interpretation of the risk factors.
Operations at any of HFC's refineries could be partially or completely shut down, temporarily or permanently, as the result of:
The effect on us of any shutdown would depend on the length of the shutdown and the extent of the refinery operations affected by the shutdown. We have no control over the factors that may lead to a shutdown or the measures HFC may take in response to a shutdown. HFC makes all decisions at each of its refineries concerning levels of production, regulatory compliance, refinery turnarounds (planned shutdowns of individual process units within the refinery to perform major maintenance activities), labor relations, environmental remediation, emission control and capital expenditures and is responsible for all related costs. HFC is not under no contractual obligation to us to maintain operations at its refineries.
Furthermore, HFC's obligations under the long-term pipeline and terminal, tankage, tolling and throughput agreements with us would be temporarily suspended during the occurrence of a force majeure event that renders performance impossible with respect to an asset for at least 30 days. If such an event were to continue for a year, we or HFC could terminate the agreements. The occurrence of any of these events could reduce our revenues and cash flows.
For the year ended December 31, 2018, Delek accounted for 7% of the combined revenues of our petroleum product and crude pipelines and of our terminals and truck loading racks, including revenues we received from Delek under a capacity lease agreement. If Delek satisfies only its minimum obligations under the long-term pipeline and terminal, tankage and throughput agreements that it has with us or is unable to meet its minimum annual payment commitment for any reason, including due to prolonged downtime or a shutdown at Delek’s refineries, our revenues and cash flow would decline.
A decline in production at Delek's Big Spring refinery could reduce materially the volume of refined products we transport and terminal for Delek and, as a result, our revenues could be materially adversely affected. The Big Spring refinery could partially or completely shut down its operations, temporarily or permanently, due to factors affecting its ability to produce refined products or for planned maintenance or capital projects. Such factors would include the factors discussed above under the discussion of risk with respect to the Navajo refinery.
The effect on us of any shutdown depends on the length of the shutdown and the extent of the refinery operations affected. We have no control over the factors that may lead to a shutdown or the measures Delek may take in response to a shutdown. Delek makes all decisions and is responsible for all costs at the Big Spring refinery concerning levels of production, regulatory compliance, refinery turnarounds, labor relations, environmental remediation, emission control and capital expenditures.
In addition, under our throughput agreement with Delek, if we are unable to transport or terminal refined products that Delek is prepared to ship, then Delek has the right to reduce its minimum volume commitment to us during the period of interruption. If a force majeure event occurs, we or Delek could terminate the Delek pipelines and terminals agreement after the expiration of certain time periods. The occurrence of any of these events could reduce our revenues and cash flows.
Due to our lack of asset and geographic diversification, an adverse developmentsdevelopment in our businesses could materially and adversely affect our financial condition, results of operations or cash flows.
We rely exclusively on the revenues generated fromA large concentration of our business.pipeline assets serve HFC's Navajo refinery. Due to our lack oflimited asset and geographic diversification, especially our large concentration of pipeline assets serving the Navajo refinery, an adverse development in our business (including adverse developments due toas a result of catastrophic events or weather, terrorist or cyberattacks, vandalism, public health crisis, decreased supply of crude oil and feedstocks and/or decreased demand for refined petroleum products), could have a significantly greater impact on our financial condition, and results of operations or cash flows than if we maintained more diverse assets in more diverse locations.
The COVID-19 pandemic or any other widespread outbreak of an illness or pandemic or other public health crisis, and actions taken in response thereto, as well as certain developments in the global oil markets, have had and may continue to have a material adverse effect on our operations, business, financial condition, results of operations or cash flows.
Our leveragebusiness depends in large part on the demand for the various petroleum products we transport, terminal and store in the markets we serve. COVID-19’s spread across the globe and government regulations in response thereto have negatively affected worldwide economic and commercial activity, impacted global demand for oil, gas and refined products, and created significant volatility and disruption of financial and commodity markets. Other factors expected to impact crude oil supply include production levels implemented by OPEC members, other large oil producers such as Russia and domestic and Canadian oil producers. Please see “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Impact of COVID-19 on Our Business”.
In addition, the volume of crude oil or refined products we transport, terminal or store depends on many other factors outside of our control, some of which include:
•changes in domestic demand for, and the marketability of, refined products, and in turn, for crude oil and its transportation, due to governmental regulations, including travel bans and restrictions, quarantines, shelter in place orders, and shutdowns;
•the ability of HFC, our other customers or our joint ventures’ other customers to fulfill their respective contractual obligations or any material reduction in, or loss of, revenue from our customers or our joint ventures’ customers;
•increased price volatility, including the prices our customers or our joint ventures’ customers pay for crude oil and other raw materials and receive for their refined and finished lubricant products;
•the health of our workforce, including contractors and subcontractors, and their access to our facilities, which could result in a full or partial shutdown of our facilities if a significant portion of the workforce at a facility is impacted or if a significant portion of the workforce in our control room is impacted;
•the availability, distribution and effectiveness of vaccines for COVID-19;
•the ability or willingness of our or our joint ventures’ current vendors and suppliers to provide the equipment or parts for our or our joint ventures’ operations or otherwise fulfill their contractual obligations, potentially causing our delay or failure in construction projects or to deliver crude oil or refined products on a timely basis or at all;
•increased potential for the occurrence of operational hazards, including terrorism, cyberattacks or vandalism, as well as information system failures or communication network disruptions;
•increasing cost and reduced availability of capital for additional liquidity, growth or capital expenditures;
•delay by government authorities in issuing or maintaining permits necessary for our business or our capital projects;
•shareholder activism and activities by non-governmental organizations to limit sources of funding for the energy sector;
•increasing costs of operation in relation to the COVID-19 outbreak, which costs may limitnot be fully recoverable or adequately covered by insurance; and
•the impact of any economic downturn, recession or other disruption of the U.S. and global economies and financial and commodity markets.
Adverse developments in the global economy or in regional economies could also negatively impact our customers and suppliers, and therefore have a negative impact on our business or financial condition.In the event of adverse developments or stagnation in the economy or financial markets, our customers may experience deterioration of their businesses, reduced demand for their products, cash flow shortages and difficulty obtaining financing. As a result, existing or potential customers might delay or cancel plans to use our services and may not be able to fulfill their obligations to us in a timely fashion.Further, suppliers may experience similar conditions, which could impact their ability to fulfill their obligations to us.
The spread of COVID-19 has caused us to modify our business practices (including limiting employee and contractor presence at our work locations and to sequester employees critical to the operation of our control room from time to time as needed), and we may take further actions as may be required by government authorities or that we determine are in the best interests of our employees, contractors, customers, suppliers and communities. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, and our ability to borrow additional funds, comply withperform critical functions could be adversely impacted.
The effects of COVID-19 are difficult to predict and the termsduration of any potential business disruption or the extent to which it may negatively affect our operating results or our liquidity is uncertain. The extent to which the pandemic will continue to impact our business results and operations remains uncertain in light of the rapidly evolving environment, duration and severity of the spread of the virus, emerging variants, vaccine and booster effectiveness, public acceptance of safety protocols, and government measures, including vaccine mandates, designed to slow and contain the spread of COVID-19, among others, and, all of which are beyond our control. In addition, if the volatility and seasonality in the oil and gas industry were to increase, the demand for our services may decline. We continue to monitor the situation to assess further possible implications to our business and to take actions in an effort to mitigate adverse consequences. These effects of the COVID-19 pandemic, as well as the volatility in global oil markets, while uncertain, have, and may continue to, materially adversely affect our business, financial condition, results of operations and/or cash flows, as well as our ability to pay distributions to our common unitholders.
A material decrease in the supply, or a material increase in the price, of crude oil or other materials available to HFC's refineries and our pipelines and terminals, and a corresponding decrease in demand for refined products in the markets served by our pipelines and terminals, could reduce our revenues materially.
The volume of refined products we transport in our refined product pipelines depends on the level of production of refined products from HFC's refineries, which, in turn, depends on the availability of attractively-priced crude oil produced in the areas accessible to those refineries. In order to maintain or increase production levels at their refineries, our shippers must continually contract for new crude oil supplies. A material decrease in crude oil production from the fields that supply their refineries, as a result of depressed commodity prices, decreased demand, lack of drilling activity, natural production declines, catastrophic events or otherwise, could result in a decline in the volume of crude oil our shippers refine, absent the availability of transported crude oil to offset such declines. Such an event would result in an overall decline in volumes of refined products transported through our pipelines and therefore a corresponding reduction in our cash flow. In addition, the future growth of our indebtednessshippers' operations will depend in part upon whether our shippers can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in their currently connected supplies.
Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We and our shippers have no control over producers or capitalize on business opportunities.
Astheir production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation, global market conditions, actions by foreign nations and the availability and cost of December 31, 2018,capital, or over the principallevel of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline. Similarly, a material increase in the price of crude oil supplied to refineries without an increase in the market value of the products produced by the refineries, either temporary or permanent, which causes a reduction in the production of refined products at the refineries, would cause a reduction in the volumes of refined products we transport, and our total outstanding debt was $1,423 million. cash flow could be adversely affected.
In addition, periods of disruption in the global supply chain, including as a result of COVID-19, have caused shortages in the equipment and parts necessary to operate our facilities and to complete our capital projects. Certain suppliers have experienced, and may continue to experience, delays related to a variety of factors, including logistical delays and component shortages from vendors. We continue to monitor the situation and work closely with our suppliers to minimize disruption to our operations as a result of supply chain interruptions.
Finally, our business depends in large part on the demand for the various petroleum products we gather, transport and store in the markets we serve. Reductions in that demand adversely affect our business. Market demand varies based upon the different end uses of the petroleum products we gather, transport and store. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, government regulation, global pandemic, technological advances in fuel economy and energy-generation devices, exploration and production activities, and actions by foreign nations, any of which could reduce the demand for the petroleum products in the areas we serve.
Competition from other pipelines that may be able to supply our shippers' customers with refined products at a lower price could cause us to reduce our rates or could reduce our revenues.
We and our shippers could face increased competition if other pipelines are able to supply our shippers' end-user markets competitively with refined products. For example, increased supplies of refined product delivered by Kinder Morgan's El Paso to Phoenix pipeline could result in additional downward pressure on wholesale-refined product prices and refined product margins in El Paso and related markets. Additionally, further increases in products from Gulf Coast refiners entering the El Paso and Arizona markets on this and other pipelines and a resulting increase in the demand for shipping product on the interconnecting common carrier pipelines could cause a decline in the demand for refined product from HFC. This could reduce our opportunity to earn revenues from HFC in excess of its minimum volume commitment obligations.
An additional factor that could affect some of HFC's markets is excess pipeline capacity from the West Coast into our shippers' Arizona markets. Additional increases in shipments of refined products from the West Coast into our shippers' Arizona markets could result in additional downward pressure on refined product prices that, if sustained over the long term, could influence product shipments by HFC to these markets.
Any reduction in the capacity of, or the allocations to, our shippers on interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals.
HFC and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, catastrophic events, terror or cyberattacks, vandalism or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volumes of refined products over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines or through our terminals.
Our business may suffer due to a change in the composition of our Board of Directors, the departure of any of our key senior executives or other key employees who provide services to us, or if certain of our executive officers, who also allocate time to our general partner and its affiliates, do not have enough time to dedicate to our business. Furthermore, a shortage of skilled labor or disruptions in the labor force that provides services to us may make it difficult for us to maintain labor productivity.
Our future performance depends to a significant degree upon the continued contributions of HLS's Board of Directors, key senior executives and key senior employees who provide services to us. Also, our business depends on the continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not currently maintain “key person” life insurance for any executives. Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks. A shortage of trained workers due to retirements or otherwise could have an adverse impact on productivity and costs, which could adversely affect our operations.
Our general partner shares officers and administrative personnel with HFC to operate both our business and HFC's business. These officers face conflicts regarding the allocation of their and other employees' time, which may affect adversely our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates above current levels. Various limitations in our Credit Agreement and the indenture for our 6.0% senior notes due 2024 (the "6% Senior Notes") may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.condition.
Our leverage could have important consequences. We require substantial cash flow to meet our payment obligations with respect to our indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to then-current economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit Agreement to service our indebtedness. However, a significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or aA portion of our debt or sell assets. We cannot guarantee that we would be able to refinance our existing indebtedness at maturity or otherwise or sell assets on termsHFC's employees that are commercially reasonable.
The instruments governing our debt contain restrictive covenants that may preventseconded to us from engaging in certain beneficial transactions. Thetime to time are represented by labor unions under collective bargaining agreements governing our debt generally require us to comply with various affirmative and negative covenants including the maintenance of certain financial ratios and restrictions on incurring additional debt, entering into mergers, consolidations and sales of assets, making investments and granting liens. Our leverage may affect adversely our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisitions, construction or development activities, or to otherwise realize fully the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage also may make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.
Weexpiration dates. HFC may not be able to obtain fundingrenegotiate the collective bargaining agreements when they expire on acceptablesatisfactory terms or at all because of volatility and uncertainty in the credit and capital markets. Thisall. A failure to do so may hinder or prevent us from meetingincrease our future capital needs.
The domestic and global financial markets and economic conditions are disrupted and volatile from time to time due to a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, including U.S. government shutdowns, weak economic conditions and uncertainty in the financial services sector.costs. In addition, existing labor agreements may not prevent a future strike or work stoppage, and any work stoppage could negatively affect our results of operations and financial condition.
If we are unable to complete capital projects at their expected costs or in a timely manner, if we incur increased maintenance or repair costs on assets, or if the fixed-income markets have experienced periodsmarket conditions assumed in our project economics deteriorate, our financial condition, results of extreme volatility, which negatively impacted market liquidity conditions. As a result, theoperations, or cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving construction of raising money in the debtnew facilities (or improvements and equityincreased maintenance or repair expenditures on our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital markets has increased substantially at times while the availability of funds from these markets diminished significantly. In particular,spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of concerns about the stabilitynumerous factors, such as:
•third-party challenges to, denials, or delays in issuing requisite regulatory approvals and/or permits;
•societal and political pressures and other forms of financial markets generally and the solvency of lending counterparties specifically,opposition;
•compliance with or liability under environmental or pipeline safety regulations;
•unplanned increases in the cost of obtaining money from the credit markets may increaseconstruction materials or labor;
•disruptions in transportation of modular components and/or construction materials;
•severe adverse weather conditions, natural disasters, terror or cyberattacks, domestic vandalism other events (such as many lendersequipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar termssuppliers;
•shortages of sufficiently skilled labor, or at all and reduce, orlabor disagreements resulting in some cases cease, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations.unplanned work stoppages;
Due to these factors, we cannot be certain that new•market-related increases in a project's debt or equity financing will be available on acceptable terms. If funding is not available when needed,costs; and/or
•nonperformance or is available only on unfavorable terms, we may be unable to:force majeure by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.
meet our obligations as they come due;
execute our growth strategy;
complete future acquisitions or construction projects;
take advantage of other business opportunities; or
respond to competitive pressures.
Any of the above could have a material adverse effect on our revenues and results of operations.
We maymay not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities, if our assumptions concerning population growth are inaccurate, or if an agreement cannot be reached with HFC for the acquisition of assets on which we have a right of first offer.
Our strategy contemplates growth through the development and acquisition of crude, intermediate and refined products transportation and storage assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses, either from HFC or third parties, to enhance our ability to compete effectively and diversifying our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating and/or pursuing, potential joint ventures, stand-alone projects or other transactions that we believe will present opportunities to realize synergies, expand our role in our chosen businesses and increase our market position.
We will require substantial new capital to finance the future development and acquisition of assets and businesses. Any limitations on our access to capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, or if the
development or acquisition opportunities are on terms that do not allow us to obtain appropriate financing, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, credit ratings, covenants, underwriting or loan origination fees and similar charges we pay to lenders.
In addition, we experience competition for the types of assets and businesses we have historically purchased or acquired. High competition, particularly for a limited pool of assets, may result in higher, less attractive asset prices, and therefore, we may lose to more competitive bidders. Such occurrences limit our ability to execute our growth strategy, which may materially adversely affect our ability to maintain or pay higher distributions in the future.
Our growth strategy also depends upon:
•the accuracy of our assumptions about growth in the markets that we currently serve or have plans to serve in the Southwestern, Northwest and Mid-Continent regions of the United States;
•HFC's willingness and ability to capture a share of additional demand in its existing markets; and
•HFC's willingness and ability to identify and penetrate new markets in the Southwestern, Northwest and Mid-Continent regions of the United States.
If our assumptions about increased market demand prove incorrect, HFC may not have any incentive to increase refinery capacity and production or shift additional throughput to our pipelines, which would adversely affect our growth strategy.
Our Omnibus Agreement with HFC provides us with a right of first offer on certain of HFC’s existing or acquired logistics assets. The consummation and timing of any future acquisitions of these assets will depend upon, among other things, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to the assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions pursuant to our right of first offer. In addition, certain of the assets covered by our right of first offer may require substantial capital expenditures in order to maintain compliance with applicable regulatory requirements or otherwise make them suitable for our commercial needs. For these or a variety of other reasons, we may decide not to exercise our right of first offer if and when any assets are offered for sale, and our decision will not be subject to unitholder approval. In addition, our right of first offer may be terminated upon a change of control of HFC.
We are exposed to the credit risks and certain other risks, of our key customers, vendors, and other counterparties.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers, vendors or other counterparties. We derive a significant portion of our revenues from contracts with key customers, including HFC and Delek under their respective pipelines and terminals, tankage, tolling and throughput agreements. To the extent that our customers may be unable to meet the specifications of their customers, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers.
Mergers among our existing customers could provide strong economic incentives for the combined entities to use systems other than ours, and we could experience difficulty in replacing lost volumes and revenues. Because a significant portion of our operating costs are fixed, a reduction in volumes would result not only in a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and make distributions to unitholders.
If any of our key customers default on their obligations to us, our financial results could be adversely affected. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. In addition, nonperformance by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability to successfully conduct our business.
Any substantial increase in the nonpayment and/or nonperformance by our customers or vendors could have a material adverse effect on our results of operations and cash flows.
In addition, in connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various counterparties, including HFC, have agreed to indemnify us, subject to certain limitations, for:
certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition;
certain matters arising from the pre-closing ownership and operation of assets; and
ongoing remediation related to the assets.
Our business, results of operation, cash flows and our ability to make cash distributions to our unitholders could be adversely affected in the future if third parties fail to satisfy an indemnification obligation owed to us.
Competition from other pipelines that may be able to supply our shippers' customers with refined products at a lower price could cause us to reduce our rates or could reduce our revenues.
We and our shippers could face increased competition if other pipelines are able to supply our shippers' end-user markets competitively with refined products. For example, increased supplies of refined product delivered by Kinder Morgan's El Paso to Phoenix pipeline could result in additional downward pressure on wholesale-refined product prices and refined product margins in El Paso and related markets. Additionally, further increases in products from Gulf Coast refiners entering the El Paso and Arizona markets on this and other pipelines and a resulting increase in the demand for shipping product on the interconnecting common carrier pipelines could cause a decline in the demand for refined product from HFC and/or Delek. This could reduce our opportunity to earn revenues from HFC and Delek in excess of their minimum volume commitment obligations.
An additional factor that could affect some of HFC's and Delek's markets is excess pipeline capacity from the West Coast into our shippers' Arizona markets. Additional increases in shipments of refined products from the West Coast into our shippers' Arizona markets could result in additional downward pressure on refined product prices that, if sustained over the long term, could influence product shipments by HFC and Delek to these markets.
A material decrease in the supply, or a material increase in the price, of crude oil available to HFC's and Delek's refineries, and a corresponding decrease in demand for refined products in the markets served by our pipelines and terminals, could reduce our revenues materially.
The volume of refined products we transport in our refined product pipelines depends on the level of production of refined products from HFC's and Delek's refineries, which, in turn, depends on the availability of attractively-priced crude oil produced in the areas accessible to those refineries. In order to maintain or increase production levels at their refineries, our shippers must continually contract for new crude oil supplies. A material decrease in crude oil production from the fields that supply their refineries, as a result of depressed commodity prices, decreased demand, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil our shippers refine, absent the availability of transported crude oil to offset such declines. Such an event would result in an overall decline in volumes of refined products transported through our pipelines and therefore a corresponding reduction in our cash flow. In addition, the future growth of our shippers' operations will depend in part upon whether our shippers can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in their currently connected supplies.
Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. We and our shippers have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital, or over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline. Similarly, a material increase in the price of crude oil supplied to our shippers' refineries without an increase in the market value of the products produced by the refineries, either temporary or permanent, which causes a reduction in the production of refined products at the refineries, would cause a reduction in the volumes of refined products we transport, and our cash flow could be adversely affected.
Finally, our business depends in large part on the demand for the various petroleum products we gather, transport and store in the markets we serve. Reductions in that demand adversely affect our business. Market demand varies based upon the different end uses of the petroleum products we gather, transport and store. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, government regulation, technological advances in fuel economy and energy-generation devices, exploration and production activities, and actions by foreign nations, any of which could reduce the demand for the petroleum products in the areas we serve.
We may not be able to retain existing customers or acquire new customers.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain attractive revenues and cash flows depends on a number of factors outside our control, including competition from other pipelines and the demand for refined products in the markets that we serve. Our long-term pipeline and terminal, tankage and refinery processing unit throughput agreements with HFC and Delek expire beginning in 2019 through 2036.
Our operations are subject to evolving federal, state and local laws, regulations and permit/authorization requirements regarding environmental protection, health, operational safety and product quality. Potential liabilities arising from these laws, regulations and requirements could affect our operations and adversely affect our performance.
Our pipelines and terminal, tankage and loading rack operations are subject to increasingly stringent environmental and safety laws and regulations.
Environmental laws and regulations have raised operating costs for the oil and refined products industry, and compliance with such laws and regulations may cause us, and the HFC and Delek refineries that we support, to incur potentially material capital expenditures associated with the construction, maintenance, and upgrading of equipment and facilities. Future environmental, health and safety requirements (or changed interpretations of existing requirements) may impose new and/or more stringent requirements on our assets and operations and require us to incur potentially material expenditures to ensure our continued compliance.
Our operations require numerous permits and authorizations under various laws and regulations, including environmental and worker health and safety laws and regulations. In May 2015, the EPA published a final rule that has the potential to greatly expand the definition of "waters of the United States" under the federal Clean Water Act ("CWA") and the jurisdiction of the Corps. The rule is currently subject to a number of legal challenges in federal court. The agencies have also issued a stay delaying implementation of the rule for two years. On December 11, 2018, the EPA and the Corps proposed a revised definition of "waters of the United States" that is subject to public comment and final agency action. To the extent this final rule on the scope of the CWA results in waters associated with our operations as being considered "waters of the United States", we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. These and other authorizations and permits are subject to revocation, renewal, modification, or third party challenge, and can require operational changes that may involve significant costs to limit impacts or potential impacts on the environment and/or worker health and safety. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations and injunctions prohibiting our operations. In addition, major modifications of our operations could require modifications to our existing permits or expensive upgrades to our existing pollution control equipment that could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may also be required to address conditions discovered in the future that require environmental response actions or remediation. The transportation and storage of refined products produces a risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury or property damages to private parties and significant business interruption. Further, we own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. Environmental laws can impose strict, joint and several liability for releases of hazardous substances into the environment, and we could find ourselves liable for past releases caused by third parties. If we were to incur a significant liability pursuant to environmental laws or regulations, it could have a material adverse effect on us.
Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and other gases) are in various phases of discussion or implementation. These include requirements that HFC's and Delek's refineries report emissions of greenhouse gases to the EPA, and proposed federal, state, and regional initiatives that require (or could require) us, HFC and Delek to reduce greenhouse gas emissions from our facilities. Requiring reductions in greenhouse gas emissions could cause us to incur substantial costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse gas emissions programs, including the acquisition or maintenance of emission credits or allowances or the payment of carbon taxes. These requirements may affect HFC's and Delek's refinery operations and have an indirect adverse effect on our business, financial condition and results of our operations.
Requiring a reduction in greenhouse gas emissions and the increased use of renewable fuels could also decrease demand for refined products, which could have an indirect, but material, adverse effect on our business, financial condition and results of operations. For example, in 2010 and again in 2016, the EPA promulgated a rule establishing greenhouse gas emission standards for new-model passenger cars, light-duty trucks, and medium-duty passenger vehicles. Also in 2010, the EPA promulgated a rule establishing greenhouse gas emission thresholds for the permitting of certain stationary sources, which could require greenhouse emission controls for those sources. In addition, the EPA finalized new regulations in 2016 that limit methane emissions from certain new and modified oil and gas facilities. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards. In October 2018, proposed amendments to the 2016 standards were published in the Federal Register and the public comment period has closed, but a final rule has not yet been
published. As a result, the June 2016 rule and associated stay are still in effect. These requirements could, to the extent fully implemented, result in increased compliance costs and could also have an indirect adverse effect on our business due to reduced demand for crude oil and refined products, and a direct adverse effect on our business from increased regulation of our facilities.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
PHMSA regulations require pipeline operators to develop and implement integrity management programs for certain pipelines that, in the event of a pipeline leak or rupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including certain population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to perform a variety of heightened assessment, analysis, prevention and repair activities. Routine assessments under the integrity management program may result in findings that require repairs or other actions.
Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA or states that result in more stringent or costly safety standards could possibly have a substantial effect on us and similarly situated midstream operators.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
Among other things, the 2011 Amendments to the Pipeline Safety Act direct the Secretary of Transportation to study, and where appropriate based on the results and statutory factors, promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valves, leak detection, and other requirements. The 2011 Amendments also increased the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day and also from $1 million to $2 million for a related series of violations. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $209,002 per violation per day, with a maximum of $2,090,022 for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Amendments as well as any implementation of PHMSA regulations thereunder, reinterpretation of existing laws or regulations, or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect to the 2011 Amendments could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. Congress made additional changes to the Pipeline Safety Laws in 2016 that require PHMSA to issue additional regulations and perform studies that may or may not lead to additional requirements in the future. There are numerous, currently pending PHMSA rulemaking proceedings on a variety of pipeline safety topics. PHMSA’s rulemakings are intended to implement the 2011 and 2016 statutory changes, as well as additional policy priorities. PHMSA has delayed implementation of these regulations, but they are expected to become effective in 2019. In addition, Congress is likely to make further substantive changes to the Pipeline Safety Laws in 2019 or 2020 as part of its periodic reauthorization of PHMSA’s national safety programs. These changes could result in additional requirements. Any such new and expanded requirements may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.
Increases in interest rates could adversely affect our business.
We use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our credit facility. From time to time we use interest rate derivatives to hedge interest obligations on specific debt. In addition, interest rates on future debt offerings could be higher, causing our financing costs to increase accordingly. Our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates above current levels.
We may be subject to information technology system failures, network disruptions and breaches in data security.
Information technology system failures, network disruptions (whether intentional by a third party or due to natural disaster), breaches of network or data security, or disruption or failure of the network system used to monitor and control pipeline operations could disrupt our operations by impeding our processing of transactions, our ability to protect customer or company information and our financial reporting. Our computer systems, including our back-up systems, could be damaged or interrupted by power outages, computer and telecommunications failures, computer viruses, internal or external security breaches, events such as fires, earthquakes, floods, tornadoes and hurricanes, and/or errors by our employees. Although we have taken steps to address these concerns by implementing sophisticated network security and internal control measures, a system failure or data security breach could have a material adverse effect on our financial condition and results of operations.
Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions for which we may not be adequately insured.
Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions such as natural disasters, adverse weather, tornadoes, earthquakes, accidents, fires, explosions, hazardous materials releases cyber-attacks,or spills, terror or cyberattacks, vandalism, power failures, mechanical failures and other events beyond our control. These events could result in an injury, loss of life, or property damage or destruction, as well as a curtailment or interruption in our operations. In addition, third-party damage, mechanical malfunctions, undetected leaks in pipelines, faulty measurement or other errors may result in significant costs or lost revenues.
We may not be able to maintain or obtain insurance of the type and amount we desire at commercially reasonable rates and exclusions from coverage may limit our ability to recover the amount of the full loss in all situations. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.
There can be no assurance that insurance will cover all or any damages and losses resulting from these types of hazards. We are not fully insured against all risks incidentor incidents to our business and therefore, we self-insure certain risks. We are not insured against all environmental accidents that might occur, other than limited coverage for certain third party sudden and accidental claims.occur. Our property insurance includes business interruption coverage for lost profit arising from physical damage to our facilities. If a significant accident or event occurs that is self-insured or not fully insured, our operations could be temporarily or permanently impaired, our liabilities and expenses could be significant and it could have a material adverse effect on our financial position. Because of our distribution policy,partnership agreement requires us to distribute all available cash (less operating surplus cash reserves) to our unitholders, we do not have the same flexibility as other legal entities to accumulate cash to protect against underinsuredunder insured or uninsured losses.
Any reduction in the capacity of, or the allocations to, our shippers on interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals.
HFC, Delek and the other users of our pipelines and terminals are dependent upon connections to third-party pipelines to receive and deliver crude oil and refined products. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volumes of refined products over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines or through our terminals.
We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of products we distribute to meet certain quality specifications. In addition, we could be required to make substantial expenditures in the event of any changes in product quality specifications.
A significant portion of our operating responsibility on refined product pipelines is to ensure the quality and purity of the products loaded at our loading racks. If our quality control measures fail, off-specification product could be sent out to public gasoline stations. This type of incident could result in liability claims regarding damages caused by the off-specification fuel or could impact our ability to retain existing customers or to acquire new customers, any of which could have a material adverse impact on our results of operations and cash flows.
In addition, various federal, state and local agencies have the authority to prescribe specific product quality specifications of refined products. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets impact the fungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions could be adversely affected. In addition, changes in the product quality of the products we receive on our petroleum products pipeline system could reduce or eliminate our ability to blend products.
We do not own all of the land on which our pipeline systems and other assets are located, which could result in disruptions to our operations. Additionally, a change in the regulations related to a state’s use of eminent domain could inhibit our ability to secure rights-of-way for future pipeline construction projects. Finally, certain of our assets are located on or adjacent to Native American tribal lands.
GrowingWe do not own all of the land on which our pipeline systems and other assets are located, and we are, therefore, subject to the risk of increased costs or more burdensome terms to maintain necessary land use. We obtain the right to construct and operate pipelines and other assets on land owned by third parties and government agencies for specified periods. If we were to lose these rights through an inability to renew leases, right-of-way contracts or similar agreements, we may be required to relocate our pipelines or other assets and our business by constructing new pipelines and terminals, or expanding existing ones, subjectscould be adversely affected. Additionally, it may become more expensive for us to obtain new rights-of-way or leases or to renew existing rights-of-way or leases. If the cost of obtaining or renewing such agreements increases, it may adversely affect our operations and the cash flows available for distribution to unitholders.
The adoption or amendment of laws and regulations that limit or eliminate a state’s ability to exercise eminent domain over private property in a state in which we operate could make it more difficult or costly for us to secure rights-of-way for future pipeline construction risks.and other projects.
OneCertain of our pipelines are located on or adjacent to Native American tribal lands. Various federal agencies, along with each Native American tribe, promulgate and enforce regulations, including environmental standards, regarding operations on Native American tribal lands. In addition, each Native American tribe is a sovereign nation having the ways we may grow our businessright to enforce laws and regulations (including various taxes, fees, and other requirements and conditions) and to grant approvals independent from federal, state and local statutes and regulations. Following a decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, throughtribal land owned or at one time owned by an individual Native American landowner, bars condemnation of any interest in the construction of new pipelines and terminals orallotment. Consequently, the expansion of existing ones. The construction of a new pipeline or the expansion of aninability to condemn such allotted lands under circumstances where existing pipeline by adding horsepowerrights-of-way may soon lapse or pump stations or by adding a secondterminate serves as an additional impediment for pipeline along an existing pipeline, involves numerous regulatory, environmental, political,operations. Separately, in 2020, the Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished, and legal uncertainties, mostseveral state courts have subsequently used the analysis therein to find that other reservations in the state have not been disestablished. Although the ruling in McGirt indicates that it is limited to criminal law, the ruling has significant potential implications for civil law. At this time, we cannot predict how these jurisdictional issues may ultimately be resolved. These factors may increase our cost of which are beyond our control. For example, pipeline construction projects requiring federal approvals are generally subject to environmental review requirements under the National Environmental Policy Act, and must also comply with other natural resource review requirements imposed pursuant to the Endangered Species Act and the National Historic Preservation Act. These projects may not be completeddoing business on schedule (or at all) or at the budgeted cost. Native American tribal lands.
In addition, our revenuesindustry is subject to potentially disruptive activities by those concerned with the possible environmental impacts of pipeline routes. Activists, non-governmental organizations and others may not increase immediately uponseek to restrict the expendituretransportation of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of timecrude oil and we will not receive any material increases in revenues until after completion of the project. Moreover, we may construct facilities to capture anticipated future growth in demand for refined products in a region in whichby exerting social or political pressure to influence when, and whether, such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return,rights-of-way or permits
are granted. This interference could impact future pipeline development, which could adversely affectinterfere with or block expansion or development projects and could have a material adverse effect on our business, financial condition, results of operations and financial condition.
Rate regulation, changes to rate-making rules, or a successful challenge to the rates we charge may reduce our revenues and the amount of cash we generate.
The FERC regulates the tariff rates for interstate movements and state regulatory authorities regulate the tariff rates for intrastate movements on our pipeline systems. These regulatory agencies periodically implement new rules, regulations and terms and conditions of services, which may adversely affect the rates charged for our services.
The primary rate-making methodology of the FERC is price indexing. We use this methodology in all of our interstate markets. The indexing method allows a pipeline to increase its rates based on a percentage change in the PPI for finished goods. If the index falls, we will be required to reduce our rates that are based on the FERC's price indexing methodology if they exceed the new maximum allowable rate. If the FERC price indexing methodology permits a rate increase that is not large enough to fully reflect actual increases in our costs, we may need to file for a rate increase using an alternative method with a much higher burden of proof and without the guarantee of success. These FERC rate-making methodologies may limit our ability to set rates based onmake cash distributions to our true costs or may delay the use of rates that reflect increased costs.unitholders.
If a party with an economic interest were to file either a protest of our proposal for increased rates or a complaint against our existing tariff rates, or the FERC were to initiate an investigation of our existing rates, then our rates could be subject to detailed review. If our proposed rate increases were found to be in excess of levels justified by our cost of service, the FERC could order us to reduce our rates, and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found to be in excess of our cost of services, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively.
In March and July of 2018, the FERC issued a revised policy statement and order on rehearing in which it expressed a general policy that it will no longer permit an income tax allowance to be included in the cost-of-service rates for interstate pipelines structured as pass-through entities. The FERC also indicated that it will incorporate the effects of the revised policy statement and the effects of the income tax rate reductions provided by the Tax Cuts and Jobs Act of 2017 in its review of the oil pipeline index level to be effective July 1, 2021. Depending on how the FERC incorporates its most recent tax policy statement and the tax rate reduction into its next index review, which is scheduled to become effective in 2021, our ability to increase our index-based rates could be negatively impacted.
In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. Any such reductions may result in lower revenues and cash flows if additional volumes and/or capacity are unavailable to offset such rate reductions.
HFC and Delek have agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the terms of their respective pipelines and terminals agreements; however, other current or future shippers may still challenge our tariff rates.
Terrorist attacks, (including cyber-attacks), and the threat of terrorist attacks or domestic vandalism, have resulted in increased costs to our business. Continued globalGlobal hostilities or other sustained military campaigns may adversely impact our results of operations.
The long-term impact of (and threat of future) terrorist attacks and the threat of future terrorist attacks,vandalism, on the energy transportation industry in general, and on us in particular, is unknown. Any attack on our facilities, those of our customers and, in some cases, those of other pipelines could have a material adverse effect on our business. Increased security measures taken by us as a precaution against possible terrorist attacks or vandalism have resulted in increased costs to our business. Uncertainty surrounding continued global hostilities or other sustained military campaigns, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror, may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products.
Changes in the insurance markets attributable to terrorist attacks could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt.
The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations or “cyber security” events.organizations. These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets or our operations could be disrupted and/or customer information could be stolen.disrupted. The occurrence of one of these events could cause a substantial decrease in revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation or litigation and or inaccurate information reported from our operations. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.
Adverse changesUncertainty surrounding global hostilities or other sustained military campaigns, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror, may affect our operations in our and/unpredictable ways, including disruptions of crude oil supplies and markets for refined products or our general partner's credit ratings and risk profile may negatively affect us.
Our ability to access capitalinstability in the financial markets is important tothat could restrict our ability to operateraise capital.
In addition, changes in the insurance markets attributable to terrorist attacks, vandalism, or cyberattacks or extortion could make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our business. Regionalexisting insurance coverage. Instability in the financial markets as a result of terrorism, cyberattacks, vandalism or war could also affect our ability to raise capital, including our ability to repay or refinance debt.
We own certain of our systems through joint ventures, and national economic conditions, increased scrutinyour control of such systems is limited by provisions of the energy industryagreements we have entered into with our joint venture partners and regulatory changes,by our percentage ownership in such joint ventures.
Although our subsidiary is the operator of the UNEV pipeline and we own a majority interest in the joint venture that owns the UNEV pipeline, the joint venture agreement for the UNEV pipeline generally requires consent of our joint venture partner(s) for specified extraordinary transactions, such as wellreversing the flow of the pipeline or increasing the fees paid to our subsidiary pursuant to the operating agreement.
In addition, certain of our systems are operated by joint venture entities for which we do not serve as changesthe operator, or in our economic performance, could result in credit agencies reexamining our credit rating.
We are in compliance with all covenants or other requirements set forth in our Credit Agreement. Further,which we do not have any rating downgrade triggersan ownership stake that would automatically acceleratepermits us to control the maturity dates of any debt.
While credit ratings reflect the opinionsbusiness activities of the credit agencies issuingentity. We have limited ability to influence the business decisions of such ratingsjoint venture entities.
Because we have partial ownership in the joint ventures, we may be unable to control the amount of cash we will need for capital projects or will receive from the operation and may not necessarily reflect actual performance, a downgrade incould be required to contribute significant cash to fund our credit ratingshare of their projects and operations, which could adversely affect adversely our ability to borrow on, renew existing,distribute cash to our unitholders.
An impairment of our long-lived assets or obtain access to new financing arrangements, could increase the cost of such financing arrangements,goodwill could reduce our level of capital expenditures and couldearnings or negatively impact our futurefinancial condition and results of operations.
An impairment of our long-lived assets or goodwill could reduce our earnings or negatively impact our results of operations and financial condition. We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset or goodwill may be impaired. If a triggering event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value based on the ability to generate future cash flows. We may also conduct impairment testing based on both the guideline public company and guideline transaction methods. Our long-lived assets and goodwill impairment analyses are sensitive to changes in key assumptions used in our analysis, estimates of future tariff rates, forecasted throughput levels, operating costs and capital expenditures. If the assumptions used in our analysis are not realized, it is possible a material impairment charge may need to be recorded in the future. We cannot accurately predict the amount and timing of any additional impairments of long-lived assets or goodwill in the future.
During the years ended December 31, 2021 and December 31, 2020, we recorded a goodwill impairment charge of $11.0 million and $35.7 million, respectively, related to our Cheyenne reporting unit. A reasonable expectation exists that further deterioration in our operating results or overall economic conditions could result in an impairment of goodwill and/or additional long-lived asset impairments at some point in the future. Future impairment charges could be material to our results of operations.
Growing our business by constructing new pipelines and terminals, or expanding existing ones, subjects us to construction risks.
One of the ways we may grow our business is through the construction of new pipelines and terminals or the expansion of existing ones. The creditconstruction of a new pipeline or the expansion of an existing pipeline, by adding horsepower or pump stations or by adding a second pipeline along an existing pipeline, involves numerous regulatory, environmental, political, and business risk profileslegal uncertainties, most of which are beyond our general partner,control. For example, the Biden Administration has temporarily suspended the grant of certain authorizations for oil and gas activities on federal lands, although this does not affect existing authorizations. Pipeline construction projects requiring federal approvals are generally subject to environmental review requirements under the National Environmental Policy Act, and must also comply with other natural resource review requirements imposed pursuant to the Endangered Species Act and the National Historic Preservation Act. For over 35 years, the Corps has authorized construction, maintenance, and repair of HFC aspipelines under a streamlined Nationwide Permit (“NWP”) program; however, in April 2020, the indirect ownerU.S. District Court for the District of our general partner,Montana determined that NWP 12 failed to comply with consultation requirements under the federal Endangered Species Act, vacated NWP 12, and enjoined the issuance of new authorizations for oil and gas pipeline projects under NWP 12. While the district court’s order has subsequently been limited pending appeal, we cannot predict the ultimate outcome of this case. Additionally, in response to the vacatur, the Corps has announced a reissuance of the NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, the rulemaking may be factors in credit evaluationssubject to litigation or to further revision under the Biden Administration. While the full extent and impact of us as a master limited partnership due to the vacatur is unclear at this time, we could face significant influence of our general partnerdelays and its indirect owner over our business activities, including our cash distribution acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flowcosts if we must obtain individual permit coverage from the partnershipCorps for our projects. These projects may not be completed on schedule (or at all) or at the budgeted cost. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project.
Moreover, we may construct facilities to service their indebtedness.capture anticipated future growth in demand for refined products in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our earnings, results of operations and financial condition.
RISKS RELATED TO OUR ACQUISITION STRATEGY AND RECENT/PENDING ACQUISITIONS
We may be unsuccessful in integrating the operations of the assets we have acquired or may acquire with our operations, and in realizing all or any part of the anticipated benefits of any such acquisitions.
From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. Our capitalization and results of operations may change significantly as a result of completed or future acquisitions. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them, and new geographic areas and the diversion of management's attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Also, following an acquisition, we may discover previously unknown liabilities associated with the acquired business or assets for which we have no recourse under applicable indemnification provisions.
We own certain ofThe pending Sinclair Transactions may not be consummated on a timely basis or at all. Failure to complete the acquisition within the expected timeframe or at all could adversely affect our systems through joint ventures,common unit price and our controlfuture business and financial results.
On August 2, 2021, we entered into the Contribution Agreement with Sinclair and certain other parties thereto to acquire all of the issued and outstanding capital stock of STC. We expect the Sinclair Transactions to close in 2022. The Sinclair Transactions are subject to closing conditions. If these conditions are not satisfied or waived, the Sinclair Transactions will not be consummated. If the closing of the Sinclair Transactions is substantially delayed or does not occur at all, or if the terms of the acquisition are required to be modified substantially, we may not realize the anticipated benefits of the acquisition fully or at all, or they may take longer to realize than expected. The closing conditions include, among others, the absence of a law or order
prohibiting the transactions contemplated by the Business Combination Agreement and the termination or expiration of any waiting periods under the Hart-Scott Rodino Act, as amended (the “HSR Act”), with respect to the Sinclair Transactions. On August 23, 2021, each of HFC and Sinclair filed its respective premerger notification and report regarding the Sinclair Transactions with the U.S. Department of Justice and the U.S. Federal Trade Commission (the “FTC”) under the HSR Act. On September 22, 2021, HFC and Sinclair each received a request for additional information and documentary material (“Second Request”) from the FTC in connection with the FTC’s review of the Sinclair Transactions. Issuance of the Second Request extends the waiting period under the HSR Act until 30 days after both HFC and Sinclair have substantially complied with the Second Request, unless the waiting period is terminated earlier by the FTC or the parties otherwise commit not to close the Sinclair Transactions for some additional period of time. HFC and Sinclair are cooperating with the FTC staff in its review and are working diligently to satisfy the closing conditions as soon as possible. We have incurred and will continue to incur substantial transaction costs whether or not the Sinclair Transactions are completed. Any failure to complete the Sinclair Transactions could have a material adverse effect on our common unit price, our competitiveness and reputation in the marketplace, and our future business and financial results, including our ability to execute on our strategy to return capital to our unitholders.
In order to complete the Sinclair Transactions, HFC and Sinclair must obtain certain governmental approvals, and if such approvals are not granted or are granted with conditions that become applicable to the parties, completion of the transactions may be jeopardized or prevented or the anticipated benefits of the transactions could be reduced.
Completion of the Sinclair Transactions is conditioned upon the expiration or termination of the waiting period relating to the Sinclair Transactions under the HSR Act. Although HFC, HEP and Sinclair have agreed in the Business Combination Agreement and Contribution Agreement to use their reasonable best efforts, subject to certain limitations, to make the necessary filings under the HSR Act and obtain the required governmental approvals, there can be no assurance that the relevant waiting period will expire or terminate and no assurance that the Sinclair Transactions will be completed. In addition, the FTC has broad discretion in administering the governing laws and regulations, and may take into account various facts and circumstances in their consideration of the Sinclair Transactions, including other potential transactions in the oil and gas industry or other industries. The FTC may be affected by government shutdowns, which could result in delays regarding any potential approvals or other actions. The FTC may initiate proceedings seeking to prevent, or otherwise seek to prevent, the Sinclair Transactions. As a condition to the approval of the Sinclair Transactions, the FTC may also impose requirements, limitations or costs, require divestitures or place restrictions on the conduct of the parties’ business after completion of the Sinclair Transactions. Under the terms of the Business Combination Agreement and Contribution Agreement, HFC and HEP are obligated to use reasonable best efforts to complete the transactions, but are not required to take any actions or agree to any terms or conditions in connection with obtaining any regulatory approvals for completing the Sinclair Transactions beyond those specifically described in the Business Combination Agreement and Contribution Agreement.
In the Contribution Agreement, HEP and Sinclair agreed that the consideration to be paid by HEP to Sinclair in connection with the HEP Transaction would be adjusted downward if, as a condition to obtaining antitrust clearance for the Sinclair Transactions, the FTC requires HEP to divest a portion of its equity interest in UNEV and the sales price for such interests does not exceed the threshold provided in the Contribution Agreement. In the Business Combination Agreement, HFC and Sinclair agreed that the stock consideration to be issued to Sinclair would be reduced if, as a condition to obtaining antitrust clearance for the Sinclair Transactions, the FTC requires HFC to divest its refinery in Davis County, Utah (the “Woods Cross Refinery”) and certain related assets and the sales price for such assets does not exceed a threshold provided in the Business Combination Agreement. In addition, HEP and HFC entered into a Letter Agreement (“Letter Agreement”), which provides that if, as a condition to obtaining antitrust clearance for the Sinclair Transactions, HFC enters into a definitive agreement to divest the Woods Cross Refinery, then HEP would sell certain assets located at, or relating to, the Woods Cross Refinery to HFC in exchange for cash consideration equal to $232.5 million plus the certain accounts receivable of HEP in respect of such systems is limitedassets, with such sale to be effective immediately prior to the closing of the sale of the Woods Cross Refinery by HFC. The Letter Agreement also provides that HEP’s right to future revenues from HFC in respect of such Woods Cross Refinery assets will terminate at the closing of such sale. If as a condition to the approval of the Sinclair Transactions the FTC requires HFC and HEP to divest the assets specified in the Business Combination Agreement, Contribution Agreement and Letter Agreement, the cash flows relating to the divested assets would also be lost, the anticipated benefits of the Sinclair Transactions would be reduced and the combined company’s financial position, results of operations and cash flows may be materially and adversely affected.
However, notwithstanding the provisions of the agreements we have entered into with our joint venture partnersBusiness Combination Agreement and by our percentage ownership in such joint ventures.
Although our subsidiary is the operator of the UNEV pipeline and we own a majority interestContribution Agreement, HFC, HEP or Sinclair could agree to become subject to terms or conditions beyond those required in the joint venture that ownsBusiness Combination Agreement and Contribution Agreement in connection with the UNEV pipeline, the joint venture agreement for the UNEV pipeline generally requires consent of our joint venture partner(s) for specified extraordinary transactions, such as reversing the flow of the pipelineexpiration or increasing the fees paid to our subsidiary pursuant to the operating agreement.
In addition, certain of our systems are operated by joint venture entities that we do not operate, or in which we do not have an ownership stake that permits us to control the business activities of the entity. We have limited ability to influence the business decisionstermination of such joint venture entities.
Because we have partial ownership inwaiting period, the joint ventures, we may be unable to control the amountimposition of cash we will receive from the operation and could be required to contribute significant cash to fund our share of their operations, which could adversely affect ourHFC’s and HEP’s ability to distributeintegrate Sinclair’s operations with their operations, reduce the anticipated benefits of the transactions or otherwise materially and adversely affect the combined company’s financial position, results of operations and cash flows after completion of the transactions.
The actual value of the consideration we will pay to Sinclair at closing may exceed the value allocated to such consideration at the time we entered into the Contribution Agreement.
Under the Contribution Agreement, at closing, we will pay Sinclair a cash payment of $325 million and issue Sinclair 21 million common units, which represents a transaction value of approximately $758 million based on the closing price of our common units as of July 30, 2021. Neither we nor the Sinclair stockholders are permitted to “walk away” from the transaction solely because of changes in the market price of our common units between the signing of the Contribution Agreement and the closing. Our common units have historically experienced volatility. Common unit price changes may result from a variety of factors that are beyond our control, including changes in our business, operations and prospects, regulatory considerations and general market and economic conditions. The closing price of our common units on the New York Stock Exchange on July 30, 2021, was $20.60; and on February 18, 2022, the closing price of our common units was $17.69. The value of the common units we issue in connection with the closing of the Sinclair Transactions may be significantly higher at the closing than when we entered into the Contribution Agreement.
We will issue a large number of common units in connection with the Sinclair Transactions, which will result in dilution to our existing unitholders and may cause the market price of our common units to decline in the future as the result of sales of our common units owned by Sinclair stockholders or current HEP unitholders. Our unitholders may not realize a benefit from the Sinclair Transactions commensurate with the ownership dilution they will experience.
At the closing of the Sinclair Transactions, we will issue 21 million common units to Sinclair. Our issuance of such common units will result in dilution of our existing unitholders’ ownership interests and may also have an adverse impact on our net income per unit in fiscal periods that include (or follow) the closing. The Unitholders Agreement (the “Unitholders Agreement”) between HEP, its ultimate general partner, certain other parties, and the stockholders of Sinclair (the “Sinclair Parties”) also subjects 15.75 million of the HEP common units issued to the Sinclair Parties (the “Restricted Units”) to a “lock-up” period commencing on the closing date, during which the Sinclair Parties will be prohibited from selling the Restricted Units, except for certain permitted transfers. One-third of such Restricted Units will be released from such restrictions on the date that is six months after the closing date, one-third of the Restricted Units will be released from such restrictions on the first anniversary of the closing date, and the remainder will be released from such restrictions on the date that is 15 months from the closing date. In addition, the Unitholders Agreement contains customary registration rights, requiring us to file, within five business days following the closing date, a shelf registration statement on Form S-3 under the Securities Act, to permit the public resale of all the registrable securities held by the Sinclair Parties once such securities are no longer subject to a lock-up.
Following their receipt of common units as consideration in the HEP Transaction, subject to release from the associated lock-up provisions and the filing of a resale registration statement or satisfaction of the requirements of Rule 144, the Sinclair Parties may seek to sell the common units delivered to them. Other HEP unitholders may also seek to sell our common units held by them following, or in anticipation of, completion of the HEP Transaction. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of common units, may affect the market for, and the market price of, our common units in an adverse manner.
If we are unable to completerealize the strategic and financial benefits currently anticipated from the Sinclair Transactions, our unitholders will have experienced dilution of their ownership interest without receiving commensurate benefit, and we may be unable to execute on our strategy to return capital projects at their expectedto our unitholders that was described in our press release and investor presentation announcing the Sinclair Transactions.
Litigation relating to the Sinclair Transactions could result in substantial costs to HEP or an injunction preventing the completion of the Sinclair Transactions.
Securities class action lawsuits, derivative and related lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert the time and resources of management. An adverse judgment could result in monetary damages, which could have a negative impact on HEP’s liquidity and financial condition.
Lawsuits that may be brought against us and/or our directors, or have been or may be brought against HFC and/or HFC’s directors, could also seek, among other things, injunctive relief or other equitable relief, including a request to rescind parts of the acquisition agreement already implemented, issue additional disclosures and to otherwise enjoin the parties from consummating the Sinclair Transactions. HFC and the members of HFC’s board of directors were named as defendants in a timely manner,lawsuit filed in Harris County, Texas, brought by an alleged HFC shareholder challenging the Sinclair Transactions and seeking, among other things, injunctive relief to enjoin and/or rescind the acquisition agreement and require the defendants to amend the related proxy statement, declare a breach of fiduciary duties, provide correct and complete disclosures (or enjoin or unwind the acquisition and share issuance if we incur increased maintenance they do not), rescissory and compensatory damages, and interest, attorney’s fees and other costs. Seven additional lawsuits were filed in federal courts on behalf of individual alleged HFC shareholders: Gerald Lovoi v. HollyFrontier Corp., et al., Case No. 1:21-cv-08805 (S.D.N.Y.); Jared Abrams v. HollyFrontier Corp., et al., Case No. 1:21-cv-09309 (S.D.N.Y.); Christopher Quayle v. HollyFrontier Corp., et al., Case No. 1:21-cv-03079 (D. Colo.); Shannon
Jenkins v. HollyFrontier Corp., et al., Case No. 1:21-cv-09497 (S.D.N.Y.); William Bancroft v. HollyFrontier Corp., et al., Case No. 1:21-cv-09878 (S.D.N.Y.); Stanley Jacobs v. HollyFrontier Corp., et al., Case No. 1:21-cv-01668 (D. Del.); and Timothy Dolan v. HollyFrontier Corp., et al., Case No. 1:21-cv-01670 (D. Del.). All asserted claims under Section 14(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) and SEC Rule 14a-9 and claims under Section 20(a) of the Exchange Act against HFC and the members of HFC’s board of directors, and seek, among other things, to enjoin and/or repairrescind the acquisition agreement and require defendants to amend the related proxy statement, and, if they do not, to recover damages. Additional lawsuits in connection with the Sinclair acquisition may be filed in the future in federal or state courts.
HFC believes that the lawsuits described above are without merit, and that no further disclosure was required under applicable law. However, HFC made supplemental disclosures on November 30, 2021 to reduce the risk that the lawsuits may delay or otherwise adversely affect the consummation of the Acquisition and to minimize the expense of defending such action. HFC entered into a Settlement Agreement with the plaintiff in the lawsuit filed in Harris County, Texas and the lawsuit was voluntarily dismissed with prejudice. Since the HFC shareholder vote on December 8, 2021, five of the lawsuits filed in federal courts have also been voluntarily dismissed: Bancroft v. HollyFrontier Corp. was voluntarily dismissed on December 13, 2021; Quayle v. HollyFrontier Corp. was voluntarily dismissed on December 21, 2021; Lovoi v. HollyFrontier Corp. was voluntarily dismissed on January 7, 2022; Abrams v. HollyFrontier Corp. was voluntarily dismissed on January 7, 2022; and Jenkins v. HollyFrontier Corp. was voluntarily dismissed on January 25, 2022. With respect to the two outstanding lawsuits, HFC’s additional disclosures moot the claims therein.
The outcome of the remaining lawsuits or any other lawsuit that may be filed challenging the Sinclair Transactions is uncertain. One of the conditions to the closing of the Sinclair Transactions is that no injunction by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case, that prohibits or makes illegal the closing of the Sinclair Transactions. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Sinclair Transactions that injunction may delay or prevent the Sinclair Transactions from being completed within the expected timeframe or at all, which could result in substantial costs on assets,to us and may adversely affect our business, financial position, results of operations and cash flows. Relatedly, the defense or ifsettlement of any lawsuit or claim that remains unresolved at the market conditions assumed intime the Sinclair Transactions are completed may adversely affect our project economics deteriorate, ourbusiness, financial condition, results of operations orand cash flows couldand result in substantial costs to us.
The HEP Transaction will require management to devote significant attention and resources to integrating the Sinclair business with our business.
The HEP Transaction will require management to devote significant attention and resources to integrating the Sinclair business with our business. Potential difficulties that may be materiallyencountered in the integration process include, among others:
•the inability to successfully integrate the Sinclair business into the HEP business in a manner that permits us to achieve the revenue and adversely affected.cost savings that we announced as anticipated from the acquisition;
•complexities associated with managing the larger, integrated business;
•potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the acquisition;
•integrating personnel from the two companies while maintaining focus on providing consistent, high-quality products and services;
•loss of key employees;
•integrating relationships with customers, vendors and business partners;
•performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the acquisition and integrating Sinclair’s operations into HEP; and
•the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies.
Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and increased maintenance or repair expenditures on our existing facilities)difficulties in the integration process could adversely affect our abilitybusiness, financial results, financial condition and common unit price. Even if we are able to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficultiesintegrate our business operations successfully, there can be no assurance that may arise, such delays or cost increases may arise as athis integration will result of numerous factors, such as:
denial or delay in issuing requisite regulatory approvals and/or permits;
unplanned increases in the realization of the full benefits of synergies, cost of construction materialssavings, innovation and operational efficiencies that we currently expect or labor;have communicated from this integration or that these benefits will be achieved within the anticipated time frame.
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions explosions, fires or spills) affectingRISKS RELATED TO GOVERNMENT REGULATION
Our operations are subject to evolving federal, state and local laws, regulations and permit/authorization requirements regarding our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
market-related increases in a project's debt or equity financing costs; and/or
nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.
If we are unable to completebusiness, capital projects at their expected costs or in a timely manner our financial condition, results of operations, or cash flowsand environmental protection, health, operational safety and product quality. Potential liabilities arising from these laws, regulations and requirements could be materially and adversely affected.
We do not own all of the land on which our pipeline systems and other assets are located, which could result in disruptions to our operations. Additionally, a change in the regulations related to a state’s use of eminent domain could inhibit our ability to secure rights-of-way for future pipeline construction projects. Finally, certain of our assets are located on tribal lands.
We do not own all of the land on which our pipeline systems and other assets are located, and we are, therefore, subject to the risk of increased costs or more burdensome terms to maintain necessary land use. We obtain the right to construct and operate pipelines and other assets on land owned by third parties and government agencies for specified periods. If we were to lose these rights through an inability to renew leases, right-of-way contracts or similar agreements, we may be required to relocate our pipelines or other assets and our business could be adversely affected. Additionally, it may become more expensive for us to obtain new rights-of-way or leases or to renew existing rights-of-way or leases. If the cost of obtaining or renewing such agreements increases, it may adversely affect our operations and the cash flows available for distributionhave a material adverse effect on our business.
Our pipelines and terminal, tankage and loading rack operations are subject to unitholders.
The adoption or amendment of laws and regulations that limit or eliminate a state’s ability to exercise eminent domain over private property in a state in which we operate could make it more difficult or costly for us to secure rights-of-way for future pipeline construction and other projects.
Certain of our pipelines are located on Native American tribal lands. Various federal agencies, along with each Native American tribe, promulgate and enforce regulations, including environmental standards, regarding operations on Native American tribal lands. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations (including various taxes, fees, and other requirements and conditions) and to grant approvals independent fromincreasingly stringent federal, state, and local statuteslaws, regulations and oversight regarding, among other things, the generation, storage, handling, use, transportation and distribution of petroleum and hazardous substances by pipeline, truck, rail, ship and barge, the emission and discharge of
materials into the environment, waste management, and characteristics and composition of gasoline and diesel fuels, and other matters otherwise relating to the protection of human health and the environment.
Environmental laws and regulations. Following a recent decision issued in May 2017 byregulations have raised operating costs for the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Native American landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operations. These factors may increase our cost of doing business on Native American tribal lands.
In addition, our industry is subject to potentially disruptive activities by those concerned with the possible environmental impacts of pipeline routes. Activists, non-governmental organizations and others may seek to restrict the transportation of crude oil and refined products by exerting social industry, and compliance with such laws and regulations may cause us, the HFC refineries, and other refineries that we support to incur potentially material expenditures associated with the construction, maintenance, and upgrading of equipment and facilities. Future environmental, health and safety requirements (or changed interpretations of existing requirements), may impose new and/or political pressuremore stringent requirements on our assets and operations and require us to influence when,incur potentially material expenditures to comply. Failure to comply with any applicable laws, regulations, and whether, such rights-of-way orrequirements of regulatory authorities could subject us to substantial penalties and fines.
Our operations require numerous authorizations and permits under various laws and regulations, including environmental and worker health and safety laws and regulations. These authorizations and permits are granted. This interferencesubject to revocation, renewal, modification, or third-party challenge, and can require operational changes that may involve significant costs to limit impacts or potential impacts on the environment and/or worker health and safety. For example, in May 2015, the EPA published a greatly expanded definition of “waters of the United States” (“WOTUS”) under the federal Clean Water Act (“CWA”) and the jurisdiction of the Corps. Many courts blocked this rule from going into effect, and the EPA and Corps rescinded the WOTUS rule in September 2019. On January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which narrowed the definition of WOTUS relative to the prior 2015 rulemaking and became effective on June 22, 2020, but some courts have blocked this rule as well. The EPA and the Corps are no longer implementing the Navigable Waters Protection Rule and are instead enforcing the WOTUS definition as it was promulgated in 1986. The government is also proposing a rule that would formally rescind the Navigable Waters Protection Rule and, again, greatly expand the definition of WOTUS. Any increase in scope could impact future pipeline development, whichresult in increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. A violation of authorization or permit conditions or other legal or regulatory requirements could interfere withresult in substantial fines, criminal sanctions, permit revocations and injunctions prohibiting our operations. In addition, major modifications of our operations could require modifications to our existing permits or block expansion or development projects andexpensive upgrades to our existing pollution control equipment that could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may also be required to address conditions that require environmental response actions or remediation. The transportation and storage of refined products produces a risk that refined products and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury or property damages to private parties and significant business interruption. Further, we own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties have also been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control. Environmental laws can impose strict, joint and several liability for releases of oil and hazardous substances into the environment, and we could be held liable for past releases caused by third parties. If we were to incur a significant liability pursuant to environmental laws or regulations, it could have a material adverse effect on us.
Our operations are also subject to various laws and regulations relating to occupational health and safety. We maintain safety, training and maintenance programs as part of our ongoing efforts to comply with applicable laws and regulations but cannot guarantee that these efforts will always be successful. Compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. Failure to appropriately manage occupational health and safety risks associated with our business could also adversely impact our employees, communities, reputation and results of operations.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
We are regulated under federal pipeline safety statutes by DOT through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”). PHMSA sets and enforces pipeline safety regulations. Failure to comply with PHMSA or comparable state pipeline safety regulations could result in a number of consequences which may have a materially adverse effect on our operations. PHMSA’s enforcement authority includes the ability to assess civil penalties for violations of pipeline safety regulations, issue orders directing compliance, and issue orders directing corrective action to abate hazardous conditions. Among other things, pipeline safety laws and regulations require pipeline operators to develop integrity management programs, including more frequent inspections and other measures for pipelines located in “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including certain population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to perform a variety of heightened assessment, analysis, prevention and repair activities. Routine assessments under the integrity management program may result in findings that require repairs or other actions.
Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA or states that result in more stringent or costly pipeline integrity management or safety standards could possibly have a substantial effect on us and similarly situated
midstream operators. In December 2020, Congress passed the PIPES Act, some elements of which could affect our operations. The Safety of Hazardous Liquid Pipelines final rule (effective July 1, 2020) expands PHMSA’s regulation of the safety of hazardous liquid pipelines by extending reporting requirements to certain hazardous liquid gravity pipelines and rural gathering pipelines, establishing additional integrity management requirements for hazardous liquid pipelines that could affect high consequence areas, adding new assessment and integrity requirements for certain other hazardous liquid pipelines, and expanding various inspection and leak detection requirements. These final rules are expected to result in additional operations and maintenance costs in the coming years.
Rate regulation, changes to rate-making rules, or a successful challenge to the rates we charge on our pipeline systems may reduce our revenues and the amount of cash we generate.
Some of our pipelines are considered interstate common carrier pipelines subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act (“ICA”). The ICA requires that the rates charged for transportation on oil pipelines, a category that includes crude oil and petroleum product pipelines, be “just and reasonable” and not unduly discriminatory. The FERC regulations implementing the ICA further require the rates and rules for transportation service on our oil pipelines be filed with the FERC. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such proposed rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.
Oil pipeline carriers may change their rates in accordance with a FERC-approved indexing methodology, which allows oil pipeline carriers to charge rates up to a prescribed ceiling level that changes annually based on the year-to-year change in the U.S. Producer Price Index for Finished Goods (“PPI”). Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. Oil pipeline carriers, as a general rule, utilize this indexing methodology to change their rates.
On December 17, 2020, the FERC established a new price index for the five-year period commencing July 1, 2021 and ending June 30, 2026, in which common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by the PPI plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order. On January 20, 2022, the FERC issued an order granting rehearing requests and reduced the index to PPI minus 0.21%. As a result, the FERC directed oil pipeline carriers to, by March 1, 2022, reduce rates not subject to agreement between such pipeline and a shipper that would be above the new indexed rate ceiling. Such reduced rates will be in effect from March 1, 2022 until July 1, 2022. Prior to June 1, 2022, the FERC will issue a revised index, which could be positive or negative. Rates reflecting this revised index will become effective on July 1, 2022.
Cost-of-service ratemaking, market-based rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates. However, these methodologies could limit an oil pipeline carrier’s ability to set rates based on actual costs or may delay implementation of any proposed increase in rates. Adverse decisions by the FERC in approving our oil pipelines’ rates could adversely affect our financial position, results of operations and cash flows.
In addition to maintaining rules and rates on file at FERC for interstate movements, we are also required to maintain rates on file with certain state regulatory authorities for intrastate movements on our petroleum products and crude oil pipelines. Tariff rates for some of our intrastate pipeline services may be subject to challenge by complaint by interested parties or by the independent action of the state regulatory authorities who have jurisdiction over our intrastate pipelines rates.
The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what we are permitted by the FERC or state regulatory authorities to recover in our rates, or to the extent that there is a lag before we can file for and obtain rate increases, such events can have a negative impact on our operating results. In addition, the FERC, state regulatory authorities, or our customers could initiate proceedings or file complaints challenging the tariff rates charged by our pipelines, which could have an adverse impact on us. HFC and other third party shippers have agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the terms of their respective pipelines and terminals agreements; however, other current or future shippers may still challenge our tariff rates. Finally, FERC and state regulatory authorities periodically implement new rules, regulations, and policies that may adversely affect our terms and conditions of service as well as the rates charged for our services or our costs of operation. Failure to comply with the FERC’s regulations and applicable governing statutes could result in civil penalty liability of up to approximately $14,536 per violation per day.
There are various risks associated with greenhouse gases, climate change legislation or regulations, and increasing societal expectations that companies address climate change that could result in increased operating costs, reduced demand for our services and reduced access to capital markets.
Climate change continues to attract considerable attention in the United States. Numerous proposals have been made and could continue to be made at the national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases (“GHGs”) as well as to limit or eliminate future emissions. In 2021, President Biden issued several executive orders that committed to substantial action on climate change and called for, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors. As a result, our operations, and those of our customers, are subject to a series of regulatory, political, litigation, and financial risks associated with the transport of fossil fuels and emission of GHGs.
The EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas sources in the United States or require control or reduction of emissions of GHGs, including methane, from such sources. In 2021, the EPA announced its intent to reconsider and revise these rules to further reduce GHG emissions and issued a proposed rule that would extend to existing petroleum and natural gas sources. In addition, the EPA, together with the DOT, implemented GHG emission and corporate average fuel economy standards for vehicles manufactured in the United States, which were revised in December 2021 to impose more stringent requirements for emissions reductions. These and other federal efforts to reduce GHG emissions from the transportation sector could increase our operating costs or reduce demand for our customers’ products.
Internationally, the United Nations-sponsored Paris Agreement requires member nations to submit non-binding, individually determined emissions reduction goals every five years after 2020. In 2021, the United States rejoined the Paris Agreement and issued its corresponding “nationally determined contribution” (“NDC”) to reduce economy-wide net GHG emissions 50-52% below 2005 levels by 2030. While the NDC does not identify specific actions necessary to achieve these reductions, it lists several sectors as pathways for reductions, including the power, transportation, building, industrial, and agricultural sectors. The administration has acknowledged that a combination of regulatory actions and legislation will be necessary to achieve the U.S. NDC. In regards to legislation, in November 2021 the United States enacted a nearly $1 trillion bipartisan infrastructure law, which provided significant funding for electric vehicles and clean energy technologies. A separate climate spending bill known as the Build Back Better Act, which could impose a fee on methane emissions, among other GHG provisions, remains under consideration in the U.S. Congress. Ultimately, the impacts of these orders, and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement remain unclear at this time.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates and combustion engine phaseouts. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the crude oil and refined products that we deliver.
Increasing societal expectations that companies address climate change and use of substitutes for energy commodities may result in increased costs, reduced demand for our customers’ products and our services, reduced profits, increased investigations and litigation, and negative impacts on our unit price and access to capital markets. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed on us without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
Furthermore, large institutional lenders have begun to announce their own policies to meet publicly announced climate commitments, which often involve commitments to shift lending activities in the energy sector to meet particular GHG emissions goals. As a result, certain institutional lenders may decide not to provide funding to us based on environmental concerns, which could adversely affect our financial condition and access to capital for potential growth projects. These impacts could be intensified if United States’ financial regulators were to promulgate climate change requirements in the future.
RISKS RELATED TO CYBERSECURITY, DATA SECURITY, AND INFORMATION TECHNOLOGY
We may be subject to information technology system failures, communications network disruptions and data breaches.
We depend on the efficient and uninterrupted operation of hardware and software systems and infrastructure, including our operating, communications and financial reporting systems. These systems are critical in meeting customer expectations, effectively tracking, maintaining and operating our equipment, directing and compensating our employees, and interfacing with our financial reporting system. We have implemented safeguards and other preventative measures to protect our systems and
data, including sophisticated network security and internal control measures; however, our information technology systems and communications network, and those of our information technology and communication service providers, remain vulnerable to interruption by natural disasters, power loss, telecommunications failure, terrorist attacks, vandalism, Internet failures, computer malware, ransomware, cyberattacks, data breaches and other events unforeseen or generally beyond our control. Additionally, the implementation of social distancing measures and other limitations on our employees, service providers and other third parties in response to the COVID-19 pandemic have necessitated in certain cases to switching to remote work arrangements on less secure systems and environments. The increase in companies and individuals working remotely has increased the risk of cyberattacks and potential cybersecurity incidents, both deliberate attacks and unintentional events.
In addition, information technology system failures, network disruptions (whether intentional by a third party or due to natural disaster), breaches of network or data security, or disruption or failure of the network system used to monitor and control pipeline and terminal operations could disrupt our operations by impeding our processing of transactions, our ability to protect customer or company information and our financial reporting. Although we have taken steps to address these concerns by implementing sophisticated network security and internal control measures, a system failure or data security breach could have a material adverse effect on our financial condition, results of operations or cash flows.
Cyberattacks or security breaches could have a material adverse effect on our business, financial condition, results of operations or cash flows.
Our business is dependent upon information technology systems and other digital technologies for controlling our plants and pipelines, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. We monitor our information technology systems on a 24/7 basis in an effort to detect cyberattacks, security breaches or unauthorized access. Preventative and detective measures we utilize include independent cybersecurity audits and penetration tests. We implemented these efforts along with other risk mitigation procedures to detect and address unauthorized and damaging activity on our network, stay abreast of the increasing cybersecurity threat landscape and improve our cybersecurity posture. While there have been immaterial incidents of unauthorized access to our information technology systems, we have not experienced any impact on our business or operations from these attacks. In addition, information technology system failures, communications network disruptions (whether intentional by a third party or due to natural disaster), and security breaches could still impact equipment and software used to control plants and pipelines, resulting in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store or distribute, or releases of hydrocarbon products and other damage to our facilities for which we could be held liable.
Despite our security measures, our information technology systems may become the target of cyberattacks or security breaches (including employee error, malfeasance or other breaches), which could result in the theft or loss of the stored information, misappropriation of assets, disruption of transactions and reporting functions, our ability to protect confidential information and our financial reporting. Moreover, we may not be able to anticipate, detect or prevent cyberattacks or security breaches, particularly because the methodologies used by attackers change frequently or may not be recognized until such attack is launched, and because attackers are increasingly using technologies specifically designed to circumvent cybersecurity measures and avoid detection. Even with insurance coverage for cyberattacks, data breaches or unauthorized access of our information technology systems, a claim could be denied or coverage delayed. In addition, as technologies evolve, and cyberattacks become increasingly sophisticated, we may incur significant costs to modify, upgrade or enhance our security measures to protect against such cyberattacks and we may face difficulties in fully anticipating or implementing adequate security measures or mitigating potential harm. A cyberattack or security breach could result in liability under data privacy laws, regulatory penalties, damage to our reputation, or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition, results of operations or cash flows.
Our business is subject to complex and evolving laws, regulations and security standards regarding privacy, cybersecurity and data protection (“data protection laws”).Many of these data protection laws are subject to change and uncertain interpretation, and could result in claims, changes to our business practices, monetary penalties, increased cost of operations or other harm to our business.
The constantly evolving regulatory and legislative environment surrounding data privacy and protection poses increasingly complex compliance challenges, and complying with such data protection laws could increase the costs and complexity of compliance. While we do not collect significant amounts of personal information from consumers, we do have personal information from our employees, job applicants and some business partners, such as contractors and distributors. Any failure, whether real or perceived, by us to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments, and negative publicity, require us to change our business practices, increase the costs and complexity of compliance, and adversely affect our business. Our compliance with emerging privacy/security laws, as well as any associated inquiries or investigations or any other government actions related to these laws, may increase our operating costs.
In the second quarter of 2021, the Department of Homeland Security’s Transportation Security Administration (“TSA”) announced two new security directives. These directives require critical pipeline owners to comply with mandatory reporting measures, including, among other things, to appoint personnel, report confirmed and potential cybersecurity incidents to the DHS Cybersecurity and Infrastructure Security Agency (“CISA”) and provide vulnerability assessments. As legislation continues to develop and cyber incidents continue to evolve, we may be required to expend significant additional resources to respond to cyberattacks, to continue to modify or enhance our protective measures, or to detect, assess, investigate and remediate any critical infrastructure security vulnerabilities and report any cyber incidents to the applicable regulatory authorities. Any failure to remain in compliance with these government regulations may results in enforcement actions which may have a material adverse effect on our business and operations.
RISKS RELATED TO LIQUIDITY, FINANCIAL INSTRUMENTS AND CREDIT
We may not be able to retain existing customers or acquire new customers.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors outside our control, including competition from other pipelines and the demand for refined products in the markets that we serve. Our long-term pipeline and terminal, tankage and refinery processing unit throughput agreements with HFC and a third party customer will expire beginning in 2022 through 2036. On September 30, 2019, Delek exercised its first renewal option (the “Renewal”) under this agreement for an additional five-year period beginning April 1, 2020, but only with respect to specific assets. For the refined product pipelines and refined product terminals that were not subject to the Renewal and which accounted for approximately $15 million to $16 million of our annual revenues from Delek as of December 31, 2019, the agreement terminated as of March 31, 2020. We reached a short-term agreement with Delek on a majority of the pipeline and terminal assets that were not part of the Renewal. We continue to explore avenues that will maximize value of the non-Renewal assets.
Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.
As of December 31, 2021, the principal amount of our total outstanding debt was $1,340 million. On February 4, 2020, we closed a private placement of $500 million 5.0% senior notes due 2028 (the “5% Senior Notes”). Various limitations in our Credit Agreement and the indenture for our 5% Senior Notes may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.
Our leverage could have important consequences. We require substantial cash flow to meet our payment obligations with respect to our indebtedness. Our ability to make scheduled payments, to refinance our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to then-current economic conditions and to financial, business, competitive, regulatory and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit Agreement to service our indebtedness. However, a significant downturn in our business or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. We cannot guarantee that we would be able to refinance our existing indebtedness at maturity or otherwise or sell assets on terms that are commercially reasonable.
The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions. The agreements governing our debt generally require us to comply with various affirmative and negative covenants including the maintenance of certain financial ratios and restrictions on incurring additional debt, entering into mergers, consolidations and sales of assets, making investments and granting liens. Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisitions, construction or development activities, or to otherwise realize fully the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage also may make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.
We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.
The domestic and global financial markets and economic conditions are disrupted and volatile from time to time due to a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, including U.S. government shutdowns, weak economic conditions and uncertainty in the financial services sector. In addition, the fixed-income markets have experienced periods of extreme volatility, which negatively impacted market liquidity conditions. As a
result, the cost of raising money in the debt and equity capital markets has increased substantially at times while the availability of funds from these markets diminished significantly. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations.
Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to:
•continue our business as currently structured and/or conducted;
•meet our obligations as they come due;
•execute our growth strategy;
•complete future acquisitions or construction projects;
•take advantage of other business opportunities; or
•respond to competitive pressures.
Any of the above could have a material adverse effect on our revenues and results of operations.
Increases in interest rates could adversely affect our business.
We use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our credit facility. In addition, interest rates on future debt offerings could be higher, causing our financing costs to increase accordingly. Our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates.
The expected phase out of LIBOR could impact the interest rates paid on our variable rate indebtedness and could cause our interest expense to increase.
A portion of our borrowing capacity and outstanding indebtedness bears interest at a variable rate based on the London Interbank Offered Rate (“LIBOR”). The ICE Benchmark Administration Limited (“IBA”) announced that it will cease calculating and publishing all USD LIBOR tenors on June 30, 2023 and cease calculating and publishing certain USD LIBOR tenors on December 31, 2021. Further, U.K. and U.S. regulatory authorities recently issued statements encouraging banks to cease entering into new USD LIBOR based loans by no later than December 31, 2021 and to continue to transition away from USD LIBOR based loans in preparation of IBA ceasing to calculate and publish LIBOR based rates on June 30, 2023. These developments may cause fluctuations in LIBOR rates and pricing of USD LIBOR based loans that are not transitioned to a new benchmark rate.
The agreements that govern our variable rate indebtedness contain customary transition and fallback provisions in contemplation of the cessation of LIBOR. Nevertheless, at this time, it is not possible to predict the effect that these developments, any discontinuance, modification or other reforms to LIBOR or any other reference rate, or the establishment of alternative reference rates may have on LIBOR, other benchmarks or variable rate indebtedness. Uncertainty as to the nature of such potential discontinuance, modification, alternative reference rates or other reforms may materially adversely affect the trading market for securities linked to such benchmarks. Furthermore, the use of alternative reference rates or other reforms could cause the market value of, the applicable interest rate on and the amount of interest paid on our variable rate indebtedness to be materially different than expected and could cause our interest expense to increase.
If we are unable to generate sufficient cash flow, our ability to pay quarterly distributions to our common unitholders at current levels or to increase our quarterly distributions in the future could be impaired materially.
Our ability to pay quarterly distributions depends primarily on cash flow (including cash flow from operations, financial reserves and credit facilities) and not solely on profitability, which is affected by non-cash items. As a result, we may pay cash distributions during periods of losses and may be unable to pay cash distributions during periods of income. Our ability to generate sufficient cash from operations is largely dependent on our ability to manage our business successfully which may also be affected by economic, financial, competitive, regulatory, and other factors that are beyond our control. Because the cash we generate from operations will fluctuate from quarter to quarter, quarterly distributions may also fluctuate from quarter to quarter.
We are exposed to the credit risks and certain other risks, of our or our joint ventures' key customers, vendors, and other counterparties.
We are subject to risks of loss resulting from nonpayment or nonperformance by our or our joint ventures' customers, vendors or other counterparties. We and our joint ventures derive a significant portion of our revenues from contracts with key
customers, particularly HFC, under its pipelines and terminals, tankage, tolling and throughput agreements. To the extent that our or our joint ventures' customers are unable to meet the specifications of their customers, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers.
Mergers among our existing customers could provide strong economic incentives for the combined entities to use systems other than ours, and we could experience difficulty in replacing lost volumes and revenues. Because a significant portion of our operating costs are fixed, a reduction in volumes would result not only in a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and make distributions to unitholders.
If any of our or our joint ventures' key customers default on their obligations, our financial results could be adversely affected. Furthermore, some of our or our joint ventures' customers may be highly leveraged and subject to their own operating and regulatory risks. In addition, nonperformance by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability to successfully conduct our business.
Any substantial increase in the nonpayment and/or nonperformance by our or our joint ventures' customers or vendors could have a material adverse effect on our results of operations and cash flows.
In addition, in connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various counterparties, including HFC, have agreed to indemnify us, subject to certain limitations, for:
•certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition;
•certain matters arising from the pre-closing ownership and operation of assets; and
•ongoing remediation related to the assets.
Our business, results of operation, cash flows and our ability to make cash distributions to our unitholders.unitholders could be adversely affected in the future if third parties fail to satisfy an indemnification obligation owed to us.
Adverse changes in our and/or our general partner's credit ratings and risk profile may negatively affect us.
Our ability to access capital markets is important to our ability to operate our business. Regional and national economic conditions, increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating.
We are in compliance with all covenants or other requirements set forth in our Credit Agreement. Further, we do not have any rating downgrade triggers that would automatically accelerate the maturity dates of any debt.
While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could affect adversely our ability to borrow on, renew existing, or obtain access to new financing arrangements, could increase the cost of such financing arrangements, could reduce our level of capital expenditures and could impact our future earnings and cash flows.
The credit and business risk profiles of our general partner, and of HFC as the indirect owner of our general partner, may sufferbe factors in credit evaluations of us as a master limited partnership due to a change in the compositionsignificant influence of our Board of Directors, if any of our key senior executives or other key employees who provide services to us discontinue employment, or if certain of our executive officers, who also allocate time to our general partner and its affiliates, do not have enough time to dedicate to our business. Furthermore, a shortage of skilled labor or disruptions in the labor force that provides services to us may make it difficult for us to maintain labor productivity.
Our future success depends to a large extent on the services of HLS's Board of Directors, key senior executives and key senior employees who provide services to us. Also,indirect ownership over our business depends onactivities, including our cash distribution policy, acquisition strategy and business risk profile. Another factor that may be considered is the continuing ability to recruit, train and retain highly qualified employees in all areasfinancial condition of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any “key man” life insurance for any executives. Furthermore, our operations require skilled and experienced laborers with proficiency in multiple tasks.
Our general partner shares officers and administrative personnel with HFC to operate both our business and HFC's business. These officers face conflicts regardingits owners, including the allocationdegree of their financial leverage and other employees' time, which may affect adversely our results of operations,their dependence on cash flows and financial condition.flow from the partnership to service their indebtedness.
A portion of HFC's employees that are seconded to us from time to time are represented by labor unions under collective bargaining agreements with various expiration dates. HFC may not be able to renegotiate the collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, existing labor agreements may not prevent a future strike or work stoppage, and any work stoppage could negatively affect our results of operations and financial condition.
RISKS TO COMMON UNITHOLDERS
HFC and its affiliates may have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests.
Currently, HFC and certain of its subsidiaries collectively own a 57% limited partner interest and a non-economic general partner interest in us and controls HLS, the general partner of our general partner, HEP Logistics. Conflicts of interest may arise between HFC and its affiliates, including our general partner, on the one hand, and us, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its other affiliates over our interests. These conflicts include, among others, the following situations:
•HFC, as a shipper on our pipelines, has an economic incentive not to cause us to seek higher tariff rates or terminalling fees, even if such higher rates or terminalling fees would reflect rates that could be obtained in arm's-length,arm's -length, third-party transactions;
neither our partnership agreement nor any other agreement requires HFC to pursue a business strategy that favors us or utilizes our assets, including whether to increase or decrease refinery production, whether to shut down or reconfigure a refinery, or what markets to pursue or grow. •HFC's directors and officers have a fiduciary duty to make thesebusiness decisions in the best interests of the stockholders of HFC;
•our general partner is allowed to take into account the interests of parties other than us, such as HFC, in resolving conflicts of interest;
•our partnership agreement provides for modified or reduced fiduciary duties for our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
•our general partner determines which costs incurred by HFC and its affiliates are reimbursable by us;
•our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
•our general partner may, in some circumstances, cause us to borrow funds to make cash distributions, even where the purpose or effect of the borrowing benefits our general partner or affiliates;
•our general partner determines the amount and timing of our asset purchases and sales, capital expenditures and borrowings, each of which can affect the amount of cash available to us; and
•our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the pipelines and terminals agreement with HFC.
Cost reimbursements, which will be determined by our general partner, and fees due to our general partner and its affiliates for services provided, are substantial.
Under our Omnibus Agreement, we are obligated to pay HFC an administrative fee of currently $2.5$2.6 million per year for the provision by HFC or its affiliates of various general and administrative services for our benefit. Beginning July 1, 2018, theThe administrative fee is subject to an annual upward adjustment for changes in PPI. In addition, we are required to reimburse HFC pursuant to the secondment arrangement for the wages, benefits, and other costs of HFC employees seconded to HLS to perform services at certain of our processing, refining, pipeline and tankage assets. We can neither provide assurance that HFC will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable to us. If HFC fails to provide us with adequate personnel, our operations could be adversely impacted.
The administrative fee and secondment allocations are subject to annual review and may increase if we make an acquisition that requires an increase in the level of general and administrative services that we receive from HFC or its affiliates. Our general partner will determine the amount of general and administrative expenses that will be allocated to us in accordance with the terms of our partnership agreement. In addition, our general partner and its affiliates are entitled to reimbursement for all other expenses they incur on our behalf, including the salaries of and the cost of employee benefits for employees of HLS who provide services to us.
Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf, plus the administrative fee. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. Our general partner and its affiliates also may provide us other services for which we are charged fees as determined by our general partner.
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, fund expansion capital expenditures, or for other purposes.
As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, fund expansion capital expenditures or for other purposes. If we then issue additional equity at a significantly lower price, material dilution to our existing unitholders could result.
Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or the board of directors of HLS and have no right to do so on an annual or other continuing basis. The board of directors of HLS is chosen by the sole member of HLS. If unitholders are dissatisfied with the performance of our
general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. Unitholders will be unable to remove the general partner without its consent because the general partner and its affiliates own sufficient units to prevent its removal. Unitholders' voting rights are further restricted by the partnership agreement
provision providing that any units held by a person that owns 20% or more of any class of units then outstanding (other than the general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of the general partner's general partner) cannot vote on any matter; however, no such person currently exists. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings, acquire information about our operations, and influence the manner or direction of management.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the partners of our general partner from transferring their respective partnership interests in our general partner to a third party. The new partners of our general partner would then be in a position to replace the board of directors and officers of the general partner of our general partner with their own choices and to control the decisions made by the board of directors and officers.
We may issue additional limited partner units without unitholder approval, which would dilute an existing unitholder's ownership interests.
Under our partnership agreement, provided there is no significant decrease in our operating performance, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders, and HEP currently has a shelf registration on file with the SEC pursuant to which it may issue up to $2.0 billion in additional common units. On May 10, 2016, HEP established a continuous offering program under the shelf registration statement pursuant to which HEP may issue and sell common units from time to time, representing limited partner interests, up to an aggregate gross sales amount of $200 million. As of December 31, 2018,2021, HEP has issued 2.4 million units under this program for gross consideration of $82.3 million.
The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
•our unitholders' proportionate ownership interest in us will decrease;
•the amount of cash available for distribution on each unit may decrease;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of the common units may decline.
Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.
In establishing cash reserves, our general partner may reduce the amount of cash available for distribution to unitholders.
Our partnership agreement requires us to distribute all available cash to our unitholders; however, it also requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available to make the required payments to our debt holders or to pay the minimum quarterly distributiondistributions on our common units every quarter.
HFC and its affiliates may engage in limited competition with us.
HFC and its affiliates may engage in limited competition with us. Pursuant to the Omnibus Agreement, HFC and its affiliates agreed not to engage in the business of operating intermediate or refined product pipelines or terminals, crude oil pipelines or terminals, truck racks or crude oil gathering systems in the continental United States. The Omnibus Agreement, however, does not apply to:
•any business operated by HFC or any of its subsidiaries at the closing of our initial public offering;
•any business or asset that HFC or any of its subsidiaries acquires or constructs that has a fair market value or construction cost of less than $5 million; and
•any business or asset that HFC or any of its subsidiaries acquires or constructs that has a fair market value or construction cost of $5 million or more if we have been offered the opportunity to purchase the business or asset at fair market value, and we decline to do so.
In the event that HFC or its affiliates no longer control our partnership or there is a change of control of HFC, the non-competition provisions of the Omnibus Agreement will terminate.
Our general partner has a limited call right that may require a unitholder to sell its common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units (which it does not presently), our general partner will have the right (which it may assign to any of its affiliates or to us) but not the obligation to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, a holder of common units may be required to sell its units at a time or price that is undesirable to it and may not receive any return on its investment. A common unitholder may also incur a tax liability upon a sale of its units.
A unitholder may not have limited liability if a court finds that unitholder actions constitute control of our business or that we have not complied with state partnership law.
Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business. Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner.
In addition, Section 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Further, we conduct business in a number of states. In some of those states the limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established. The unitholders might be held liable for the partnership's obligations as if they were a general partner if a court or government agency determined that we were conducting business in the state but had not complied with the state's partnership statute.
HFC may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units. Additionally, HFC may pledge or hypothecate its common units or its interest in us.
HFC currently holds 59,630,030 of our common units, which is approximately 57% of our outstanding common units. The sale of these units in the public or private markets could have an adverse impact on the trading price of our common units. Additionally, we agreed to provide HFC registration rights with respect to our common units that it holds. HFC may pledge or hypothecate its common units, and such pledge or hypothecation may include terms and conditions that might result in an adverse impact on the trading price of our common units.
TAX RISKS TO COMMON UNITHOLDERS
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as usand not being subject to a material amount of entity-level taxation by individual states. If the U.S. Internal Revenue Service (the “IRS”)IRS were to treat us as a corporation for U.S. federal income tax purposes or if we were to become subject to additional amounts of entity-level taxation for federal or state tax purposes, our cash available for distribution to our unitholders wouldcould be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income"“qualifying income” requirement. Based upon our current operations and current Treasury Regulations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. Distributions to unitholders would generally be taxed again as corporate distributions, and no income,
income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders wouldcould be substantially reduced. Therefore, our treatment of us as a corporation wouldcould result in a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of our common units.
At the entity level, wereif we to bewere subject to U.S. federal income tax, we would also be subject to the income tax provisions of many states. Moreover, states are evaluating ways to independently subject partnerships to entity-level taxation through the imposition of state income taxes, franchise taxes and other forms of taxation. For example, we are required to pay Texas margin tax on any income apportioned to Texas.Texas, despite our status as a partnership. Imposition of any additional such taxes on us or an increase in the existing tax rates wouldcould reduce the cash available for distributions to our unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships including us, or an investment in our common units may be modified by administrative, legislative or judicial changes and differing interpretations at any time. From time to time, membersMembers of Congress proposehave frequently proposed and considerconsidered similar substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including a prior legislative proposalproposals that would have eliminated the qualifying income exceptioneliminate our ability to the treatment of all publicly traded partnerships as corporations, upon which we relyqualify for our treatment as a partnership for federal income tax purposes.treatment.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. Although there are no current legislative or administrative proposals, thereThere can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department'sDepartment’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future, which could also negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws and interpretations thereof may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. You are urged to consult with your own tax advisor with respect to the status of legislative, regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions we have taken or may take on tax matters. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. Atake, and a court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS willwould be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced, and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on their behalf.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Under our partnership agreement, our general partner is permitted to make elections under the newthese rules to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each affected current and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our affected current and former unitholders take such audit adjustment into account and pay any resulting taxes (including any applicable penalties orand interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties andor interest, our cash available for distribution to our unitholders might be substantially reduced, and our current and former unitholders may be required to indemnify us for any taxes (including any applicable
penalties and interest) resulting from such audit adjustments that were paid on their behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Even if youunitholders do not receive any cash distributions from us, youthey will be required to pay taxes on yourtheir share of our taxable income.
YouUnitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes, on yourtheir share of our taxable income, whether or not youthey receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, youunitholders may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt, could result in “cancellation of indebtedness income” being allocated to youunitholders as taxable income without any increase in our cash available for distribution. YouUnitholders may not receive cash distributions from us equal to yourtheir share of our taxable income or even equal to the actual tax due from youthe unitholder with respect to that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a unitholder disposes of common units, it will recognize gain or loss equal to the difference between the amount realized and its tax basis in those common units. Because distributions in excess of a unitholder's allocable share of our net taxable income result in a decrease of the unitholder's tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price the unitholder receives is less than its original cost. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
A substantial portion of the amount realized from the sale of a unitholder's common units, whether or not representing gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. Thus, the unitholder may recognize both ordinary income and capital loss from the sale of such units if the amount realized on a sale of such units is less than the unitholder's adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which the unitholder sells hisits units, the unitholder may recognize ordinary income from our allocations of income and gain to the unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we
We are generally entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. If this limitation weredepletion to applythe extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to a taxable year,inventory.
If our business interest is subject to limitation under these rules, it could result in an increase in the taxable income allocable to a unitholder for such taxable year without any corresponding increase in the cash available for distribution to such unitholder.
Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses/activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are generally taxed and subject to U.S. income tax filing requirements on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected”effectively connected with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate, and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of
Moreover, the amount realized upon a non-U.S. unitholder’s sale or exchangetransferee of an interest in a partnership that is engaged in a U.S. trade or business. However, duebusiness is generally required to challengeswithhold 10% of administeringthe “amount realized” by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s amount realized generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury Regulations provide that the amount realized on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury Regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022, and administrative guidance from the IRS further provides that such withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the applicationbeen deferred until January 1, 2023. For a transfer of this withholding rule to open market transfers of interestinterests in a publicly traded partnerships pending promulgation of regulationspartnership that is effected through a broker on or other guidance that resolvesafter January 1, 2023, the challenges. Itobligation to withhold is not clear if or when such regulations or other guidance will be issued. Non-U.S.imposed on the transferor’s broker. Prospective foreign unitholders should consult atheir tax advisor before investingadvisors regarding the impact of these rules on an investment in our common units.
We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units, and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from unitholders' sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to their tax returns.adjustments.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month (the "Allocation Date") based upon the ownership of our units on the first day of each month (the “Allocation Date”) instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, it would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies in determining a unitholder's allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters,
we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain recognized from our unitholders' sale of common units and
could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
Unitholders likely will be subject to state and local taxes and return filing requirements as a result of investing in our common units.
In addition to U.S. federal income taxes,tax, unitholders likely will be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future. Unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions, even if they do not live in these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in Texas, New Mexico, Utah, Idaho, Oklahoma, Washington, Kansas, Wyoming and Nevada. We may also own property or conduct business in other states or foreign countries in the future.future, including following the closing of the HEP Transaction. It is the unitholder's responsibility to file all federal, state, local and foreign tax returns.
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Item 1B. | Unresolved Staff Comments |
Item 1B.Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
Item 3.Legal Proceedings
In the ordinary course of business, we may become party to legal, regulatory or administrative proceedings or governmental investigations, including environmental and other matters. Damages or penalties may be sought from us in some matters and certain matters may require years to resolve. While the outcome and impact of these proceedings and investigations on us cannot be predicted with certainty, based on advice of counsel, management believes that the resolution of these proceedings and investigations, through settlement or adverse judgment, will not, either individually or in the aggregate, have a materiallymaterial adverse effect on our financial condition, results of operations or cash flows.
Environmental Matters
We are reporting the following proceeding to comply with SEC regulations which require us to disclose proceedings arising under federal, state or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings may result in monetary sanctions of $100,000 or more. Our respective subsidiaries have or will develop corrective action plans regarding the subject of this proceeding that will be implemented in consultation with the respective federal and state agencies. It is not possible to predict the ultimate outcome of this proceeding, although it is not currently expected to have a material effect on our financial condition, results of operations or cash flows.
Written Safety Compliance Program
Holly Energy Partners - Operating, L.P. (“HEP Operating”) received a Notice of Probable Violation ("NOPV") dated June 20, 2018 from the Pipeline and Hazardous Materials Safety Administration (“PHMSA”). The NOPV follows a routine inspection of HEP's facilities and records and was not issued in response to an incident. In the NOPV, PHMSA alleges certain regulatory violations involving HEP Operating’s written safety compliance program for its pipelines, terminals and tanks. PHMSA has proposed a civil penalty and a compliance order that would require HEP Operating to take certain remedial actions. HEP Operating is currently working with PHMSA to resolve this matter.
Other
We are a party to various other legal and regulatory proceedings, which we believe, based on the advice of counsel, will not either individually or in the aggregate have a materially adverse impact on our financial condition, results of operations or cash flows.
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Item 4. | Mine Safety Disclosures |
Item 4.Mine Safety Disclosures
Not applicable.
PART II
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Item 5. | Market for the Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units |
Item 5.Market for the Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units
Our common limited partner units are traded on the New York Stock Exchange under the symbol “HEP.”
As of February 13, 2019,15, 2022, we had approximately 18,90917,216 common unitholders, including beneficial owners of common units held in street name.
We consider regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. See “Liquidity and Capital Resources” under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of conditions and limitations prohibiting distributions under the Credit Agreement and indentures relating to our senior notes.
Common Unit Repurchases Made in the Quarter
The following table discloses purchases of our common units made by us or on our behalf for the periods shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Total Number of
Units Purchased | | Average Price
Paid Per Unit | | Total Number of
Units Purchased as
Part of Publicly
Announced Plan or
Program | | Maximum Number
of Units that May
Yet be Purchased
Under a Publicly
Announced Plan or
Program |
| October 2021 | | — | | | $ | — | | | — | | | $ | — | |
| November 2021 | | 113,729 | | | $ | 17.21 | | | — | | | $ | — | |
| December 2021 | | 31,734 | | | $ | 16.42 | | | — | | | $ | — | |
| Total for October to December 2021 | | 145,463 | | | | | — | | | |
|
| | | | | | | | | | | | | | |
| Period | | Total Number of Units Purchased | | Average Price Paid Per Unit | | Total Number of Units Purchased as Part of Publicly Announced Plan or Program | | Maximum Number of Units that May Yet be Purchased Under a Publicly Announced Plan or Program |
| October 2018 | | — |
| | $ | — |
| | — |
| | $ | — |
|
| November 2018 | | — |
| | $ | — |
| | — |
| | $ | — |
|
| December 2018 | | 17,606 |
| | $ | 28.96 |
| | — |
| | $ | — |
|
| Total for October to December 2018 | | 17,606 |
| | | | — |
| | |
The units reported represent (a) purchases of 113,729 common units in the open market for delivery to the recipients of our phantom unit and performance unit awards under our Long-Term Incentive Plan at the time of grant or settlement, as applicable; and (b) the delivery of 17,60631,734 common units (which units were previously issued to certain officers and other employees pursuant to restricted unit awards or phantom unit awards at the time of grant)grant or settlement, as applicable) by such officers and employees to provide funds for the payment of payroll and income taxes due at vesting in the case of officers and employees who did not elect to satisfy such taxes by other means.
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Item 6. | Selected Financial Data |
The following table shows selected financial information from the consolidated financial statements of HEP and from the financial statements of our Predecessor (defined below). We acquired assets from HFC, including El Dorado Operating on November 1, 2015, crude tanks at HFC's Tulsa refinery on March 31, 2016 and Woods Cross Operating on October 1, 2016. As we are a variable interest entity controlled by HFC, these acquisitions were accounted for as transfers between entities under common control. Accordingly, this financial data includes the historical results of these acquisitions for all periods presented prior to the effective dates of each acquisition. We refer to these historical results as those of our "Predecessor." See Note 2 in notes to consolidated financial statements of HEP for further discussion of these acquisitions.
This table should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements of HEP and related notes thereto included elsewhere in this Form 10-K.6.[Reserved]
|
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | | (In thousands, except per unit data) |
| Statement of Income Data: | | | | | | | | | | |
| Revenues | | $ | 506,220 |
| | $ | 454,362 |
| | $ | 402,043 |
| | $ | 358,875 |
| | $ | 332,545 |
|
| Operating costs and expenses | | | | | | | | | | |
| Operations (exclusive of depreciation and amortization) | | 146,430 |
| | 137,605 |
| | 123,986 |
| | 105,556 |
| | 106,185 |
|
| Depreciation and amortization | | 98,492 |
| | 79,278 |
| | 70,428 |
| | 63,306 |
| | 62,529 |
|
| General and administrative | | 11,040 |
| | 14,323 |
| | 12,532 |
| | 12,556 |
| | 10,824 |
|
| | | 255,962 |
| | 231,206 |
| | 206,946 |
| | 181,418 |
| | 179,538 |
|
| Operating income | | 250,258 |
| | 223,156 |
| | 195,097 |
| | 177,457 |
| | 153,007 |
|
| Equity in earnings of equity method investments | | 5,825 |
| | 12,510 |
| | 14,213 |
| | 4,803 |
| | 2,987 |
|
| Interest expense | | (71,899 | ) | | (58,448 | ) | | (52,552 | ) | | (37,418 | ) | | (36,101 | ) |
| Interest income | | 2,108 |
| | 491 |
| | 440 |
| | 526 |
| | 3 |
|
| Loss on early extinguishments of debt | | — |
| | (12,225 | ) | | — |
| | — |
| | (7,677 | ) |
| Remeasurement gain on preexisting equity interests | | — |
| | 36,254 |
| | — |
| | — |
| | — |
|
| Gain on sale of assets and other | | 121 |
| | 422 |
| | 677 |
| | 486 |
| | 82 |
|
| | | (63,845 | ) | | (20,996 | ) | | (37,222 | ) | | (31,603 | ) | | (40,706 | ) |
| Income before income taxes | | 186,413 |
| | 202,160 |
| | 157,875 |
| | 145,854 |
| | 112,301 |
|
| State income tax expense | | (26 | ) | | (249 | ) | | (285 | ) | | (228 | ) | | (235 | ) |
| Net income | | 186,387 |
| | 201,911 |
| | 157,590 |
| | 145,626 |
| | 112,066 |
|
| Allocation of net loss attributable to Predecessor | | — |
| | — |
| | 10,657 |
| | 2,702 |
| | 1,747 |
|
| Allocation of net income attributable to noncontrolling interests | | (7,540 | ) | | (6,871 | ) | | (10,006 | ) | | (11,120 | ) | | (8,288 | ) |
| Net income attributable to the partners | | 178,847 |
| | 195,040 |
| | 158,241 |
| | 137,208 |
| | 105,525 |
|
General partner interest in net income, including incentive distributions(1) | | — |
| | (35,047 | ) | | (57,173 | ) | | (42,337 | ) | | (34,667 | ) |
| Limited partners’ interest in net income | | $ | 178,847 |
| | $ | 159,993 |
| | $ | 101,068 |
| | $ | 94,871 |
| | $ | 70,858 |
|
Limited partners’ earnings per unit – basic and diluted(1) | | $ | 1.70 |
| | $ | 2.28 |
| | $ | 1.69 |
| | $ | 1.60 |
| | $ | 1.20 |
|
| Distributions per limited partner unit | | $ | 2.6475 |
| | $ | 2.5475 |
| | $ | 2.3625 |
| | $ | 2.2025 |
| | $ | 2.0750 |
|
| | | | | | | | | | | |
| Other Financial Data: | | | | | | | | | | |
| Cash flows from operating activities | | $ | 295,213 |
| | $ | 238,487 |
| | $ | 243,548 |
| | $ | 231,442 |
| | $ | 185,256 |
|
| Cash flows from investing activities | | $ | (52,343 | ) | | $ | (286,273 | ) | | $ | (143,030 | ) | | $ | (246,680 | ) | | $ | (198,423 | ) |
| Cash flows from financing activities | | $ | (247,601 | ) | | $ | 51,905 |
| | $ | (111,874 | ) | | $ | 27,421 |
| | $ | 9,645 |
|
EBITDA(2) | | $ | 347,156 |
| | $ | 332,524 |
| | $ | 277,545 |
| | $ | 237,180 |
| | $ | 204,024 |
|
Distributable cash flow(3) | | $ | 265,087 |
| | $ | 242,955 |
| | $ | 218,810 |
| | $ | 197,046 |
| | $ | 172,718 |
|
Maintenance capital expenditures(4) | | $ | 8,182 |
| | $ | 7,748 |
| | $ | 9,658 |
| | $ | 8,926 |
| | $ | 4,616 |
|
| Expansion capital expenditures | | 39,118 |
| | 37,062 |
| | 50,046 |
| | 30,467 |
| | 75,343 |
|
| Acquisition capital expenditures | | 6,841 |
| | 245,446 |
| | 44,119 |
| | 153,728 |
| | 118,727 |
|
| Total capital expenditures | | $ | 54,141 |
| | $ | 290,256 |
| | $ | 103,823 |
| | $ | 193,121 |
| | $ | 198,686 |
|
| | | | | | | | | | | |
| Balance Sheet Data (at period end): | | | | | | | | | | |
| Net property, plant and equipment | | $ | 1,538,655 |
| | $ | 1,569,471 |
| | $ | 1,328,395 |
| | $ | 1,293,060 |
| | $ | 1,163,631 |
|
| Total assets | | $ | 2,102,540 |
| | $ | 2,154,114 |
| | $ | 1,884,237 |
| | $ | 1,777,646 |
| | $ | 1,584,114 |
|
Long-term debt(5) | | $ | 1,418,900 |
| | $ | 1,507,308 |
| | $ | 1,243,912 |
| | $ | 1,008,752 |
| | $ | 866,986 |
|
| Total liabilities | | $ | 1,586,979 |
| | $ | 1,669,049 |
| | $ | 1,412,446 |
| | $ | 1,151,424 |
| | $ | 989,324 |
|
Total equity(6) | | $ | 515,561 |
| | $ | 485,065 |
| | $ | 471,791 |
| | $ | 626,222 |
| | $ | 594,790 |
|
- 51 -
| |
(1) | Net income attributable to the partners is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner included incentive distributions that were declared subsequent to quarter end. After the amount of incentive distributions and other priority allocations are allocated to the general partner, the remaining net income attributable to the partners is allocated to the partners based on their weighted average ownership percentage during the period. As a result of the IDR Restructuring Transaction, no IDR or general partner distributions were made after October 31, 2017. See "Business and Properties - Overview." |
| |
(2) | Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to the partners plus (i) interest expense, net of interest income, (ii) state income tax and (iii) depreciation and amortization excluding amounts related to the Predecessor. EBITDA is not a calculation based upon generally accepted accounting principles (“GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income attributable to the partners or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants. |
Set forth below is our calculation of EBITDA.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | | (In thousands) |
| Net income attributable to the partners | | $ | 178,847 |
| | $ | 195,040 |
| | $ | 158,241 |
| | $ | 137,208 |
| | $ | 105,525 |
|
| Add (subtract): | | | | | | | | | | |
| Interest expense | | 68,858 |
| | 55,385 |
| | 49,306 |
| | 35,490 |
| | 34,280 |
|
| Interest income | | (2,108 | ) | | (491 | ) | | (440 | ) | | (526 | ) | | (3 | ) |
| Amortization of discount and deferred debt issuance costs | | 3,041 |
| | 3,063 |
| | 3,246 |
| | 1,928 |
| | 1,821 |
|
| State income tax expense | | 26 |
| | 249 |
| | 285 |
| | 228 |
| | 235 |
|
| Depreciation and amortization | | 98,492 |
| | 79,278 |
| | 70,428 |
| | 63,306 |
| | 62,529 |
|
| Predecessor depreciation and amortization | | — |
| | — |
| | (3,521 | ) | | (454 | ) | | (363 | ) |
| EBITDA | | $ | 347,156 |
| | $ | 332,524 |
| | $ | 277,545 |
| | $ | 237,180 |
| | $ | 204,024 |
|
| |
(3) | Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts presented in our consolidated financial statements, with the general exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also used by management for internal analysis and for our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating. |
Set forth below is our calculation of distributable cash flow.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | | (In thousands) |
| Net income attributable to the partners | | $ | 178,847 |
| | $ | 195,040 |
| | $ | 158,241 |
| | $ | 137,208 |
| | $ | 105,525 |
|
| Add (subtract): | | | | | | | | | | |
| Depreciation and amortization | | 98,492 |
| | 79,278 |
| | 70,428 |
| | 63,306 |
| | 62,529 |
|
| Remeasurement gain on preexisting equity interests | | — |
| | (36,254 | ) | | — |
| | — |
| | — |
|
| Amortization of discount and deferred debt issuance costs | | 3,041 |
| | 3,063 |
| | 3,246 |
| | 1,928 |
| | 1,821 |
|
| Loss on early extinguishment of debt | | — |
| | 12,225 |
| | — |
| | — |
| | 7,677 |
|
| Increase (decrease) in deferred revenue related to minimum revenue commitments | | (786 | ) | | (1,283 | ) | | (1,292 | ) | | (1,233 | ) | | (2,503 | ) |
Maintenance capital expenditures (4) | | (8,182 | ) | | (7,748 | ) | | (9,658 | ) | | (8,926 | ) | | (4,616 | ) |
| Increase (decrease) in environmental liability | | (237 | ) | | (581 | ) | | (584 | ) | | 1,107 |
| | 1,596 |
|
| Increase (decrease) in reimbursable deferred revenue | | (5,179 | ) | | (3,679 | ) | | (2,733 | ) | | 176 |
| | (2,274 | ) |
| Other non-cash adjustments | | (909 | ) | | 2,894 |
| | 4,683 |
| | 3,934 |
| | 3,326 |
|
| Predecessor depreciation and amortization | | — |
| | — |
| | (3,521 | ) | | (454 | ) | | (363 | ) |
| Distributable cash flow | | $ | 265,087 |
| | $ | 242,955 |
| | $ | 218,810 |
| | $ | 197,046 |
| | $ | 172,718 |
|
| |
(4) | Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations. |
| |
(5) | Includes $923 million, $1,012 million, $553 million, $712 million and $571 million in Credit Agreement advances that were classified as long-term debt at December 31, 2018, 2017, 2016, 2015 and 2014, respectively. |
| |
(6) | As a master limited partnership, we distribute our available cash, which historically has exceeded our net income attributable to the partners because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in partners’ equity since our regular quarterly distributions have exceeded our quarterly net income attributable to partners. Additionally, if the assets contributed and acquired from HFC while we were a consolidated variable interest entity of HFC had been acquired from third parties, our acquisition cost in excess of HFC’s basis in the transferred assets would have been recorded in our financial statements as increases to our properties and equipment and intangible assets at the time of acquisition instead of decreases to partners’ equity. |
| |
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Item 7, including but not limited to the sections onunder “Results of Operations” and “Liquidity and Capital Resources,” contains forward-looking statements. See “Forward-Looking Statements” at the beginning of Part I and Item 1A. “Risk Factors.” In this document, the words “we,” “our,” “ours” and “us” refer to HEPHolly Energy Partners, L.P. (“HEP”) and its consolidated subsidiaries or to HEP or an individual subsidiary and not to any other person.
OVERVIEW
HEP is a Delaware limited partnership. WeThrough our subsidiaries and joint ventures we own andand/or operate petroleum product and crude oil pipelines, terminal, tankage and loading rack facilities and refinery processing units that support the refining and marketing operations of HFCHollyFrontier Corporation (“HFC”) and other refineries in the Mid-Continent, Southwest and Northwest regions of the United States and Delek’s refinery in Big Spring, Texas.States. HEP, through its subsidiaries and joint ventures, owns and/or operates petroleum product and crude pipelines, tankage and terminals in Texas, New Mexico, Washington, Idaho, Oklahoma, Utah, Nevada, Wyoming and Kansas as well as refinery processing units in Utah and Kansas. HFC owned 57% of our outstanding common units and the non-economic general partner interest as of December 31, 2018.2021.
We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling and storing refined products and other hydrocarbons, providing other services at our storage tanks and terminals and charging a tolling fee per barrel or thousand standard cubic feet of feedstock throughput in our refinery processing units. We do not take ownership of products that we transport, terminal or store, and therefore we are not directly exposed to changes in commodity prices.
We believe the long-term growth of global refined product demand and US crude production should support high utilization rates for the refineries we serve, which in turn will support volumes in our product pipelines, crude gathering system and terminals.
Acquisitions
On February 22, 2016, HFC obtained a 50% membership interest in Osage Pipe LineAugust 2, 2021, HEP, The Sinclair Companies (“Sinclair”), and Sinclair Transportation Company, LLC (“Osage”) in a non-monetary exchange for a 20-year terminalling services agreement, whereby, a subsidiary of Magellan Midstream Partners (“Magellan”) will provide terminalling services for all HFC products originating in Artesia, New Mexico that require terminalling in or through El Paso, Texas. Osage is the owner of the Osage pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to HFC’s El Dorado Refinery in Kansas and also has a connection to the Jayhawk pipeline that services the CHS refinery in McPherson, Kansas. The Osage pipeline is the primary pipeline that supplies HFC's El Dorado Refinery with crude oil.
Concurrent with this transaction, we entered into a non-monetary exchange with HFC, whereby we received HFC’s interest in Osage in exchange for our El Paso terminal. Under this exchange, we also agreed to build two connections on our south products pipeline system that permit HFC access to Magellan’s El Paso terminal. Effective upon the closing of this exchange, we are the named operator of the Osage pipeline and transitioned into this role on September 1, 2016.
On March 31, 2016, we acquired crude oil tanks located at HFC’s Tulsa refinery from an affiliate of Plains for $39.5 million. In 2009, HFC sold these tanks to Plains and leased them back, and due to HFC’s continuing interest in the tanks, HFC accounted for the transaction as a financing arrangement. Accordingly, the tanks remained on HFC’s balance sheet and were depreciated for accounting purposes.
On June 3, 2016, we acquired a 50% interest in Cheyenne Pipeline LLC, owner of the Cheyenne pipeline, in exchange for a contribution of $42.6 million in cash to Cheyenne Pipeline LLC. Cheyenne Pipeline LLC will continue to be operated by an affiliate of Plains, which owns the remaining 50% interest. The 87-mile crude oil pipeline runs from Fort Laramie to Cheyenne, Wyoming and has an 80,000 barrel per day (“bpd”) capacity.
On October 1, 2016, we acquired all the membership interests of Woods Cross Operating, a wholly owned subsidiary of HFC,Sinclair (“STC”), entered into a Contribution Agreement (the “Contribution Agreement”) pursuant to which ownsHEP will acquire all of the outstanding shares of STC in exchange for 21 million newly constructed atmospheric distillation tower, fluid catalytic cracking unit,issued common units of HEP and polymerization unit located at HFC’s Woods Cross refinery for cash consideration equal to $325 million (the “HEP Transaction”), subject to downward adjustment if, as a condition to obtaining antitrust clearance for the Sinclair Transactions (as defined below), HEP agrees to divest a portion of $278 million. Inits equity interest in UNEV Pipeline, LLC and the sales price for such interests does not exceed the threshold provided in the Contribution Agreement.
The Sinclair Transactions are expected to close in 2022, subject to customary closing conditions and regulatory clearance, including the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (the “HSR Act”). On August 23, 2021, each of HFC and Sinclair filed its respective premerger notification and report regarding the Sinclair Transactions with the U.S. Department of Justice and the U.S. Federal Trade Commission (the “FTC”) under the HSR Act. On September 22, 2021, HFC and Sinclair each received a request for additional information and documentary material (“Second Request”) from the FTC in connection with this transaction, we entered into 15-year tolling agreements containing minimum quarterly throughput commitments fromthe FTC’s review of the Sinclair Transactions. Issuance of the Second Request extends the waiting period under the HSR Act until 30 days after both HFC and Sinclair have substantially complied with the Second Request, unless the waiting period is terminated earlier by the FTC or the parties otherwise commit not to close the Sinclair Transactions for some additional period of time. HFC and Sinclair are cooperating with the FTC staff in its review and are working diligently to satisfy the closing conditions as soon as possible. In addition, the HEP Transaction is conditioned on the closing of the transactions contemplated by that provide minimum annualized revenues of $57 millioncertain Business Combination Agreement, dated as of August 2, 2021, by and among HFC, Sinclair and certain other parties, which will occur immediately following the acquisition date.HEP Transaction (the “HFC Transaction,” and together with the HEP Transaction, the “Sinclair Transactions”). See Note 2 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information.
Impact of COVID-19 on Our Business
We are a consolidated variable interest entity of HFC. Therefore,Our business depends in large part on the acquisitionsdemand for the various petroleum products we transport, terminal and store in the markets we serve. The initial impact of the COVID-19 pandemic on the global macroeconomy created diminished demand, as well as lack of forward visibility, for refined products and crude tanksoil transportation, and for the terminalling and storage services that we provide. Since the declines in demand at HFC's Tulsa refinery on March 31, 2016,the beginning of the COVID-19 pandemic, we began to see improvement in demand for these products and Woods Cross Operating on October 1, 2016, were accounted for as transfers between entities under common control. Accordingly, this financial data has been retrospectively adjusted to include the historical results of these acquisitions for all periods presented prior to the effective dates of each acquisition. We refer to these historical results as those of our "Predecessor." See Notes 1 and 2services beginning late in the notes to consolidated financial statementssecond quarter of HEP included in this annual report for further discussion of these acquisitions and basis of presentation.
On October 31, 2017, we acquired the remaining 75% interest in SLC Pipeline and the remaining 50% interest in Frontier Aspen from subsidiaries of Plains, for cash consideration of $250 million. Prior to this acquisition, we held noncontrolling interests of 25% of SLC Pipeline and 50% of Frontier Aspen. As a result of the acquisitions, SLC Pipeline and Frontier Aspen are wholly-owned subsidiaries of HEP.
This acquisition was accounted for as a business combination achieved in stages with the consideration allocated to the acquisition date fair value of assets and liabilities acquired. The preexisting equity interests in SLC Pipeline and Frontier Aspen were remeasured at acquisition date fair value since we will have a controlling interest, and we recognized a gain on the remeasurement in2020 that continued through the fourth quarter of 20172021, with aggregate volumes approaching pre-pandemic levels. We expect our customers will continue to adjust refinery production levels commensurate with market demand and ultimately expect demand to return to pre-COVID-19 levels.
Most of $36.3 million.our employees have returned to work at our locations, and we continue to follow Centers for Disease Control and local government guidance. We will continue to monitor developments in the COVID-19 pandemic and the dynamic environment it has created to properly address these policies going forward.
SLCIn 2022, HEP expects to hold its quarterly distribution constant at $0.35 per unit, or $1.40 on an annualized basis. HEP remains committed to its distribution strategy focused on funding all capital expenditures and distributions within operating cash flow and maintaining distributable cash flow coverage of 1.3x or greater with the goal of reducing leverage to 3.0-3.5x.
On March 27, 2020, the United States government passed the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), an approximately $2 trillion stimulus package that included various provisions intended to provide relief to individuals and businesses in the form of tax changes, loans and grants, among others. At this time, we have not sought relief in the form of loans or grants from the CARES Act; however, we have benefited from certain tax deferrals in the CARES Act and may benefit from other tax provisions if we meet the requirements to do so.
The extent to which HEP’s future results are affected by the COVID-19 pandemic will depend on various factors and consequences beyond our control, such as the duration and scope of the pandemic, the effects of any new variant strains of the underlying virus, additional actions by businesses and governments in response to the pandemic and the speed and effectiveness of responses to combat the virus. However, we have long-term customer contracts with minimum volume commitments, which have expiration dates from 2022 to 2036. These minimum volume commitments accounted for approximately 76% of our total revenues in 2021. We are currently not aware of any reasons that would prevent such customers from making the minimum payments required under the contracts or potentially making payments in excess of the minimum payments. In addition to these payments, we also expect to collect payments for services provided to uncommitted shippers. There have been no material changes to customer payment terms due to the COVID-19 pandemic.
The COVID-19 pandemic, and the volatile regional and global economic conditions stemming from it, could also exacerbate the risk factors identified in this Form 10-K under “Risk Factors” in Item 1A. The COVID-19 pandemic may also materially adversely affect our results in a manner that is either not currently known or that we do not currently consider to be a significant risk to our business.
Investment in Joint Venture
On October 2, 2019, HEP Cushing LLC (“HEP Cushing”), a wholly-owned subsidiary of HEP, and Plains Marketing, L.P., a wholly-owned subsidiary of Plains All American Pipeline, isL.P. (“Plains”), formed a 50/50 joint venture, Cushing Connect Pipeline & Terminal LLC (the “Cushing Connect Joint Venture”), for (i) the ownerdevelopment, construction, ownership and operation of a 95-mile crude pipeline that transportsnew 160,000 barrel per day common carrier crude oil pipeline (the “Cushing Connect Pipeline”) that will connect the Cushing, Oklahoma crude oil hub to the Tulsa, Oklahoma refining complex owned by a subsidiary of HFC and (ii) the ownership and operation of 1.5 million barrels of crude oil storage in Cushing, Oklahoma (the “Cushing Connect JV Terminal”). The Cushing Connect JV Terminal went in service during the second quarter of 2020, and the Cushing Connect Pipeline was placed into service at the Salt Lake City area from the Utah terminalend of the Frontierthird quarter of 2021. Long-term commercial agreements have been entered into to support the Cushing Connect Joint Venture assets.
The Cushing Connect Joint Venture has contracted with an affiliate of HEP to manage the construction and operation of the Cushing Connect Pipeline and from Wahsatch Station. Frontier Aspen iswith an affiliate of Plains to manage the owneroperation of a 289-mile crude pipeline from Casper, Wyomingthe Cushing Connect JV Terminal. The total Cushing Connect Joint Venture investment will generally be shared equally among the partners. However, we are solely responsible for any Cushing Connect Pipeline construction costs that exceed the budget by more than 10%. HEP estimates its share of the cost of the Cushing Connect JV Terminal contributed by Plains and Cushing Connect Pipeline construction costs are approximately $70 million to Frontier Station, Utah that supplies Canadian and Rocky Mountain crudes$75 million, including $4 million to Salt Lake City area refiners through a connection$6 million of Cushing Connect Pipeline construction costs exceeding the budget by more than 10% to the SLC Pipeline.be borne solely by HEP.
Agreements with HFC and Delek
We serve HFC's refineries under long-term pipeline, terminal, tankage and refinery processing unit throughput agreements expiring from 20192022 to 2036. Under these agreements, HFC agrees to transport, store, and process throughput volumes of refined product, crude oil and feedstocks on our pipelines, terminal, tankage, loading rack facilities and refinery processing units that result in minimum annual payments to us. These minimum annual payments or revenues are subject to annual rate adjustments on July 1st each year based on the PPI or the FERC index. On December 17, 2020, FERC established a new price index for the five-year period commencing July 1, 2021 and ending June 30, 2026, in which common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price Index plus 0.78%. FERC received requests for rehearing of its December 17, 2020 order, and on January 20, 2022, FERC revised the index level used to determine annual changes to interstate oil pipeline rate ceilings to Producer Price Index minus 0.21%. The order requires the recalculation of the July 1, 2021
index ceilings to be effective as of March 1, 2022. As of December 31, 2018,2021, these agreements with HFC requirerequired minimum annualized payments to us of $314$352.8 million.
If HFC fails to meet its minimum volume commitments under the agreements in any quarter, it will be required to pay us the amount of any shortfall in cash by the last day of the month following the end of the quarter. Under certain of the agreements, a shortfall payment may be applied as a credit in the following four quarters after minimum obligations are met.
We have a pipelines and terminals agreement with Delek expiring in 2020 under which Delek has agreed to transport on our pipelines and throughput through our terminals volumes of refined products that result in a minimum level of annual revenue that is also subject to annual tariff rate adjustments. We also have a capacity lease agreement under which we lease Delek space on our Orla to El Paso pipeline for the shipment of refined product. The terms for a portion of the capacity under this lease agreement expired in 2018 and were not renewed, and the remaining portions of capacity expire in 2020 and 2022. As of December 31, 2018, these agreements with Delek require minimum annualized payments to us of $32 million.
A significant reduction in revenues under thesethe HFC agreements could have a material adverse effect on our results of operations.
On June 1, 2020, HFC announced plans to permanently cease petroleum refining operations at its Cheyenne refinery and to convert certain assets at that refinery to renewable diesel production. HFC subsequently began winding down petroleum refining operations at its Cheyenne refinery on August 3, 2020.
On February 8, 2021, HEP and HFC finalized and executed new agreements for HEP's Cheyenne assets with the following terms, in each case effective January 1, 2021: (1) a ten-year lease with two five-year renewal option periods for HFC’s use of certain HEP tank and rack assets in the Cheyenne refinery to facilitate renewable diesel production with an annual lease payment of approximately $5 million, (2) a five-year contango service fee arrangement that will utilize HEP tank assets inside the Cheyenne refinery where HFC will pay a base tariff to HEP for available crude oil storage and HFC and HEP will split any profits generated on crude oil contango opportunities and (3) a $10 million one-time cash payment from HFC to HEP for the termination of the existing minimum volume commitment.
Under certain provisions of an omnibus agreement that we have with HFC (“Omnibus Agreement”), we pay HFC an annual administrative fee ($2.52.6 million in 2018)2021), for the provision by HFC or its affiliates of various general and administrative services to us. This fee does not include the salaries of personnel employed by HFC who perform services for us on behalf of HLS or the cost of their employee benefits, which are separately charged to us by HFC. We also reimburse HFC and its affiliates for direct expenses they incur on our behalf.
Under HLS’s Secondment Agreement with HFC, certain employees of HFC are seconded to HLS to provide operational and maintenance services for certain of our processing, refining, pipeline and tankage assets, and HLS reimburses HFC for its prorated portion of the wages, benefits, and other costs of these employees for our benefit.
We have a long-term strategic relationship with HFC.HFC that has historically facilitated our growth. Our currentfuture growth plan isplans include organic projects around our existing assets and select investments or acquisitions that enhance our service platform while creating accretion for our unitholders. While in the near term, any acquisitions would be subject to continueeconomic conditions discussed in “Overview - Impact of COVID-19 on Our Business” above, we also expect over the longer term to pursue purchases of logistic and other assets at HFC's existing refining locations in New Mexico, Utah, Oklahoma, Kansas and Wyoming. We also expectcontinue to work with HFC on logistic asset acquisitions in conjunction with HFC’s refinery acquisition strategies.
Furthermore, we plan to continue to pursue third-party logistic asset acquisitions that are accretive to our unitholders and increase the diversity of our revenues.
A more detailed discussion of our financial condition at December 31, 2021 and 2020 and operating results for the years ended December 31, 2021 and 2020 is presented in the following sections. Discussions of year-over-year comparisons for 2020 and 2019 can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2020.
RESULTS OF OPERATIONS (Unaudited)
Income, Distributable Cash Flow and Volumes
The following tables present income, distributable cash flow and volume information for the years ended December 31, 2018, 20172021, 2020 and 2016. These results have been adjusted2019.
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | Change from |
| | | 2021 | | 2020 | | 2020 |
| | | (In thousands, except per unit data) |
| Revenues | | | | | | |
| Pipelines: | | | | | | |
| Affiliates—refined product pipelines | | $ | 69,351 | | | $ | 73,571 | | | $ | (4,220) | |
| Affiliates—intermediate pipelines | | 30,101 | | | 30,023 | | | 78 | |
| Affiliates—crude pipelines | | 77,768 | | | 80,026 | | | (2,258) | |
| | 177,220 | | | 183,620 | | | (6,400) | |
| Third parties—refined product pipelines | | 38,064 | | | 43,371 | | | (5,307) | |
| Third parties—crude pipelines | | 47,826 | | | 38,843 | | | 8,983 | |
| | 263,110 | | | 265,834 | | | (2,724) | |
| Terminals, tanks and loading racks: | | | | | | |
| Affiliates | | 124,511 | | | 135,867 | | | (11,356) | |
| Third parties | | 17,756 | | | 15,825 | | | 1,931 | |
| | 142,267 | | | 151,692 | | | (9,425) | |
| | | | | | |
| Affiliates—refinery processing units | | 89,118 | | | 80,322 | | | 8,796 | |
| | | | | | |
| Total revenues | | 494,495 | | | 497,848 | | | (3,353) | |
| Operating costs and expenses | | | | | | |
| Operations (exclusive of depreciation and amortization) | | 170,524 | | | 147,692 | | | 22,832 | |
| Depreciation and amortization | | 93,800 | | | 99,578 | | | (5,778) | |
| General and administrative | | 12,637 | | | 9,989 | | | 2,648 | |
| Goodwill impairment | | 11,034 | | | 35,653 | | | (24,619) | |
| | 287,995 | | | 292,912 | | | (4,917) | |
| Operating income | | 206,500 | | | 204,936 | | | 1,564 | |
| Other income (expense): | | | | | | |
| Equity in earnings of equity method investments | | 12,432 | | | 6,647 | | | 5,785 | |
| Interest expense, including amortization | | (53,818) | | | (59,424) | | | 5,606 | |
| Interest income | | 29,925 | | | 10,621 | | | 19,304 | |
| Loss on early extinguishment of debt | | — | | | (25,915) | | | 25,915 | |
| Gain on sales-type leases | | 24,677 | | | 33,834 | | | (9,157) | |
| Gain on sale of assets and other | | 6,179 | | | 8,691 | | | (2,512) | |
| | | | | | |
| | 19,395 | | | (25,546) | | | 44,941 | |
| Income before income taxes | | 225,895 | | | 179,390 | | | 46,505 | |
| State income tax expense | | (32) | | | (167) | | | 135 | |
| Net income | | 225,863 | | | 179,223 | | | 46,640 | |
| | | | | | |
| Allocation of net income attributable to noncontrolling interests | | (10,917) | | | (8,740) | | | (2,177) | |
| Net income attributable to the partners | | 214,946 | | | 170,483 | | | 44,463 | |
| | | | | | |
| | | | | | |
| Limited partners’ earnings per unit—basic and diluted | | $ | 2.03 | | | $ | 1.61 | | | $ | 0.42 | |
| Weighted average limited partners’ units outstanding | | 105,440 | | | 105,440 | | | — | |
EBITDA (1) | | $ | 332,671 | | | $ | 319,031 | | | $ | 13,640 | |
Adjusted EBITDA (1) | | $ | 339,203 | | | $ | 345,978 | | | $ | (6,775) | |
Distributable cash flow (2) | | $ | 269,805 | | | $ | 283,057 | | | $ | (13,252) | |
| | | | | | |
| Volumes (bpd) | | | | | | |
| Pipelines: | | | | | | |
| Affiliates—refined product pipelines | | 108,767 | | | 115,827 | | | (7,060) | |
| Affiliates—intermediate pipelines | | 125,225 | | | 137,053 | | | (11,828) | |
| Affiliates—crude pipelines | | 279,514 | | | 277,025 | | | 2,489 | |
| | 513,506 | | | 529,905 | | | (16,399) | |
| Third parties—refined product pipelines | | 49,356 | | | 45,685 | | | 3,671 | |
| Third parties—crude pipelines | | 129,084 | | | 110,691 | | | 18,393 | |
| | 691,946 | | | 686,281 | | | 5,665 | |
| Terminals and loading racks: | | | | | | |
| Affiliates | | 391,698 | | | 393,300 | | | (1,602) | |
| Third parties | | 51,184 | | | 48,909 | | | 2,275 | |
| | 442,882 | | | 442,209 | | | 673 | |
| | | | | | |
| Affiliates—refinery processing units | | 69,628 | | | 61,416 | | | 8,212 | |
| | | | | | |
| Total for pipelines, terminals and refinery processing unit assets (bpd) | | 1,204,456 | | | 1,189,906 | | | 14,550 | |
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | | Change from |
| | | 2020 | | 2019 | | 2019 |
| | | (In thousands, except per unit data) |
| Revenues | | | | | | |
| Pipelines: | | | | | | |
| Affiliates—refined product pipelines | | $ | 73,571 | | | $ | 77,443 | | | $ | (3,872) | |
| Affiliates—intermediate pipelines | | 30,023 | | | 29,558 | | | 465 | |
| Affiliates—crude pipelines | | 80,026 | | | 85,415 | | | (5,389) | |
| | 183,620 | | | 192,416 | | | (8,796) | |
| Third parties—refined product pipelines | | 43,371 | | | 54,914 | | | (11,543) | |
| Third parties—crude pipelines | | 38,843 | | | 45,301 | | | (6,458) | |
| | 265,834 | | | 292,631 | | | (26,797) | |
| Terminals, tanks and loading racks: | | | | | | |
| Affiliates | | 135,867 | | | 139,655 | | | (3,788) | |
| Third parties | | 15,825 | | | 20,812 | | | (4,987) | |
| | 151,692 | | | 160,467 | | | (8,775) | |
| | | | | | |
| Affiliates—refinery processing units | | 80,322 | | | 79,679 | | | 643 | |
| | | | | | |
| Total revenues | | 497,848 | | | 532,777 | | | (34,929) | |
| Operating costs and expenses | | | | | | |
| Operations (exclusive of depreciation and amortization) | | 147,692 | | | 161,996 | | | (14,304) | |
| Depreciation and amortization | | 99,578 | | | 96,705 | | | 2,873 | |
| General and administrative | | 9,989 | | | 10,251 | | | (262) | |
| Goodwill impairment | | 35,653 | | | — | | | 35,653 | |
| | 292,912 | | | 268,952 | | | 23,960 | |
| Operating income | | 204,936 | | | 263,825 | | | (58,889) | |
| Other income (expense): | | | | | | |
| Equity in earnings of equity method investments | | 6,647 | | | 5,180 | | | 1,467 | |
| Interest expense, including amortization | | (59,424) | | | (76,823) | | | 17,399 | |
| Interest income | | 10,621 | | | 5,517 | | | 5,104 | |
| Loss on early extinguishment of debt | | (25,915) | | | — | | | (25,915) | |
| Gain on sales-type leases | | 33,834 | | | 35,166 | | | (1,332) | |
| Gain on sale of assets and other | | 8,691 | | | 272 | | | 8,419 | |
| | | | | | |
| | (25,546) | | | (30,688) | | | 5,142 | |
| Income before income taxes | | 179,390 | | | 233,137 | | | (53,747) | |
| State income tax expense | | (167) | | | (41) | | | (126) | |
| Net income | | 179,223 | | | 233,096 | | | (53,873) | |
| Allocation of net income attributable to noncontrolling interests | | (8,740) | | | (8,212) | | | (528) | |
| Net income attributable to the partners | | 170,483 | | | 224,884 | | | (54,401) | |
| Limited partners’ earnings per unit—basic and diluted | | $ | 1.61 | | | $ | 2.13 | | | $ | (0.52) | |
| Weighted average limited partners’ units outstanding | | 105,440 | | | 105,440 | | | — | |
EBITDA (1) | | $ | 319,031 | | | $ | 392,936 | | | $ | (73,905) | |
Adjusted EBITDA (1) | | $ | 345,978 | | | $ | 359,308 | | | $ | (13,330) | |
Distributable cash flow (2) | | $ | 283,057 | | | $ | 271,431 | | | $ | 11,626 | |
| | | | | | |
| Volumes (bpd) | | | | | | |
| Pipelines: | | | | | | |
| Affiliates—refined product pipelines | | 115,827 | | | 123,986 | | | (8,159) | |
| Affiliates—intermediate pipelines | | 137,053 | | | 140,585 | | | (3,532) | |
| Affiliates—crude pipelines | | 277,025 | | | 368,699 | | | (91,674) | |
| | 529,905 | | | 633,270 | | | (103,365) | |
| Third parties—refined product pipelines | | 45,685 | | | 71,545 | | | (25,860) | |
| Third parties—crude pipelines | | 110,691 | | | 132,507 | | | (21,816) | |
| | 686,281 | | | 837,322 | | | (151,041) | |
| Terminals and loading racks: | | | | | | |
| Affiliates | | 393,300 | | | 422,119 | | | (28,819) | |
| Third parties | | 48,909 | | | 61,054 | | | (12,145) | |
| | 442,209 | | | 483,173 | | | (40,964) | |
| | | | | | |
| Affiliates—refinery processing units | | 61,416 | | | 68,780 | | | (7,364) | |
| | | | | | |
| Total for pipelines, terminals and refinery processing unit assets (bpd) | | 1,189,906 | | | 1,389,275 | | | (199,369) | |
(1)Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to include the combined resultspartners plus (i) interest expense, net of interest income, (ii) state income tax and (iii) depreciation and amortization. Adjusted EBITDA is calculated as EBITDA plus (i) loss on early extinguishment of debt, (ii) goodwill impairment, (iii) pipeline tariffs not included in revenues due to impacts from lease accounting for certain pipeline tariffs minus (iv) gain on sales-type leases, (v) gain on significant asset sales, (vi) HEP's pro-rata share of gain on business interruption settlement and (vii) pipeline lease payments not included in operating costs and expenses. Portions of our Predecessor. See Notes 1 and 2minimum guaranteed pipeline tariffs for assets subject to sales-type lease accounting are recorded as interest income with the remaining amounts recorded as a reduction in net investment in leases. These pipeline tariffs were previously recorded as revenues prior to the Consolidated Financial Statements of HEP for discussionrenewal of the throughput agreement, which triggered sales-type lease accounting. Similarly, certain pipeline lease payments were previously recorded as operating costs and expenses, but the underlying lease was reclassified from an operating lease to a financing lease, and these payments are now recorded as interest expense and reductions in the lease liability. EBITDA and Adjusted EBITDA are not calculations based upon generally accepted accounting principles (“GAAP”). However, the amounts included in the EBITDA and Adjusted EBITDA calculations are derived from amounts included in our consolidated financial statements. EBITDA and Adjusted EBITDA should not be considered as alternatives to net income attributable to the partners or operating income, as indications of our operating performance or as alternatives to operating cash flow as a measure of liquidity. EBITDA and Adjusted EBITDA are not necessarily comparable to similarly titled measures of other companies. EBITDA and Adjusted EBITDA are presented here because they are widely used financial indicators used by investors and analysts to measure performance. EBITDA and Adjusted EBITDA are also used by our management for internal analysis and as a basis for compliance with financial covenants.
(2)Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts presented in our consolidated financial statements, with the general exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also used by management for internal analysis and for our performance units. We believe that this presentation.measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2021 | | 2020 | | 2019 | | | | |
| | | (In thousands) |
| Net income attributable to the partners | | $ | 214,946 | | | $ | 170,483 | | | $ | 224,884 | | | | | |
| Add (subtract): | | | | | | | | | | |
| Interest expense | | 53,818 | | | 59,424 | | | 76,823 | | | | | |
| Interest income | | (29,925) | | | (10,621) | | | (5,517) | | | | | |
| State income tax expense | | 32 | | | 167 | | | 41 | | | | | |
| Depreciation and amortization | | 93,800 | | | 99,578 | | | 96,705 | | | | | |
| | | | | | | | | | |
| EBITDA | | 332,671 | | | 319,031 | | | 392,936 | | | | | |
| Loss on early extinguishment of debt | | — | | | 25,915 | | | — | | | | | |
| Gain on sales-type lease | | (24,677) | | | (33,834) | | | (35,166) | | | | | |
| Gain on significant asset sales | | (5,263) | | | — | | | — | | | | | |
| Goodwill impairment | | 11,034 | | | 35,653 | | | — | | | | | |
| HEP's pro-rata share of gain on business interruption insurance settlement | | — | | | (6,079) | | | — | | | | | |
| Pipeline tariffs not included in revenues | | 31,863 | | | 11,717 | | | 4,750 | | | | | |
| Lease payments not included in operating costs | | (6,425) | | | (6,425) | | | (3,212) | | | | | |
| Adjusted EBITDA | | $ | 339,203 | | | $ | 345,978 | | | $ | 359,308 | | | | | |
|
| | | | | | | | | | | | |
| | | Years Ended December 31, | | Change from |
| | | 2018 | | 2017 | | 2017 |
| | | (In thousands, except per unit data) |
| Revenues | | | | | | |
| Pipelines: | | | | | | |
| Affiliates—refined product pipelines | | $ | 82,998 |
| | $ | 80,030 |
| | $ | 2,968 |
|
| Affiliates—intermediate pipelines | | 29,639 |
| | 28,732 |
| | 907 |
|
| Affiliates—crude pipelines | | 79,741 |
| | 65,960 |
| | 13,781 |
|
| | | 192,378 |
| | 174,722 |
| | 17,656 |
|
| Third parties—refined product pipelines | | 54,524 |
| | 52,379 |
| | 2,145 |
|
| Third parties—crude pipelines | | 36,605 |
| | 7,939 |
| | 28,666 |
|
| | | 283,507 |
| | 235,040 |
| | 48,467 |
|
| Terminals, tanks and loading racks: | | | | | | |
| Affiliates | | 130,251 |
| | 125,510 |
| | 4,741 |
|
| Third parties | | 17,283 |
| | 16,908 |
| | 375 |
|
| | | 147,534 |
| | 142,418 |
| | 5,116 |
|
| | | | | | | |
| Affiliates—refinery processing units | | 75,179 |
| | 76,904 |
| | (1,725 | ) |
| | | | | | | |
| Total revenues | | 506,220 |
| | 454,362 |
| | 51,858 |
|
| Operating costs and expenses | | | | | | |
| Operations (exclusive of depreciation and amortization) | | 146,430 |
| | 137,605 |
| | 8,825 |
|
| Depreciation and amortization | | 98,492 |
| | 79,278 |
| | 19,214 |
|
| General and administrative | | 11,040 |
| | 14,323 |
| | (3,283 | ) |
| | | 255,962 |
| | 231,206 |
| | 24,756 |
|
| Operating income | | 250,258 |
| | 223,156 |
| | 27,102 |
|
| Other income (expense): | | | | | | |
| Equity in earnings of equity method investments | | 5,825 |
| | 12,510 |
| | (6,685 | ) |
| Interest expense, including amortization | | (71,899 | ) | | (58,448 | ) | | (13,451 | ) |
| Interest income | | 2,108 |
| | 491 |
| | 1,617 |
|
| Loss on early extinguishment of debt | | — |
| | (12,225 | ) | | 12,225 |
|
| Remeasurement gain on preexisting equity interests | | — |
| | 36,254 |
| | (36,254 | ) |
| Gain on sale of assets and other | | 121 |
| | 422 |
| | (301 | ) |
| | | (63,845 | ) | | (20,996 | ) | | (42,849 | ) |
| Income before income taxes | | 186,413 |
| | 202,160 |
| | (15,747 | ) |
| State income tax expense | | (26 | ) | | (249 | ) | | 223 |
|
| Net income | | 186,387 |
| | 201,911 |
| | (15,524 | ) |
| Allocation of net income attributable to noncontrolling interests | | (7,540 | ) | | (6,871 | ) | | (669 | ) |
| Net income attributable to the partners | | 178,847 |
| | 195,040 |
| | (16,193 | ) |
General partner interest in net income attributable to the partners (1) | | — |
| | (35,047 | ) | | 35,047 |
|
| Limited partners’ interest in net income | | $ | 178,847 |
| | $ | 159,993 |
| | $ | 18,854 |
|
Limited partners’ earnings per unit—basic and diluted (1) | | $ | 1.70 |
| | $ | 2.28 |
| | $ | (0.58 | ) |
| Weighted average limited partners’ units outstanding | | 105,042 |
| | 70,291 |
| | 34,751 |
|
EBITDA (2) | | $ | 347,156 |
| | $ | 332,524 |
| | $ | 14,632 |
|
Distributable cash flow (3) | | $ | 265,087 |
| | $ | 242,955 |
| | $ | 22,132 |
|
| | | | | | | |
| Volumes (bpd) | | | | | | |
| Pipelines: | | | | | | |
| Affiliates—refined product pipelines | | 127,865 |
| | 133,822 |
| | (5,957 | ) |
| Affiliates—intermediate pipelines | | 144,537 |
| | 141,601 |
| | 2,936 |
|
| Affiliates—crude pipelines | | 349,686 |
| | 281,093 |
| | 68,593 |
|
| | | 622,088 |
| | 556,516 |
| | 65,572 |
|
| Third parties—refined product pipelines | | 71,784 |
| | 78,013 |
| | (6,229 | ) |
| Third parties—crude pipelines | | 115,933 |
| | 21,834 |
| | 94,099 |
|
| | | 809,805 |
| | 656,363 |
| | 153,442 |
|
| Terminals and loading racks: | | | | | |
|
| Affiliates | | 413,525 |
| | 428,001 |
| | (14,476 | ) |
| Third parties | | 61,367 |
| | 68,687 |
| | (7,320 | ) |
| | | 474,892 |
| | 496,688 |
| | (21,796 | ) |
| | | | | | | |
| Affiliates—refinery processing units | | 62,787 |
| | 63,572 |
| | (785 | ) |
| | | | | | | |
| Total for pipelines, terminals and refinery processing unit assets (bpd) | | 1,347,484 |
| | 1,216,623 |
| | 130,861 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2021 | | 2020 | | 2019 | | | | |
| | | (In thousands) |
| Net income attributable to the partners | | $ | 214,946 | | | $ | 170,483 | | | $ | 224,884 | | | | | |
| Add (subtract): | | | | | | | | | | |
| Depreciation and amortization | | 93,800 | | | 99,578 | | | 96,705 | | | | | |
| | | | | | | | | | |
| Amortization of discount and deferred debt issuance costs | | 3,757 | | | 3,319 | | | 3,080 | | | | | |
| Loss on early extinguishment of debt | | — | | | 25,915 | | | — | | | | | |
| Revenue recognized (greater) less than customer billings | | 3,355 | | | (743) | | | (2,433) | | | | | |
Maintenance capital expenditures (3) | | (15,293) | | | (8,643) | | | (6,471) | | | | | |
| | | | | | | | | | |
| Increase (decrease) in environmental liability | | (661) | | | (1,020) | | | (741) | | | | | |
| Increase (decrease) in reimbursable deferred revenue | | (13,494) | | | (12,175) | | | (8,036) | | | | | |
| Gain on sales-type lease | | (24,677) | | | (33,834) | | | (35,166) | | | | | |
| Gain on significant asset sales | | (5,263) | | | — | | | — | | | | | |
| Goodwill impairment | | 11,034 | | | 35,653 | | | — | | | | | |
| Other | | 2,301 | | | 4,524 | | | (391) | | | | | |
| | | | | | | | | | |
| Distributable cash flow | | $ | 269,805 | | | $ | 283,057 | | | $ | 271,431 | | | | | |
(3)Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations.
|
| | | | | | | | | | | | |
| | | Years Ended December 31, | | Change from |
| | | 2017 | | 2016 | | 2016 |
| | | (In thousands, except per unit data) |
| Revenues | | | | | | |
| Pipelines: | | | | | | |
| Affiliates—refined product pipelines | | $ | 80,030 |
| | $ | 83,102 |
| | $ | (3,072 | ) |
| Affiliates—intermediate pipelines | | 28,732 |
| | 26,996 |
| | 1,736 |
|
| Affiliates—crude pipelines | | 65,960 |
| | 70,341 |
| | (4,381 | ) |
| | | 174,722 |
| | 180,439 |
| | (5,717 | ) |
| Third parties—refined product pipelines | | 52,379 |
| | 52,195 |
| | 184 |
|
| Third parties—crude pipelines | | 7,939 |
| | — |
| | 7,939 |
|
| | | 235,040 |
| | 232,634 |
| | 2,406 |
|
| Terminals, tanks and loading racks: | | | | | | |
| Affiliates | | 125,510 |
| | 119,633 |
| | 5,877 |
|
| Third parties | | 16,908 |
| | 16,732 |
| | 176 |
|
| | | 142,418 |
| | 136,365 |
| | 6,053 |
|
| | | | | | | |
| Affiliates—refinery processing units | | 76,904 |
| | 33,044 |
| | 43,860 |
|
| | | | | | | |
| Total revenues | | 454,362 |
| | 402,043 |
| | 52,319 |
|
| Operating costs and expenses | | | | | | |
| Operations (exclusive of depreciation and amortization) | | 137,605 |
| | 123,986 |
| | 13,619 |
|
| Depreciation and amortization | | 79,278 |
| | 70,428 |
| | 8,850 |
|
| General and administrative | | 14,323 |
| | 12,532 |
| | 1,791 |
|
| | | 231,206 |
| | 206,946 |
| | 24,260 |
|
| Operating income | | 223,156 |
| | 195,097 |
| | 28,059 |
|
| Other income (expense): | | | | | | |
| Equity in earnings of equity method investments | | 12,510 |
| | 14,213 |
| | (1,703 | ) |
| Interest expense, including amortization | | (58,448 | ) | | (52,552 | ) | | (5,896 | ) |
| Interest income | | 491 |
| | 440 |
| | 51 |
|
| Loss on early extinguishment of debt | | (12,225 | ) | | — |
| | (12,225 | ) |
| Remeasurement gain on preexisting equity interests | | 36,254 |
| | — |
| | 36,254 |
|
| Gain on sale of assets and other | | 422 |
| | 677 |
| | (255 | ) |
| | | (20,996 | ) | | (37,222 | ) | | 16,226 |
|
| Income before income taxes | | 202,160 |
| | 157,875 |
| | 44,285 |
|
| State income tax expense | | (249 | ) | | (285 | ) | | 36 |
|
| Net income | | 201,911 |
| | 157,590 |
| | 44,321 |
|
| Allocation of net loss attributable to Predecessor | | — |
| | 10,657 |
| | (10,657 | ) |
| Allocation of net income attributable to noncontrolling interests | | (6,871 | ) | | (10,006 | ) | | 3,135 |
|
| Net income attributable to the partners | | 195,040 |
| | 158,241 |
| | 36,799 |
|
General partner interest in net income attributable to the partners (1) | | (35,047 | ) | | (57,173 | ) | | 22,126 |
|
| Limited partners’ interest in net income | | $ | 159,993 |
| | $ | 101,068 |
| | $ | 58,925 |
|
Limited partners’ earnings per unit—basic and diluted (1) | | $ | 2.28 |
| | $ | 1.69 |
| | $ | 0.59 |
|
| Weighted average limited partners’ units outstanding | | 70,291 |
| | 59,872 |
| | 10,419 |
|
EBITDA (2) | | $ | 332,524 |
| | $ | 277,545 |
| | $ | 54,979 |
|
Distributable cash flow (3) | | $ | 242,955 |
| | $ | 218,810 |
| | $ | 24,145 |
|
| | | | | | | |
| Volumes (bpd) | | | | | | |
| Pipelines: | | | | | | |
| Affiliates—refined product pipelines | | 133,822 |
| | 128,140 |
| | 5,682 |
|
| Affiliates—intermediate pipelines | | 141,601 |
| | 137,381 |
| | 4,220 |
|
| Affiliates—crude pipelines | | 281,093 |
| | 277,241 |
| | 3,852 |
|
| | | 556,516 |
| | 542,762 |
| | 13,754 |
|
| Third parties—refined product pipelines | | 78,013 |
| | 75,909 |
| | 2,104 |
|
| Third parties—crude pipelines | | 21,834 |
| | — |
| | 21,834 |
|
| | | 656,363 |
| | 618,671 |
| | 37,692 |
|
| Terminals and loading racks: | | | | | |
|
| Affiliates | | 428,001 |
| | 413,487 |
| | 14,514 |
|
| Third parties | | 68,687 |
| | 72,342 |
| | (3,655 | ) |
| | | 496,688 |
| | 485,829 |
| | 10,859 |
|
| | | | | | | |
| Affiliates—refinery processing units | | 63,572 |
| | 51,778 |
| | 11,794 |
|
| | | | | | | |
| Total for pipelines, terminals and refinery processing unit assets (bpd) | | 1,216,623 |
| | 1,156,278 |
| | 60,345 |
|
| | | | | | | | | | | | | | |
| | December 31, |
| | 2021 | | 2020 |
| | (In thousands) |
| Balance Sheet Data | | | | |
| Cash and cash equivalents | | $ | 14,381 | | | $ | 21,990 | |
| Working capital | | $ | 17,461 | | | $ | 14,247 | |
| Total assets | | $ | 2,165,867 | | | $ | 2,167,565 | |
| Long-term debt | | $ | 1,333,049 | | | $ | 1,405,603 | |
| Partners' equity | | $ | 443,017 | | | $ | 379,292 | |
| |
(1) | Net income attributable to the partners is allocated between limited partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner included incentive distributions that were declared subsequent to quarter end. After the amount of incentive distributions and other priority allocations are allocated to the general partner, the remaining net income attributable to the partners is allocated to the partners based on their weighted average ownership percentage during the period. As a result of the IDR Restructuring Transaction, no IDR or general partner distributions were made after October 31, 2017. See "Business and Properties - Overview." |
| |
(2) | Earnings before interest, taxes, depreciation and amortization (“EBITDA”) is calculated as net income attributable to the partners plus (i) interest expense, net of interest income (ii) state income tax and (iii) depreciation and amortization excluding Predecessor. EBITDA is not a calculation based upon generally accepted accounting principles (“GAAP”). However, the amounts included in the EBITDA calculation are derived from amounts included in our consolidated financial statements. EBITDA should not be considered as an alternative to net income attributable to Holly Energy Partners or operating income, as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. EBITDA is not necessarily comparable to similarly titled measures of other companies. EBITDA is presented here because it is a widely used financial indicator used by investors and analysts to measure performance. EBITDA is also used by our management for internal analysis and as a basis for compliance with financial covenants. See our calculation of EBITDA under Item 6, “Selected Financial Data.” |
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(3) | Distributable cash flow is not a calculation based upon GAAP. However, the amounts included in the calculation are derived from amounts presented in our consolidated financial statements, with the general exception of maintenance capital expenditures. Distributable cash flow should not be considered in isolation or as an alternative to net income or operating income as an indication of our operating performance or as an alternative to operating cash flow as a measure of liquidity. Distributable cash flow is not necessarily comparable to similarly titled measures of other companies. Distributable cash flow is presented here because it is a widely accepted financial indicator used by investors to compare partnership performance. It is also used by management for internal analysis and for our performance units. We believe that this measure provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating. See our calculation of distributable cash flow under Item 6, “Selected Financial Data.” |
Results of Operations — Year Ended December 31, 20182021 Compared with Year Ended December 31, 20172020
Summary
Net income attributable to the partners for the year ended December 31, 2018,2021, was $178.8$214.9 million, a $16.2$44.5 million decreaseincrease compared to the year ended December 31, 2017. The decrease in earnings was primarily due2020. Results for the year ended December 31, 2021 reflect special items that collectively increased net income attributable to HEP by a total of $18.9 million. These items include a gain on sales type leases of $24.7 million, a gain on significant asset sales of $5.3 million and a goodwill impairment charge of $11.0 million related to our Cheyenne reporting unit. In addition, net income attributable to HEP for the year ended December 31, 2020 included a goodwill impairment charge of $35.7 million related to our Cheyenne reporting unit, a charge of $25.9 million related to the recognitionearly redemption of our previously outstanding $500 million aggregate principal amount of 6% Senior Notes due in 2024, a $36.3gain on sales-type leases of $33.8 million remeasurementand a $6.1 million gain related to our acquisitionHEP's pro-rata share of the remaining interests in SLC Pipeline and Frontier Aspen in the fourth quarter of 2017.a business interruption insurance claim settlement resulting from a loss at HFC's Woods Cross refinery. Excluding this remeasurement gain,these items, net income attributable to the partners increased $20.1 million primarily due to higher pipeline throughputs and revenues as well as increased earnings related to our acquisition of the remaining interests in SLC Pipeline and Frontier Aspen in the fourth quarter of 2017, which were partially offset by higher interest expense.
Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Revenues for the year ended December 31, 2018, include the recognition of $3.32021 was $196.0 million of prior shortfalls billed($1.86 per basic and diluted limited partner unit) compared to shippers$192.1 million ($1.82 per basic and diluted limited partner unit) in 2017. As of December 31, 2018, deferred revenue on our consolidated balance sheet related to shortfalls billed was $1.8 million.2020.
Revenues
Revenues for the year ended December 31, 2018,2021, were $506.2$494.5 million, a $51.9$3.4 million increasedecrease compared to the same period in 2017.2020. The increasedecrease was primarilymainly attributable to lower on-going revenues from our acquisitionCheyenne assets as a result of the remaining interests in SLC Pipeline and Frontier Aspen inconversion of the fourth quarter of 2017 and the turnaround atHFC Cheyenne refinery to renewable diesel production, lower volumes on our product pipelines servicing HFC's Navajo refinery and Delek's Big Spring refinery, and recording certain tariffs and fees as interest income under sales-type lease accounting that were previously recorded as revenue in the first quarteryear ended December 31, 2020, partially offset by higher revenues from our crude pipeline systems in Wyoming and Utah and our Woods Cross and El Dorado refinery processing units mainly due to higher recovery of 2017.natural gas costs.
Revenues from our refined product pipelines were $137.5$107.4 million, an increasea decrease of $5.1$9.5 million, on shipments averaging 199.6158.1 mbpd compared to 211.8161.5 mbpd for the year ended December 31, 2017.2020. The volume decrease wasand revenue decreases were mainly due to lower volumes on pipelines servicing HFC's Woods Cross refinery, which had lower throughput due to operational issues at the refinery beginning in the first quarter of 2018. These decreases were partially offset by higher volumes on our product pipelines in New Mexico due to the turnaround at HFC's Navajo refinery in the first quarter of 2017. Revenue increased as a result of the higher volumes on the New Mexico product pipelines and remained relatively consistent around pipelines servicing HFC's Woods Cross refinery due to contractual minimum volume commitments and tariff escalators.
Delek's Big Spring refinery.
Revenues from our intermediate pipelines were $29.6$30.1 million, an increase of $0.9$0.1 million, on shipments averaging 144.5125.2 mbpd compared to 141.6137.1 mbpd for the year ended December 31, 2017. These increases were principally2020. The decrease in volumes was mainly due to the turnaround at HFC's Navajo refinery in the first quarter of 2017 and increased production of base oil and lubricants atlower throughputs on our intermediate pipelines servicing HFC's Tulsa refinery.and Navajo refineries while revenue remained relatively constant mainly due to contractual minimum volume guarantees.
Revenues from our crude pipelines were $116.3$125.6 million, an increase of $42.4$6.7 million, on shipments averaging 465.6408.6 mbpd compared to 302.9387.7 mbpd for the year ended December 31, 2017.2020. The increases were mainly attributable to our acquisition of the remaining interests in SLC Pipeline and Frontier Aspen in the fourth quarter of 2017, as well as increased volumes on our crude pipeline systems in New MexicoWyoming and Texas.Utah partially offset by lower volumes on our pipeline systems servicing HFC's Navajo refinery. Volumes also increased due to the addition of volumes on our Cushing Connect Pipeline in Oklahoma which went into service at the end of the third quarter of 2021.
Revenues from terminal, tankage and loading rack fees were $147.5$142.3 million, an increasea decrease of $5.1$9.4 million compared to the year ended December 31, 2017.2020. Refined products and crude oil terminalled in the facilities averaged 474.9442.9 mbpd compared to 496.7442.2 mbpd for the year ended December 31, 2017. Despite the decrease in volume, revenue increased primarily2020. Revenues decreased mainly due to tariff escalatorslower on-going revenues on minimumour Cheyenne assets as a result of the conversion of HFC's Cheyenne refinery to renewable diesel production and recording certain tariffs and fees as interest income under sales-type lease accounting that were previously recorded as revenue commitments.in the year ended December 31, 2020.
Revenues from refinery processing units were $75.2$89.1 million, a decreasean increase of $1.7$8.8 million on throughputs averaging 62.869.6 mbpd compared to 63.661.4 mbpd for the year ended December 31, 2017.2020. The reductionincrease in revenue and volumevolumes was mainly due to an unplanned outage onincreased throughput for both our fluid catalytic cracking unit at HFC's Woods Cross refinery in the fourth quarterand El Dorado processing units. Revenues increased mainly due to higher recovery of 2018.natural gas costs as well as higher throughputs.
Operations Expense
Operations (exclusive(exclusive of depreciation and amortization)amortization) expense for the year ended December 31, 2018,2021, increased by $8.8$22.8 million compared to the year ended December 31, 2017.2020. The increase was primarilymainly due to new operating expenses related to our acquisition of the remaining interestsan increase in SLC Pipelineemployee costs, maintenance costs, pipeline rental costs and Frontier Aspen in the fourth quarter of 2017.natural gas costs.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2018, increased2021, decreased by $19.2$5.8 million compared to the year ended December 31, 2017.2020. The increasedecrease was primarilymainly due to depreciationthe retirements in Cheyenne operations and amortization related to our acquisitionsale of the remaining interests in SLC Pipeline and Frontier Aspen in the fourth quarter of 2017.El Paso 6-inch pipeline assets.
General and Administrative
General and administrative costs for the year ended December 31, 2018, decreased2021, increased by $3.3$2.6 million compared to the year ended December 31, 2017, mainly2020 primarily due to higher legal and consulting costs incurred inrelated to the year ended December 31, 2017, associated with the IDR RestructuringHEP Transaction.
Equity in Earnings of Equity Method Investments
See the summary chart below for a description of our equity in earnings of equity method investments:
| | | | | | | | | | | |
| Years Ended December 31, |
| Equity Method Investment | 2021 | | 2020 |
| (In thousands) |
| Osage Pipe Line Company, LLC | $ | 3,889 | | | $ | 2,416 | |
| Cheyenne Pipeline LLC | 5,008 | | | 2,689 | |
| Cushing Connect Terminal Holdings LLC | 3,535 | | | 1,542 | |
| Total | $ | 12,432 | | | $ | 6,647 | |
|
| | | | | | | |
| | Years Ended December 31, |
| Equity Method Investment | 2018 | | 2017 |
| | (in thousands) |
| SLC Pipeline LLC | $ | — |
| | $ | 2,267 |
|
| Frontier Aspen LLC | — |
| | 4,089 |
|
| Osage Pipe Line Company, LLC | 1,961 |
| | 2,447 |
|
| Cheyenne Pipeline LLC | 3,864 |
| | 3,707 |
|
| Total | $ | 5,825 |
| | $ | 12,510 |
|
Interest Expense
Interest expense for the year ended December 31, 2018,2021, totaled $71.9$53.8 million, an increasea decrease of $13.5$5.6 million compared to the year ended December 31, 2017.2020. The increasedecrease was mainly due to interest expense associated with the private placement of an additional $100 million in aggregate principal amount oflower outstanding balances under our 6% Senior Notes due 2024 completed in the third quarter of 2017, higher average balances outstanding under the Credit Agreement, and market interest rate increases under the Credit Agreement.senior secured revolving credit facility. Our aggregate weighted-average interest rates were 5.1%3.7% and 4.4%3.8% for the years ended December 31, 20182021 and 2017,2020, respectively.
Interest Income
Interest income for the year ended December 31, 2021, totaled $29.9 million, an increase of $19.3 million compared to the year ended December 31, 2020. The increase was due to recording certain tariffs and fees as interest income under sales-type lease accounting that were previously recorded as revenue in 2020 as underlying agreements were classified as sales-type leases when the agreements were modified or renewed. See Note 5 of our consolidated financial statements for further discussion of lease accounting.
State Income Tax
We recorded state income tax expense of $26,000$32,000 and $249,000$167,000 for the years ended December 31, 20182021 and 2017,2020, respectively. All state income tax expense is solely attributable to the Texas margin tax.
ResultsResults of Operations—Year Ended December 31, 20172020 Compared with Year Ended December 31, 20162019
Summary
Net income attributable to the partners for the year ended December 31, 2017,2020, was $195.0$170.5 million, a $36.8$54.4 million million increasedecrease compared to the year ended December 31, 2016. The increase in earnings is primarily due to (a) the Woods Cross refinery processing units acquired in the fourth quarter of 2016, (b) the gain recognized on the acquisition of SLC Pipeline and Frontier Aspen2019. Results for the remeasurementyear ended December 31, 2020 reflect special items that collectively decreased net income attributable to HEP by a total of preexisting equity interests, offset by (c)$21.7 million. These items include a goodwill impairment charge of $35.7 million related to our Cheyenne reporting unit, a charge of $12.2$25.9 million related to the early redemption of our previously outstanding $300$500 million aggregate principal amount of 6.5% senior notes6% Senior Notes due 2020 (the "6.5% Senior Notes")in 2024, a gain on sales type leases of $33.8 million and (d) higher interest expensea $6.1 million gain related to HEP's pro-rata share of $5.9 million.
Our major shippers are obligateda business interruption insurance claim settlement resulting from a loss at HFC's Woods Cross refinery. In addition, net income attributable to make deficiency payments to us if they do not meet their minimum volume shipping obligations. RevenuesHEP for the year ended December 31, 2017, include2019 included a gain on sales-type leases of $35.2 million. Excluding these items, net income attributable to the recognition of $5.6 million of prior shortfalls billed to shippers in 2016. As ofpartners for the year ended December 31, 2017, deferred revenue on our consolidated balance sheet related2020 was $192.1 million ($1.82 per basic and diluted limited partner unit) compared to shortfalls billed was $4.0 million.$189.7 million ($1.80 per basic and diluted limited partner unit) in 2019.
Revenues
Revenues for the year ended December 31, 2017,2020, were $454.4$497.8 million, a $52.3$34.9 million increasedecrease compared to the same period of 2016.2019. The increase is primarily duedecrease was mainly attributable to the $43.5 million of revenue recorded for the Woods Cross processing units acquiredan 18% reduction in the fourth quarter of 2016 as well as revenues from SLC Pipelineoverall crude and Frontier Aspen acquiredproduct pipeline volumes predominantly in the fourth quarter of 2017..our Southwest and Northwest regions.
Revenues from our refined product pipelines were $132.4$116.9 million, a decrease of $2.9$15.4 million, on shipments averaging 211.8161.5 mbpd compared to 204.0195.5 mbpd for the year ended December 31, 2016.2019. The decrease involume and revenue is primarilydecreases were mainly due to lower volumes on product pipelines due to the turnaround atservicing HFC's Navajo refinery, inDelek's Big Spring refinery and our UNEV pipeline largely as a result of demand destruction associated with the first quarter of 2017COVID-19 pandemic as well as a decrease in previously deferred revenues realized. The increase in volumes is primarily duethe recording of certain pipeline tariffs as interest income as the related throughput contract renewals were determined to higher volumes on relatively short pipelines with lower tariff rates.be sales-type leases.
Revenues from our intermediate pipelines were $28.7$30.0 million, an increase of $1.7$0.5 million, on shipments averaging 141.6137.1 mbpd compared to 137.4140.6 mbpd for the year ended December 31, 2016. The increase in revenue is mainly due to higher volumes from pipelines servicing HFC's Navajo refinery after its turnaround in the first quarter of 2017 as well as an increase of $1.5 million in previously deferred revenue realized.2019.
Revenues from our crude pipelines were $73.9$118.9 million, an increasea decrease of $3.6$11.8 million, on shipments averaging 302.9387.7 mbpd compared to 277.2501.2 mbpd for the year ended December 31, 2016. Revenues and2019. The decreases were mainly attributable to decreased volumes increased primarily due to revenues received from the acquisition of the remaining interests in SLC Pipeline and Frontier Aspenon our crude pipeline systems in the fourth quarterPermian Basin, Wyoming and Utah largely as a result of 2017, offset by lower throughput due to HFC's Navajo refinery turnaround indemand destruction associated with the first quarter of 2017.COVID-19 pandemic.
Revenues from terminal, tankage and loading rack fees were $142.4$151.7 million, an increasea decrease of $6.1$8.8 million compared to the year ended December 31, 2016.2019. Refined products and crude oil terminalled in ourthe facilities increased to an average of 496.7averaged 442.2 mbpd compared to 485.8 483.2
mbpd for the year ended December 31, 2016.2019. The revenue and volume and revenue increases aredecreases were mainly due toas a result of demand destruction associated with the COVID-19 pandemic across many of our Tulsa crude tanks acquired on the last day of the first quarter of 2016, higher throughput on the UNEV terminals, and higher reimbursable revenue related to tank inspections and repairs, offset by the transfer of the El Paso terminal to HFC in the first quarter of 2016.facilities.
Revenues from refinery processing units were $76.9$80.3 million, an increase of $43.9 million$0.6 million on throughputs averaging 63.661.4 mbpd compared to 51.868.8 mbpd for 2016.2019. The increasedecrease in revenues and volumes is primarilywas mainly due to thereduced throughput for both our Woods Cross refineryand El Dorado processing units acquired inlargely as a result of demand destruction associated with the fourth quarter of 2016.COVID-19 pandemic. Revenues remained relatively constant due to contractual minimum volume guarantees.
Operations Expense
Operations (exclusive of depreciation and amortization) expense for the year ended December 31, 2017, increased2020, decreased by $13.6$14.3 million compared to the year ended December 31, 2016. 2019. The increasedecrease was primarilymainly due to operatinglower rental expenses, for the Woods Cross refinery processing units acquired in the fourth quarter of 2016.property taxes and variable costs such as electricity and chemicals associated with lower volumes.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2017,2020, increased by $8.9$2.9 million compared to the year ended December 31, 2016.2019. The increase was mainly due to the acceleration of depreciation from the Woods Cross refinery processing units acquired in the fourth quarteron certain of 2016.our Cheyenne tanks.
General and Administrative
General and administrative costs for the year ended December 31, 2017, increased2020, decreased by $1.8$0.3 million compared to the year ended December 31, 2016,2019, mainly due to higherlower legal and consulting costs, offset by decreased employee compensation.expenses.
Equity in Earnings of Equity Method Investments
See the summary chart below for a description of our equity in earnings of equity method investments:
| | | | | | | | | | | |
| Years Ended December 31, |
| Equity Method Investment | 2020 | | 2019 |
| (In thousands) |
| | | |
| | | |
| Osage Pipe Line Company, LLC | 2,416 | | | 1,344 | |
| Cheyenne Pipeline LLC | 2,689 | | | 3,976 | |
| Cushing Connect Terminal Holdings LLC | 1,542 | | | (140) | |
| Total | 6,647 | | | 5,180 | |
|
| | | | | | | |
| | Years Ended December 31, |
| Equity Method Investment | 2017 | | 2016 |
| | (in thousands) |
| SLC Pipeline LLC | $ | 2,267 |
| | $ | 4,508 |
|
| Frontier Aspen LLC | 4,089 |
| | 4,130 |
|
| Osage Pipe Line Company, LLC | 2,447 |
| | 3,250 |
|
| Cheyenne Pipeline LLC | 3,707 |
| | 2,325 |
|
| Total | $ | 12,510 |
| | $ | 14,213 |
|
SLC Pipeline and Frontier Aspen equity earnings for the year ended December 31, 2017 reflect the ten months before we purchased the remaining interests on October 31, 2017. SLC Pipeline and Frontier Aspen operations for November and December 2017 are included in HEP's consolidated results.
Interest Expense
Interest expense for the year ended December 31, 2017,2020, totaled $58.4$59.4 million, an increasea decrease of $5.9$17.4 million compared to the year ended December 31, 2016.2019. The increasedecrease was primarilymainly due to the issuancemarket interest rate decreases under our senior secured revolving credit facility and refinancing our $500 million aggregate principal amount of new 6% senior notes due 2024 to $500 million aggregate principal amount of 5% Senior Notes in July 2016.due 2028. Our aggregate effectiveweighted-average interest rate was 4.4%rates were 3.8% and 4.7%5.4% for the years ended December 31, 20172020 and 2016,2019, respectively.
State Income Tax
We recorded state income tax expense of $249,000$167,000 and $285,00041,000 for the years ended December 31, 20172020 and 2016,2019, respectively. All state income tax expense is solely attributable to the Texas margin tax.
LIQUIDITY AND CAPITAL RESOURCES
Overview
We have a $1.4$1.2 billion senior secured revolving credit facility (the “Credit Agreement”) expiring in July 2022. 2025. The Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. The Credit Agreement is also available to fund letters of credit up to a $50 million sub-limit and it containscontinues to provide for an accordion feature givingthat allows us the ability to increase commitments under the size of the facility byCredit Agreement up to $300 million with additional lender commitments.a maximum amount of $1.7 billion.
During the year ended December 31, 2018,2021, we received advances totaling $337.0$480.5 million and repaid $426.0$554.0 million, resulting in a net decrease of $89.0$73.5 million under the Credit Agreement and an outstanding balance of $923.0$840.0 million at December 31, 2018.2021. As of December 31, 2018,2021, we had no letters of credit outstanding under the Credit Agreement, and the available capacity under the Credit Agreement was $477$360.0 million.
If any particular lender under the Credit Agreement could not honor its commitment, we believe the unused capacity that would be available from the remaining lenders would be sufficient to meet our borrowing needs. Additionally, we review publicly available information on the lenders in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the Credit Agreement. We do not expect to experience any difficulty in the lenders’ ability to honor their respective commitments, and if it were to become necessary, we believe there would be alternative lenders or options available.
On January 25, 2018,February 4, 2020, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase inclosed a private placement 3,700,000 common units representing limited partnership interests,of $500 million in aggregate principal amount of 5% senior unsecured notes due in 2028 (the “5% Senior Notes”). On February 5, 2020, we redeemed the existing $500 million 6% Senior Notes at a priceredemption cost of $29.73 per common unit. The private placement closed on February 6, 2018,$522.5 million, at which time we recognized a $25.9 million early extinguishment loss consisting of a $22.5 million debt redemption premium and we receivedunamortized financing costs of $3.4 million. We funded the $522.5 million redemption with proceeds from the issuance of approximately $110 million, which were used to repay indebtednessour 5% Senior Notes and borrowings under theour Credit Agreement. After this common unit issuance, HFC owns a 57% limited partner interest in us.
We have a continuous offering program under which we may issue and sell common units from time to time, representing limited partner interests, up to an aggregate gross sales amount of $200 million. As of December 31, 2018,2021, HEP hashad issued 2,413,153 units under this program, providing $82.3 million in gross proceeds. We intend to use the net proceeds for general partnership purposes, which may include funding working capital, repayment of debt, acquisitions and capital expenditures.
On October 31, 2017, we closed on an equity restructuring transaction with HEP Logistics, a wholly-owned subsidiary of HFC and the general partner of HEP, pursuant to which the incentive distribution rights held by HEP Logistics were canceled, and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP. In consideration,
we issued 37,250,000 of our common units to HEP Logistics. In addition, HEP Logistics agreed to waive $2.5 million of limited partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration were eligible to receive distributions.
On September 22, 2017, we closed a private placement of an additional $100 million in aggregate principal of our 6.0% Senior Notes for a combined aggregate principal amount outstanding of $500 million maturing in 2024. The proceeds were used to repay indebtedness outstanding under the Credit Agreement.
On January 4, 2017, we redeemed the $300 million aggregate principal amount of our 6.5% Senior Notes at a redemption cost of $309.8 million, at which time we recognized a $12.2 million early extinguishment loss. We funded the redemption with borrowings under our Credit Agreement.
Under our registration statement filed with the SECSecurities and Exchange Commission (“SEC”) using a “shelf” registration process, we currently have the authority to raise up to $2.0 billion less amounts issued under the $200 million continuous offering program, by offering securities, through one or more prospectus supplements that would describe, among other things, the specific amounts, prices and terms of any securities offered and how the proceeds would be used. Any proceeds from the sale of securities wouldare expected to be used for general business purposes, which may include, among other things, funding acquisitions of assets or businesses, working capital, capital expenditures, investments in subsidiaries, the retirement of existing debt and/or the repurchase of common units or other securities.
We believe our current sources of liquidity, including cash balances, future internally generated funds, and funds available under the Credit Agreement, as well as our access to additional bank financing, and public or private capital markets, will provide sufficient resources to meet our working capital liquidity, capital expenditure and quarterly distribution needs for the foreseeable future.future, including funding the cash portion of the HEP Transaction. Future securities issuances, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.
In February, May, August and November 2018,2021, we paid regular quarterly cash distributions of $0.6500, $0.6550, $0.6600$0.3500, $0.3500, $0.3500 and $0.6650,$0.3500, respectively, on all units in an aggregate amount of $265.0$149.4 million. In February 2019,2022, we paid a regular quarterly cash distribution of $0.6675$0.3500 on all units in an aggregate amount of $68.0 million after deducting HEP Logistics' waiver of $2.5 million of limited partner cash distributions.$37.0 million.
Cash and cash equivalents decreased by $4.7$7.6 million during the year ended December 31, 2018.2021. The cash flows provided by operating activities of $295.2$294.1 million were less than the cash flows used for investing and financing activities of $52.3$78.5 million and $247.6$223.2 million, respectively. Working capital decreasedincreased by $10.3$3.2 million to a surplus of $8.6$17.5 million at December 31, 20182021 from a surplus of $18.9$14.2 million at December 31, 2017.2020.
Cash Flows—Operating Activities
Year Ended December 31, 20182021 Compared with Year Ended December 31, 20172020
Cash flows provided by operating activities increaseddecreased by $56.7$21.5 million from $238.5$315.6 million for the year ended December 31, 2017,2020, to $295.2$294.1 million for the year ended December 31, 2018. 2021. This increasedecrease was mainly due principally to higher receipts from customerspayments for operating expenses partially offset by higher cash receipts from customers and lower payments for interest and operating expenses in the year ended December 31, 2018,2021, as compared to the prior year. The increase in customer receipts was primarily attributable to our acquisition of the remaining interests in SLC Pipeline and Frontier Aspen in the fourth quarter of 2017.
Year Ended December 31, 20172020 Compared with Year Ended December 31, 20162019
Cash flows from operating activities decreasedincreased by $5.1$18.6 million from $243.5$297.1 million for the year ended December 31, 2016,2019, to $238.5$315.6 million for the year ended December 31, 2017. 2020. This decreaseincrease was mainly due principally to higherlower payments for interest and operating expenses partially offset by increasedlower cash receipts from customers in the year ended December 31, 2017,2020, as compared to the prior year.
Cash Flows—Investing Activities
Year Ended December 31, 20182021 Compared with Year Ended December 31, 2017
Cash flows used for investing activities decreased by $233.9 million from $286.3 million for the year ended December 31, 2017, to $52.3 million for the year ended December 31, 2018. During the years ended December 31, 2018 and 2017, we invested $47.3 million and $44.8 million in additions to properties and equipment, respectively. During the year ended December 31, 2018, we acquired businesses and assets for $5.1 million. Additionally, we acquired the remaining 75% interest in SLC Pipeline and 50% interest in Frontier Aspen for $245.4 million in October 2017.
Year Ended December 31, 2017 Compared with Year Ended December 31, 20162020
Cash flows used for investing activities increased by $143.2$18.7 million from $143.0$59.8 million for the year ended December 31, 2016,2020, to $286.3$78.5 million for the year ended December 31, 2017.2021. During the years ended December 31, 20172021 and 2016,2020, we invested $44.8$90.0 million and $59.7$59.3 million, respectively, in additions to properties and equipment, respectively. We acquiredequipment. In addition, we received proceeds from sales of assets of $7.4 million during the remaining 75% interestyear ended December 31, 2021.
Year Ended December 31, 2020 Compared with Year Ended December 31, 2019
Cash flows used for investing activities increased by $13.5 million from $46.3 million for the year ended December 31, 2019, to $59.8 million for the year ended December 31, 2020. During the years ended December 31, 2020 and 2019, we invested $59.3 million and $30.1 million, respectively, in SLC Pipelineadditions to properties and equipment. During the year ended December 31, 2020, we made payments of $2.4 million related to our 50% interest in Frontier Aspen for $245.4 million in October 2017. We acquired a 50% interest in CheyenneCushing Connect Pipeline LLC for $42.6 million in June 2016 as well as $44.1 million for the Woods Cross refinery processing units and Tulsa tanks.& Terminal LLC.
Cash Flows—Financing Activities
Year Ended December 31, 20182021 Compared with Year Ended December 31, 20172020
Cash flows used for financing activities were $247.6decreased by $23.9 million from $247.2 million for the year ended December 31, 2018, compared2020, to cash flows provided by financing activities of $51.9$223.2 million for the year ended December 31, 2017, a decrease of $299.5 million.2021. During the year ended December 31, 2018,2021, we received $337.0$480.5 million and repaid $426.0$554.0 million in advances under the Credit Agreement. We also received net proceeds of $114.8 million from issuance of common units. Additionally, we paid $265.0$149.4 million in regular quarterly cash distributions to our generalHEP unitholders and limited partners and $7.5$10.7 million to our noncontrolling interest.interests. We received $23.2 million in contributions from our noncontrolling interests during the year ended December 31, 2021. During the year ended December 31, 2017,2020, we received $969.0$258.5 million and repaid $510.0$310.5 million in advances under the Credit Agreement. We also received net proceeds of $101.8 million from the issuance of our 6% Senior Notes and $52.1 million from the issuance of common units. Additionally, we paid $309.8 million for the redemption of our 6.5% Senior Notes, $234.6$174.4 million in regular quarterly cash distributions to our generalHEP unitholders and limited partners and $6.5$9.8 million to our noncontrolling interest.interests. We also received net proceeds of $491.3 million from the issuance of our 5% Senior Notes and paid $9.4$522.5 million in deferred financing charges to amend the Credit Agreement.retire our 6% Senior Notes.
Year Ended December 31, 20172020 Compared with Year Ended December 31, 20162019
Cash flows provided byused for financing activities were $51.9increased by $6.6 million from $240.6 million for the year ended December 31, 2017, compared2019, to cash flows used for financing activities of $111.9$247.2 million for the year ended December 31, 2016, an increase of $163.8 million.2020. During the year ended December 31, 2017,2020, we received $969.0$258.5 million and repaid $510.0$310.5 million in advances under the Credit Agreement. We also received net proceeds of $101.8 million from the issuance of our 6% Senior Notes and $52.1 million from issuance of common units. Additionally, we paid $309.8 million for the redemption of our 6.5% Senior Notes, $234.6$174.4 million in regular quarterly cash distributions to our generalHEP unitholders and limited partners and $6.5$9.8 million to our noncontrolling interest. We received $23.9 million in contributions from our noncontrolling interests during the year ended December 31, 2020. We also received net proceeds of $491.3 million from the issuance of our 5% Senior Notes and paid $9.4$522.5 million in deferred financing charges to amend the Credit Agreement.retire our 6% Senior Notes. During the year ended December 31, 2016,2019, we received $554.0$365.5 million and repaid $713.0$323.0 million in advances under the Credit Agreement. We also received net proceeds of $394.0 million from the issuance of our 6% Senior Notes and $125.9 million from the issuance of common units. We alsoAdditionally, we paid $192.0$273.2 million in regular quarterly cash distributions to our generalHEP unitholders and limited partners, paid $5.8$9.0 million to our noncontrolling interest and paid $3.5 million for the purchase of common units for recipients of our incentive grants. In addition, we received $51.3 million for the Woods Cross Operating and Tulsa tank acquisitions, and recorded distributions to HFC for acquisitions of $317.5 million.interests.
Capital Requirements
Our pipeline and terminalling operations are capital intensive, requiring investments to maintain, expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements have consisted of, and are expected to continue to consist of, maintenance capital expenditures and expansion capital expenditures. “Maintenance capital expenditures” represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity, safety and to address environmental regulations. “Expansion capital expenditures” represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition.but exclude acquisitions. Expansion capital expenditures include expenditures to acquire assets, to grow our business and to expand existing facilities, such as projects that increase throughput capacity on our pipelines and in our terminals. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.
Each year the board of directors of HLS, our ultimate general partner, approves our annual capital budget, which specifies capital projects that our management is authorized to undertake. Additionally, at times when conditions warrant or as new opportunities arise, additional projects may be approved. The funds allocated for a particular capital project may be expended over a period in excess of a year, depending on the time required to complete the project. Therefore, our planned capital expenditures for a given year consist of expenditures approved for capital projects included in the current year’s capital budget as well as, in certain cases, expenditures approved for capital projects in capital budgets for prior years. The 2019 Our current 2022 capital budgetforecast is comprised of approximately $10$15 million to $20 million for maintenance capital expenditures, and approximately $20$35 million to $25$50 million for refinery unit turnarounds and $5 to $10 million for expansion capital expenditures. We expectexpenditures, excluding any expenditures related to the majority of the expansion capital budget to be invested in refined product pipeline expansions, crude system enhancements, new storage tanks, and enhanced blending capabilities at our racks.HEP Transaction. In addition to our capitalcapital budget, we may spend funds periodically to perform capital upgrades or additions to our assets where a customer reimburses us for such costs. The upgrades or additions would generally benefit the customer over the remaining life of the related service agreements.
We expect that our currently planned sustaining and maintenance capital expenditures, as well as expenditures for acquisitions and capital development projects, will be funded with cash generated by operations,operations. We expect that, to the sale ofextent necessary, we can raise additional limited partner common units, the issuance offunds from time to time through equity or debt securities and advances under our Credit Agreement, or a combination thereof. With volatility and uncertainty at timesfinancings in the creditpublic and equity markets, there may be limits on our ability to issue new debt or equity financing. Additionally, due to pricing movements in the debt and equity markets, we may not be able to issue new debt and equity securities at acceptable pricing. Without additionalprivate capital beyond amounts available under the Credit Agreement, our ability to obtain funds for some of these capital projects may be limited.markets.
Under the terms of the transaction to acquire HFC’s 75% interest in UNEV, we issued to HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2015, and ending in June 2032, subject to certain limitations. However, to the extent earnings thresholds are not achieved, no redemption payments are required. No redemption payments have been required to date.
Credit Agreement
We have a $1.4$1.2 billion senior secured revolving credit facility (the “Credit Agreement”) expiring in July 2022.2025. The Credit Agreement is available to fund capital expenditures, investments, acquisitions, distribution payments and working capital and for general partnership purposes. The Credit Agreement is also available to fund letters of credit up to a $50 million sub-limit and it containscontinues to provide for an accordion feature givingthat allows us the ability to increase commitments under the size of the facility byCredit Agreement up to $300 million with additional lender commitments.a maximum amount of $1.7 billion. As of December 31, 2018,2021, we had outstanding borrowings of $923$840.0 million under the Credit Agreement, no letters of credit outstanding, and the available capacity was $477$360.0 million.
Our obligations under the Credit Agreement are collateralized by substantially all of our assets, and indebtedness under the Credit Agreement is guaranteed by our material wholly-owned subsidiaries. The Credit Agreement requires us to maintain compliance with certain financial covenants consisting of total leverage, senior secured leverage and interest coverage. It also limits or restricts our ability to engage in certain activities. If, at any time prior to the expiration of the Credit Agreement, HEP obtains two investment grade credit ratings, the Credit Agreement will become unsecured and many of the covenants, limitations, and restrictions will be eliminated.
We may prepay all loans at any time without penalty, except for tranche breakage costs. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of all loans outstanding and exercise other rights and remedies. We were in compliance with all covenants as of December 31, 2018.2021.
Indebtedness under the Credit Agreement bears interest, at our option, at either (a) the reference rate as announced by the administrative agent plus an applicable margin (ranging from 0.50% to 1.50%) or (b) at a rate equal to LIBOR plus an applicable margin (ranging from 1.50% to 2.50%). In each case, the applicable margin is based upon the ratio of our funded debt (as defined in the Credit Agreement) to EBITDA (earnings before interest, taxes, depreciation and amortization, as defined in the Credit Agreement). The weighted-average interest rates on our Credit Agreement borrowings for the years ending December 31, 20182021 and 2017,2020, were 4.238%2.30% and 3.734%2.58%, respectively. We incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.25% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.
Senior Notes
On January 4, 2017,As of December 31, 2021, we redeemed the $300had $500 million in aggregate principal amount of our 6.5%5% Senior Notes due in 2028.
On February 4, 2020, we closed the private placement of $500 million in aggregate principal amount of 5% senior unsecured notes due in 2028 (the “5% Senior Notes”). On February 5, 2020, we redeemed the existing $500 million 6% Senior Notes at a redemption cost of $309.8$522.5 million, at which time we recognized a $12.2$25.9 million early extinguishment loss.loss consisting of a $22.5 million debt redemption premium and unamortized financing costs of $3.4 million. We funded the $522.5 million redemption with proceeds from the issuance of our 5% Senior Notes and borrowings under our Credit Agreement.
We have $500 million in aggregate principal amount of 6% Senior Notes due in 2024. We used the net proceeds from our offerings of the 6% Senior Notes to repay indebtedness under our Credit Agreement.
The 6%5% Senior Notes are unsecured and impose certain restrictive covenants, including limitations on our ability to incur additional indebtedness, make investments, sell assets, incur certain liens, pay distributions, enter into transactions with affiliates, and enter into mergers. We were in compliance with the restrictive covenants for the 6%5% Senior Notes as of December 31, 2018.2021. At any time when the 6%5% Senior Notes are rated investment grade by botheither Moody’s andor Standard & Poor’s and no default or event of default exists, we will not be subject to many of the foregoing covenants. Additionally, we have certain redemption rights at varying premiums over face value under the 6%5% Senior Notes.
Indebtedness under the 6%5% Senior Notes is guaranteed by all of our existing wholly-owned subsidiaries.subsidiaries (other than Holly Energy Finance Corp. and certain immaterial subsidiaries).
Long-term Debt
The carrying amounts of our long-term debt are as follows: | | | | | | | | | | | | | | |
| | December 31,
2021 | | December 31,
2020 |
| | (In thousands) |
| Credit Agreement | | $ | 840,000 | | | $ | 913,500 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| 5% Senior Notes | | 500,000 | | | 500,000 | |
| Principal | | (6,951) | | | (7,897) | |
| Unamortized debt issuance costs | | 493,049 | | | 492,103 | |
| | | | |
| Total long-term debt | | $ | 1,333,049 | | | $ | 1,405,603 | |
|
| | | | | | | | |
| | | December 31,
2018 | | December 31,
2017 |
| | | (In thousands) |
| Credit Agreement | | $ | 923,000 |
| | $ | 1,012,000 |
|
| | | | | |
| 6% Senior Notes | | | | |
| Principal | | 500,000 |
| | 500,000 |
|
| Unamortized debt issuance costs | | (4,100 | ) | | (4,692 | ) |
| | | 495,900 |
| | 495,308 |
|
| | | | | |
| Total long-term debt | | $ | 1,418,900 |
| | $ | 1,507,308 |
|
See “Risk Management” for a discussion of our interest rate swaps.
Long-term Contractual Obligations
The following table presents our long-term contractual obligations as of December 31, 2018.2021.
| | | | | | | Payments Due by Period | | | | | Payments Due by Period |
| | | Total | | Less than 1 Year | | 1-3 Years | | 3-5 Years | | Over 5 Years | | | Total | | Less than
1 Year | | 1-3 Years | | 3-5 Years | | Over 5
Years |
| | | (In thousands) | | | (In thousands) |
| Long-term debt – principal | | $ | 1,423,000 |
| | $ | — |
| | $ | — |
| | $ | 923,000 |
| | $ | 500,000 |
| Long-term debt – principal | | $ | 1,340,000 | | | $ | — | | | $ | — | | | $ | 840,000 | | | $ | 500,000 | |
| Long-term debt - interest | | 313,303 |
| | 70,784 |
| | 141,568 |
| | 83,451 |
| | 17,500 |
| Long-term debt - interest | | 222,456 | | | 44,700 | | | 89,400 | | | 61,273 | | | 27,083 | |
| Site service fees | | 246,180 |
| | 5,286 |
| | 10,573 |
| | 10,573 |
| | 219,748 |
| Site service fees | | 242,933 | | | 5,601 | | | 11,202 | | | 11,202 | | | 214,928 | |
| Pipeline operating lease | | 55,814 |
| | 6,566 |
| | 13,133 |
| | 13,133 |
| | 22,982 |
| |
| Pipeline finance lease | | Pipeline finance lease | | 36,115 | | | 6,566 | | | 13,133 | | | 13,133 | | | 3,283 | |
| Right-of-way agreements and other | | 21,095 |
| | 5,828 |
| | 6,739 |
| | 3,072 |
| | 5,456 |
| Right-of-way agreements and other | | 18,990 | | | 4,326 | | | 7,973 | | | 2,180 | | | 4,511 | |
| Total | | $ | 2,059,392 |
| | $ | 88,464 |
| | $ | 172,013 |
| | $ | 1,033,229 |
| | $ | 765,686 |
| Total | | $ | 1,860,494 | | | $ | 61,193 | | | $ | 121,708 | | | $ | 927,788 | | | $ | 749,805 | |
Long-term debt consists of outstanding principal under the Credit Agreement and the 5% Senior Notes. Interest on the Credit Agreement is calculated using the rate in effect at December 31, 2018.2021.
Site service fees consist of site service agreements with HFC, expiring in 2058 through 2066, for the provision of certain facility services and utility costs that relate to our assets located at HFC’s refinery facilities. We are presenting obligations for the full term of these agreements; however, the agreements can be terminated with 180 day notice if we cease to operate the applicable assets.
The pipeline operatingfinance lease amounts above reflect the exercise of the second 10-year extension, expiring in 2027, on our lease agreement for the refined products pipeline between White Lakes Junction and Kuntz Station in New Mexico.
Most of our right-of-way agreements are renewable on an annual basis, and the right-of-way agreements payments above include only obligations under the remaining non-cancelable terms of these agreements at December 31, 2018.2021. For the foreseeable future, we intend to continue renewing these agreements and expect to incur right-of-way expenses in addition to the payments listed.
Other contractual obligations include capital lease obligations related to vehicles leases, office space leases, and other.
Impact of Inflation
Inflation in the United States has beenAfter being relatively moderate in recent years, andinflation in the United States increased significantly during 2021. However, inflation did not have a material impact on our results of operations for the years ended December 31, 2018, 20172021, 2020 and 20162019. PPI has increased an average of 0.8%2.9% annually over the past five calendar years, including an increasesincrease of 3.0%8.9% in 2021 and 3.2%a decrease of 1.3% in 2018 and 2017, respectively.2020.
The substantial majority of our revenues are generated under long-term contracts that provide for increases or decreases in our rates and minimum revenue guarantees annually for increases or decreases in the PPI. Most of these annual PPI percentage rate increases or decreases go into effect on July 1st of the following year. Certain of these contracts have provisions that limit the level of annual PPI percentage rate increases or decreases. A significant and prolonged period of high inflation or a significant and prolonged period of negative inflation could adversely affect our cash flows and results of operations if costs increase at a rate greater than the fees we charge our shippers.
Environmental Matters
Our operation of pipelines, terminals, and associated facilities in connection with the transportation and storage of refined products and crude oil is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position given that the operations of our competitors are similarly affected. However, these laws and regulations, and the interpretation or enforcement thereof, are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions, and construction bans or delays. A major discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by employees, neighboring landowners and other third parties for personal injury and property damage.
Contamination resulting from spills of refined products and crude oil is not unusual within the petroleum pipeline industry. Historic spills along our existing pipelines and terminals as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at a few of our properties where operations may have resulted in releases of hydrocarbons and other wastes, none of which we believe will have a significant effect on our operations since the remediation of such releases would be covered under environmental indemnification agreements.
Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC and occurring or existing prior to the date of such transfers.
We have an environmental agreement with Delek with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Delek in 2005, under which Delek will indemnify us subject to certain monetary and time limitations.
There are environmental remediation projects in progress that relate to certain assets acquired from HFC. Certain of these projects were underway prior to our purchase and represent liabilities retained by HFC. As of December 31, 2018,2021, we have an accrual of $6.3$3.9 million that relates to environmental clean-up projects for which we have assumed liability or for which the indemnity provided for by HFC has expired. The remaining projects, including assessment and monitoring activities, are covered under the HFC environmental indemnification discussed above and represent liabilities of HFC.
CRITICAL ACCOUNTING POLICIESESTIMATES
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from these estimates under different assumptions or conditions. We consider the following policies to be the most critical to understanding the judgments that are involved and the uncertainties that could impact our results of operations, financial condition and cash flows.
Revenue Recognition
Revenues are generally recognized as products are shipped through our pipelines and terminals, feedstocks are processed through our refinery processing units or other services are rendered. The majority of our contracts with customers meet the definition of a lease since (1) performance of the contracts is dependent on specified property, plant, or equipment and (2) the possibility is remote that one or more parties other than the customer will take more than a minor amount of the output associated with the specified property, plant, or equipment. As a result,Prior to the adoption of the new lease standard (see below), we bifurcatebifurcated the consideration received between lease and service revenue. The service component is withinnew lease standard allows the scopeelection of a practical expedient whereby a lessor does not have to separate non-lease (service) components from lease components under certain conditions. The majority of our contracts meet these conditions, and we have made this election for those contracts. Under this practical expedient, we treat the combined components as a single performance obligation in accordance with Accounting Standards Codification (“ASC”) 606, which largely codified ASU 2014-09.2014-09, if the non-lease (service) component is
the dominant component. If the lease component is the dominant component, we treat the combined components as a lease in accordance with ASC 842, which largely codified ASU 2016-02.
Several of our contracts include incentive or reduced tariffs once a certain quarterly volume is met. Revenue from the variable element of these transactions is recognized based on the actual volumes shipped as it relates specifically to rendering the services during the applicable quarter.
The majority of our long-term transportation contracts specify minimum volume requirements, whereby, we bill a customer for a minimum level of shipments in the event a customer ships below their contractual requirements. If there are no future performance obligations, we will recognize these deficiency payments in revenue.
In certain of these throughput agreements, a customer may later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum levels within its respective contractual shortfall make-up period. Such amounts represent an obligation to perform future services, which may be initially deferred and later recognized as revenue based on estimated future shipping levels, including the likelihood of a customer’s ability to utilize such amounts prior to the end of the contractual shortfall make-up period. We recognize the service portion of these deficiency payments in revenue when we do not expect we will be required to satisfy these performance obligations in the future based on the pattern of rights projected to be exercised by the customer.
Prior to the adoption ofLeases
We adopted ASC 606 on842 effective January 1, 2018, billings2019, and elected to customers for their obligations under their quarterly minimum revenue commitments were recordedadopt using the modified retrospective transition method and practical expedients, both of which are provided as deferred revenue liabilitiesoptions by the standard and further defined below.
Lessee Accounting - At inception, we determine if the customer had thean arrangement is or contains a lease. Right-of-use assets represent our right to receive future servicesuse an underlying asset for these billings. The revenue wasthe lease term, and lease liabilities represent our payment obligation under the leasing arrangement. Right-of-use assets and lease liabilities are recognized at the earlier of:
commencement date based on the customer receivingpresent value of lease payments over the future services provided by these billings,
lease term. We use our estimated incremental borrowing rate (“IBR”) to determine the period inpresent value of lease payments as most of our leases do not contain an implicit rate. Our IBR represents the interest rate which the customer was contractually allowed to receive the services expired, or
our determination that we would not be requiredpay to provide services withinborrow, on a collateralized basis, an amount equal to the allowed period.lease payments over a similar term in a similar economic environment. We use the implicit rate when readily determinable.
We determined that we would not be required to provide services within the allowed period when, based onOperating leases are recorded in operating lease right-of-use assets and current and projected shipping levels,noncurrent operating lease liabilities on our pipeline systems wouldconsolidated balance sheet. Finance leases are included in properties and equipment, current finance lease liabilities and noncurrent finance lease liabilities on our consolidated balance sheet.
When renewal options are defined in a lease, our lease term includes an option to extend the lease when it is reasonably certain we will exercise that option. Leases with a term of 12 months or less are not haverecorded on our balance sheet, and lease expense is accounted for on a straight-line basis. In addition, as a lessee, we separate non-lease components that are identifiable and exclude them from the necessary capacity to enable a customer to exceed its minimum volume levels todetermination of net present value of lease payment obligations.
Lessor Accounting - Customer contracts that contain leases are generally classified as either operating leases, direct finance leases or sales-type leases. We consider inputs such a degree as to utilize the shortfall credit within its respective contractual shortfall make-up period.lease term, fair value of the underlying asset and residual value of the underlying assets when assessing the classification.
Goodwill and Long-Lived Assets
Goodwill represents the excess of our cost of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized. We test goodwill at the reporting unit level for impairment annually and between annual tests if events or changes in circumstances indicate the carrying amount may exceed fair value. Our goodwill impairment testing first entails a comparison of our reporting unit fair values relative to their respective carrying values, including goodwill. If carrying value exceeds the estimated fair value for a reporting unit, we measure goodwill impairment as the excess of the carrying amount of the reporting unit goodwill over the impliedestimated fair value of that goodwill based on estimates of the fair value of all assets and liabilities in the reporting unit.
In 2018, we usedThe changes due to our new agreements with HFC related to our Cheyenne assets resulted in an increase in the presentnet book value of our Cheyenne reporting unit during the first quarter of 2021 due to sales-type lease accounting, which led us to determine indicators of potential goodwill impairment for our Cheyenne reporting unit were present. Therefore, we performed an interim quantitative review of our Cheyenne reporting unit goodwill for the first quarter of 2021.
The estimated fair value of our Cheyenne reporting unit was derived using a combination of income and market approaches. The income approach reflects expected future net cash flows based on anticipated gross margins, operating costs and capital expenditures. The market multiple analyses to determineapproaches include both the estimatedguideline public company and guideline transaction methods. Both methods utilize pricing multiples derived from historical market transactions of other like-kind assets. These fair valuesvalue measurements involve significant unobservable inputs (Level 3 inputs). See Note 6 for further discussion of the reporting units. TheLevel 3 inputs.
Our interim impairment test requires the use of projections, estimates and assumptions as to the future performancetesting of our operations. Actual results could differ from projections resulting in revisions to our assumptions, and if required, could resultCheyenne reporting unit goodwill identified an impairment charge of $11.0 million, which was recorded in the recognitionthree months ended March 31, 2021.
Our annual goodwill impairment testing was performed on a qualitative basis during the third quarter of an impairment loss. In 2017, we2021. We assessed qualitative factors such as macroeconomic conditions, industry considerations, cost factors, and reporting unit financial performance and determined it was not more likely than not that the fair value of our reporting units werewas less than the respective carrying value. Therefore, in accordance with GAAP, further testing was not required.
In 2020, our annual goodwill testing was performed on a quantitative basis with the estimated fair value of our reporting units derived using a combination of both income and market approaches as described above. Our annual testing of goodwill did not identify any impairments other than our Cheyenne reporting unit, which reported goodwill impairment charges of $35.7 million for the year ending December 31, 2020.
We evaluate long-lived assets, including finite-lived intangible assets, for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value.
There have been no impairments to goodwill or our long-lived assets through December 31, 2018.
Accounting Pronouncement Adopted During the Periods Presented
Revenue Recognition
In May 2014, an accounting standard update was issued requiring revenue to be recognized when promised goods or services are transferred to customers in an amount that reflects the expected consideration for these goods or services. This standard had an effective date of January 1, 2018, and we accounted for the new guidance using the modified retrospective implementation method, whereby a cumulative effect adjustment was recorded to retained earnings as of the date of initial application. In preparing for adoption, we evaluated the terms, conditions and performance obligations under our existing contracts with customers. Furthermore, we implemented policies to comply with this new standard. See above and Note 3 to the consolidated financial statements for additional information on our revenue recognition policies.
Business Combinations
In December 2014, an accounting standard update was issued to provide new guidance on the definition of a business in relation to accounting for identifiable intangible assets in business combinations. This standard had an effective date of January 1, 2018, and had no effect on our financial condition, results of operations or cash flows.
Financial Assets and Liabilities
In January 2016, an accounting standard update was issued requiring changes in the accounting and disclosures for financial instruments. This standard was effective beginning with our 2018 reporting year and had no effect on our financial condition, results of operations or cash flows.
Accounting Pronouncements Not Yet Adopted
Leases
In February 2016, an accounting standard update was issued requiring leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. This standard has an effective date of January 1, 2019, and we plan to apply practical expedients provided in the standards update that allow us, among other things, not to reassess contracts that commenced prior to the adoption. The primary effect of adopting the new standard will be to record assets and obligations for current operating leases on our consolidated balance sheet. Adoption of the standard is not expected to have a material impact on our results of operations or cash flows.
In preparing for adoption, we have identified, reviewed and evaluated contracts containing lease and embedded lease arrangements. Additionally, we have acquired and implemented software and systems to facilitate lease capture and related accounting treatment.
RISK MANAGEMENT
The two interest rate swaps that hedged our exposure to the cash flow risk caused by the effects of LIBOR changes on $150 million of Credit Agreement matured on July 31, 2017. The swaps had effectively converted $150 million of our LIBOR based debt to fixed rate debt.
The market risk inherent in our debt positions is the potential change arising from increases or decreases in interest rates as discussed below.
At December 31, 2018,2021, we had an outstanding principal balance of $500 million on our 6%5% Senior Notes. A change in interest rates generally would affect the fair value of the 6%5% Senior Notes, but not our earnings or cash flows. At December 31, 2018,2021, the fair value of our 6%5% Senior Notes was $488$502.7 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6%5% Senior Notes at December 31, 2018,2021, would result in a change of approximately $15$12.9 million in the fair value of the underlying 6%5% Senior Notes.
For the variable rate Credit Agreement, changes in interest rates would affect cash flows, but not the fair value. At December 31, 2018,2021, borrowings outstanding under the Credit Agreement were $923$840.0 million. A hypothetical 10% change in interest rates applicable to the Credit Agreement would not materially affect our cash flows.
Borrowings under our variable rate Credit Agreement bear interest at a variable rate based on the London Interbank Offered Rate (“LIBOR”). The ICE Benchmark Administration Limited (“IBA”) announced that it will cease calculating and publishing all USD LIBOR tenors on June 30, 2023, and ceased calculating and publishing certain USD LIBOR tenors on December 31, 2021. Further, U.K. and U.S. regulatory authorities issued statements encouraging banks to cease entering into new USD LIBOR based loans by no later than December 31, 2021 and to continue to transition away from USD LIBOR based loans in preparation of IBA ceasing to calculate and publish LIBOR based rates on June 30, 2023. These developments may cause fluctuations in LIBOR rates and pricing of USD LIBOR based loans that are not transitioned to an alternative reference rate. While we do not expect the transition to an alternative reference rate to have a significant impact on our business or operations, it is possible that the use of alternative reference rates or other reforms could cause the market value of, the applicable interest rate on and the amount of interest paid on our variable rate indebtedness to be materially different than expected and could cause our interest expense to increase.
Our operations are subject to normal hazards of operations, including fire, explosion and weather-related perils. We maintain various insurance coverages, including business interruption insurance, subject to certain deductibles. We are not fully insured against certain risks because such risks are not fully insurable, coverage is unavailable, or premium costs, in our judgment, do not justify such expenditures.
We have a risk management oversight committee that is made up of members from our senior management. This committee monitors our risk environment and provides direction for activities to mitigate, to an acceptable level, identified risks that may adversely affect the achievement of our goals.
| |
Item 7A. | Quantitative and Qualitative Disclosures about Market Risk |
Item 7A.Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. See “Risk Management” under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of market risk exposures that we have with respect to our long-term debt. We utilize derivative instruments to hedge our interest rate exposure, as discussed under “Risk Management.”
Since we do not own products shipped on our pipelines or terminalled at our terminal facilities, we do not have direct market risks associated with commodity prices.
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Item 8. | Financial Statements and Supplementary Data |
Item 8.Financial Statements and Supplementary Data
MANAGEMENT’S REPORT ON ITS ASSESSMENT OF THE PARTNERSHIP’S INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Holly Energy Partners, L.P. (the “Partnership”) is responsible for establishing and maintaining adequate internal control over financial reporting.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the Partnership’s internal control over financial reporting as of December 31, 2018,2021, using the criteria for effective control over financial reporting established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this assessment, management concluded that, as of December 31, 2018,2021, the Partnership maintained effective internal control over financial reporting.
The Partnership’s independent registered public accounting firm has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2018.2021. That report appears on page 62.70.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Unitholders of Holly Energy Partners, L.P. and the Board of Directors of Holly Logistic Services, L.L.C.
Opinion on Internal Control overOver Financial Reporting
We have audited Holly Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2018,2021, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Holly Energy Partners, L.P. (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018,2021, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 20182021 and 2017,2020, the related consolidated statements of income, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2018,2021, and the related notes of the Partnership and our report dated February 20, 201923, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on its Assessment of the Partnership’s Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ ERNSTErnst & YOUNGYoung LLP
Dallas, Texas
February 20, 201923, 2022
Index to Consolidated Financial Statements
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To Unitholders of Holly Energy Partners, L.P. and the Board of Directors of Holly Logistic Services, L.L.C.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Holly Energy Partners, L.P. (the Partnership) as of December 31, 20182021 and 2017,2020, the related consolidated statements of income, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2018,2021, and the related notes (collectively referred to as the "financial statements"“consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 20182021 and 2017,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2018,2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 20, 201923, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
| | | | | |
| Revenue Recognition |
| |
| Description of the Matter | For the year ended December 31, 2021, the Partnership’s total revenues were $494.5 million. As discussed in Note 1 and Note 4 of the financial statements, revenues are generally recognized as products are shipped through pipelines and terminals, feedstocks are processed through the refinery processing units or other services are rendered. The majority of the Partnership’s long-term throughput agreements with customers specify minimum volume requirements. In the event a customer does not fulfill minimum volume requirements during a contractual period, the Partnership can bill the customer for the minimum level. In certain contracts, a customer may later utilize these shortfall billings as credit towards future throughput volumes in excess of minimum levels within a respective contractual shortfall make-up period. Shortfall billing amounts represent an obligation to provide future shipping services and may be initially deferred and later recognized as revenue. Recognition is based on estimated future throughput volumes, including the likelihood of a customer’s ability to utilize such amounts prior to the end of the contractual shortfall make-up period or when the Partnership does not expect to be required to satisfy these performance obligations in the future based on the pattern of rights exercised by the customer.
Auditing the measurement of the Partnership’s revenue was complex and judgmental due to various contractual provisions used in customer agreements and measurement uncertainty associated with management’s estimates of deferred revenue related to the future utilization of shortfall billings. |
| |
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership’s revenue recognition process. This included testing relevant controls over the review of the accounting analysis upon execution of a customer contract, as well as controls over management’s estimates affecting deferred revenue associated with shortfall billings.
Our audit procedures over the Partnership’s revenue included, among others, testing a sample of revenue transactions to evaluate whether revenue was recorded in accordance with the contract terms, performing recalculations of the deferred revenue amounts related to shortfall billings, and testing management’s estimation of deferred revenue based on historical pattern of rights exercised by the customer and expected future usage. |
| |
| Sales-Type Lease Accounting |
| |
| Description of the Matter | As disclosed in Note 5 of the financial statements, the Partnership entered into new agreements and amended other agreements which met the criteria of sales-type leases since the underlying assets are not expected to have an alternative use at the end of the lease terms. Under sales-type lease accounting, the lessor recognizes a net investment in the lease and derecognizes the underlying asset with the difference recorded as a gain or loss at the lease commencement date. During the year ended December 31, 2021, the Partnership recorded total net investment in the leases of $148.4 million and recognized gains on the sales-type leases totaling $24.7 million.
Auditing management’s accounting for certain sales-type leases, specifically those related to lube racks constructed in prior years, was complex and highly judgmental due to the estimation uncertainty in determining the fair value of the underlying leased assets at the commencement date of the leases. The fair value of the underlying leased assets is factored into the Partnership’s determination of the net investment in the leases. The fair value estimates for these assets were sensitive to significant assumptions and inputs used based on a replacement cost valuation method, such as estimates of the replacement cost and the effective age of the assets. These assumptions have a significant effect on the fair value estimate. |
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| | | | | |
| How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership's evaluation of the lease classification and related accounting for the sales-type leases. For example, we tested controls over management's review of the significant inputs and assumptions used in estimating the fair value of the underlying leased assets.
To test the Partnership’s accounting for the sales-type leases involving the previously constructed lube racks, including the estimated fair value of the underlying leased assets, we performed audit procedures that included, among others, assessing methodologies and testing the significant assumptions discussed above and the underlying data used by the Partnership in its analysis. We compared the significant replacement cost assumptions used by management to recent expenditures for similar assets. We also inspected supporting documentation, such as evidence related to maintenance records, to assess the effective age of the assets. In addition, we involved our valuation specialists to assist with our evaluation of the methodologies and significant assumptions included in the fair value estimates. |
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/s/ ERNSTErnst & YOUNGYoung LLP
We have served as the Partnership's auditor since 2003.
Dallas, Texas
February 20, 201923, 2022
HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(inIn thousands, except unit data)
| | | | | December 31, 2018 | | December 31, 2017 | | December 31, 2021 | | December 31, 2020 |
| ASSETS | | | | | ASSETS | | | | |
| Current assets: | | | | | Current assets: | |
| Cash and cash equivalents | | $ | 3,045 |
| | $ | 7,776 |
| |
Cash and cash equivalents (Cushing Connect VIEs: $8,881 and $18,259, respectively) | | Cash and cash equivalents (Cushing Connect VIEs: $8,881 and $18,259, respectively) | | $ | 14,381 | | | $ | 21,990 | |
| Accounts receivable: | | | | | Accounts receivable: | |
| Trade | | 12,332 |
| | 12,803 |
| Trade | | 12,745 | | | 14,543 | |
| Affiliates | | 46,786 |
| | 51,501 |
| Affiliates | | 56,154 | | | 47,972 | |
| | | 59,118 |
| | 64,304 |
| | 68,899 | | | 62,515 | |
| Prepaid and other current assets | | 4,311 |
| | 2,311 |
| Prepaid and other current assets | | 11,033 | | | 9,487 | |
| Total current assets | | 66,474 |
| | 74,391 |
| Total current assets | | 94,313 | | | 93,992 | |
| | | | | | |
| Properties and equipment, net | | 1,538,655 |
| | 1,569,471 |
| |
Properties and equipment, net (Cushing Connect VIEs: $— and $47,801, respectively) | | Properties and equipment, net (Cushing Connect VIEs: $— and $47,801, respectively) | | 1,329,028 | | | 1,450,685 | |
| Operating lease right-of-use assets | | Operating lease right-of-use assets | | 2,275 | | | 2,979 | |
Net investment in leases (Cushing Connect VIEs: $100,042 and $—, respectively) | | Net investment in leases (Cushing Connect VIEs: $100,042 and $—, respectively) | | 309,303 | | | 166,316 | |
| Intangible assets, net | | 115,329 |
| | 129,463 |
| Intangible assets, net | | 73,307 | | | 87,315 | |
| Goodwill | | 270,336 |
| | 266,716 |
| Goodwill | | 223,650 | | | 234,684 | |
| Equity method investments | | 83,840 |
| | 85,279 |
| |
Equity method investments (Cushing Connect VIEs: $37,505 and $39,456, respectively) | | Equity method investments (Cushing Connect VIEs: $37,505 and $39,456, respectively) | | 116,378 | | | 120,544 | |
| Other assets | | 27,906 |
| | 28,794 |
| Other assets | | 17,613 | | | 11,050 | |
| Total assets | | $ | 2,102,540 |
| | $ | 2,154,114 |
| Total assets | | $ | 2,165,867 | | | $ | 2,167,565 | |
| | | | | | | | | |
| LIABILITIES AND EQUITY | | | | | LIABILITIES AND EQUITY | |
| Current liabilities: | | | | | Current liabilities: | |
| Accounts payable: | | | | | Accounts payable: | |
| Trade | | $ | 16,435 |
| | $ | 14,547 |
| |
Trade (Cushing Connect VIEs: $8,285 and $14,076, respectively) | | Trade (Cushing Connect VIEs: $8,285 and $14,076, respectively) | | $ | 28,577 | | | $ | 28,280 | |
| Affiliates | | 14,222 |
| | 7,725 |
| Affiliates | | 11,703 | | | 18,120 | |
| | | 30,657 |
| | 22,272 |
| | 40,280 | | | 46,400 | |
| | | | | | |
| Accrued interest | | 13,302 |
| | 13,256 |
| Accrued interest | | 11,258 | | | 10,892 | |
| Deferred revenue | | 8,697 |
| | 9,598 |
| Deferred revenue | | 14,585 | | | 11,368 | |
| Accrued property taxes | | 1,779 |
| | 4,652 |
| Accrued property taxes | | 4,542 | | | 3,992 | |
| Current operating lease liabilities | | Current operating lease liabilities | | 620 | | | 875 | |
| Current finance lease liabilities | | Current finance lease liabilities | | 3,786 | | | 3,713 | |
| Other current liabilities | | 3,462 |
| | 5,707 |
| Other current liabilities | | 1,781 | | | 2,505 | |
| Total current liabilities | | 57,897 |
| | 55,485 |
| Total current liabilities | | 76,852 | | | 79,745 | |
| | | | | | |
| Long-term debt | | 1,418,900 |
| | 1,507,308 |
| Long-term debt | | 1,333,049 | | | 1,405,603 | |
| Noncurrent operating lease liabilities | | Noncurrent operating lease liabilities | | 2,030 | | | 2,476 | |
| Noncurrent finance lease liabilities | | Noncurrent finance lease liabilities | | 64,649 | | | 68,047 | |
| Other long-term liabilities | | 15,307 |
| | 15,843 |
| Other long-term liabilities | | 12,527 | | | 12,905 | |
| Deferred revenue | | 48,714 |
| | 47,272 |
| Deferred revenue | | 29,662 | | | 40,581 | |
| | | | | | |
| Class B unit | | 46,161 |
| | 43,141 |
| Class B unit | | 56,549 | | | 52,850 | |
| | | | | | |
| Equity: | | | | | Equity: | |
| Partners’ equity: | | | | | Partners’ equity: | |
Common unitholders (105,440,201 and 101,568,955 units issued and outstanding at December 31, 2018 and 2017, respectively) | | 427,435 |
| | 393,959 |
| |
Common unitholders (105,440,201 units issued and outstanding at both December 31, 2021 and 2020) | | Common unitholders (105,440,201 units issued and outstanding at both December 31, 2021 and 2020) | | 443,017 | | | 379,292 | |
| Total partners’ equity | | 427,435 |
| | 393,959 |
| Total partners’ equity | | 443,017 | | | 379,292 | |
| Noncontrolling interest | | 88,126 |
| | 91,106 |
| |
| Noncontrolling interests | | Noncontrolling interests | | 147,532 | | | 126,066 | |
| Total equity | | 515,561 |
| | 485,065 |
| Total equity | | 590,549 | | | 505,358 | |
| Total liabilities and equity | | $ | 2,102,540 |
| | $ | 2,154,114 |
| Total liabilities and equity | | $ | 2,165,867 | | | $ | 2,167,565 | |
See accompanying notes.
HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per unit data)
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2021 | | 2020 | | 2019 |
| Revenues: | | | | | | |
| Affiliates | | $ | 390,849 | | | $ | 399,809 | | | $ | 411,750 | |
| Third parties | | 103,646 | | | 98,039 | | | 121,027 | |
| | 494,495 | | | 497,848 | | | 532,777 | |
| Operating costs and expenses: | | | | | | |
| Operations (exclusive of depreciation and amortization) | | 170,524 | | | 147,692 | | | 161,996 | |
| Depreciation and amortization | | 93,800 | | | 99,578 | | | 96,705 | |
| General and administrative | | 12,637 | | | 9,989 | | | 10,251 | |
| Goodwill impairment | | 11,034 | | | 35,653 | | | — | |
| | 287,995 | | | 292,912 | | | 268,952 | |
| Operating income | | 206,500 | | | 204,936 | | | 263,825 | |
| | | | | | |
| Other income (expense): | | | | | | |
| Equity in earnings of equity method investments | | 12,432 | | | 6,647 | | | 5,180 | |
| Interest expense | | (53,818) | | | (59,424) | | | (76,823) | |
| Interest income | | 29,925 | | | 10,621 | | | 5,517 | |
| Gain on sales-type lease | | 24,677 | | | 33,834 | | | 35,166 | |
| Loss on early extinguishment of debt | | — | | | (25,915) | | | — | |
| Gain on sale of assets and other | | 6,179 | | | 8,691 | | | 272 | |
| | | | | | |
| | 19,395 | | | (25,546) | | | (30,688) | |
| Income before income taxes | | 225,895 | | | 179,390 | | | 233,137 | |
| State income tax expense | | (32) | | | (167) | | | (41) | |
| Net income | | 225,863 | | | 179,223 | | | 233,096 | |
| Allocation of net income attributable to noncontrolling interests | | (10,917) | | | (8,740) | | | (8,212) | |
| Net income attributable to the partners | | 214,946 | | | 170,483 | | | 224,884 | |
| | | | | | |
| | | | | | |
| Limited partners’ per unit interest in earnings—basic and diluted | | $ | 2.03 | | | $ | 1.61 | | | $ | 2.13 | |
| Weighted average limited partners’ units outstanding | | 105,440 | | | 105,440 | | | 105,440 | |
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| Revenues: | | | | | | |
| Affiliates | | $ | 397,808 |
| | $ | 377,136 |
| | $ | 333,116 |
|
| Third parties | | 108,412 |
| | 77,226 |
| | 68,927 |
|
| | | 506,220 |
| | 454,362 |
| | 402,043 |
|
| Operating costs and expenses: | | | | | | |
| Operations (exclusive of depreciation and amortization) | | 146,430 |
| | 137,605 |
| | 123,986 |
|
| Depreciation and amortization | | 98,492 |
| | 79,278 |
| | 70,428 |
|
| General and administrative | | 11,040 |
| | 14,323 |
| | 12,532 |
|
| | | 255,962 |
| | 231,206 |
| | 206,946 |
|
| Operating income | | 250,258 |
| | 223,156 |
| | 195,097 |
|
| | | | | | | |
| Other income (expense): | | | | | | |
| Equity in earnings of equity method investments | | 5,825 |
| | 12,510 |
| | 14,213 |
|
| Interest expense | | (71,899 | ) | | (58,448 | ) | | (52,552 | ) |
| Interest income | | 2,108 |
| | 491 |
| | 440 |
|
| Loss on early extinguishment of debt | | — |
| | (12,225 | ) | | — |
|
| Remeasurement gain on preexisting equity interests | | — |
| | 36,254 |
| | — |
|
| Gain on sale of assets and other | | 121 |
| | 422 |
| | 677 |
|
| | | (63,845 | ) | | (20,996 | ) | | (37,222 | ) |
| Income before income taxes | | 186,413 |
| | 202,160 |
| | 157,875 |
|
| State income tax expense | | (26 | ) | | (249 | ) | | (285 | ) |
| Net income | | 186,387 |
| | 201,911 |
| | 157,590 |
|
| Allocation of net loss attributable to Predecessor | | — |
| | — |
| | 10,657 |
|
| Allocation of net income attributable to noncontrolling interests | | (7,540 | ) | | (6,871 | ) | | (10,006 | ) |
| Net income attributable to the partners | | 178,847 |
| | 195,040 |
| | 158,241 |
|
| General partner interest in net income attributable to the Partnership, including incentive distributions | | — |
| | (35,047 | ) | | (57,173 | ) |
| Limited partners’ interest in net income | | $ | 178,847 |
| | $ | 159,993 |
| | $ | 101,068 |
|
| Limited partners’ per unit interest in earnings—basic and diluted | | $ | 1.70 |
| | $ | 2.28 |
| | $ | 1.69 |
|
| Weighted average limited partners’ units outstanding | | 105,042 |
| | 70,291 |
| | 59,872 |
|
Net income and comprehensive income are the same in all periods presented.
See accompanying notes.
HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| Net income | | $ | 186,387 |
| | $ | 201,911 |
| | $ | 157,590 |
|
| | | | | | | |
| Other comprehensive income: | | | | | | |
| Change in fair value of cash flow hedging instruments | | — |
| | 88 |
| | (607 | ) |
| Reclassification adjustment to net income on partial settlement of cash flow hedge | | — |
| | (179 | ) | | 508 |
|
| Other comprehensive loss | | — |
| | (91 | ) | | (99 | ) |
| Comprehensive income before noncontrolling interest | | 186,387 |
| | 201,820 |
| | 157,491 |
|
| Allocation of net loss attributable to Predecessor | | — |
| | — |
| | 10,657 |
|
| Allocation of comprehensive income to noncontrolling interests | | (7,540 | ) | | (6,871 | ) | | (10,006 | ) |
| | | | | | | |
| Comprehensive income attributable to the partners | | $ | 178,847 |
| | $ | 194,949 |
| | $ | 158,142 |
|
See accompanying notes.
HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In (In thousands)
| | | | | Years Ended December 31, | | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | | 2021 | | 2020 | | 2019 |
| Cash flows from operating activities | | | | | | | Cash flows from operating activities | | | | | | |
| Net income | | $ | 186,387 |
| | $ | 201,911 |
| | $ | 157,590 |
| Net income | | $ | 225,863 | | | $ | 179,223 | | | $ | 233,096 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | Adjustments to reconcile net income to net cash provided by operating activities: | |
| Depreciation and amortization | | 98,492 |
| | 79,278 |
| | 70,428 |
| Depreciation and amortization | | 93,800 | | | 99,578 | | | 96,705 | |
| Gain on sale of assets | | (196 | ) | | (319 | ) | | (150 | ) | Gain on sale of assets | | (5,567) | | | (1,015) | | | (229) | |
| Remeasurement gain on preexisting equity interests | | — |
| | (36,254 | ) | | — |
| |
| Gain on sales-type lease | | Gain on sales-type lease | | (24,677) | | | (33,834) | | | (35,166) | |
| | Goodwill impairment | | Goodwill impairment | | 11,034 | | | 35,653 | | | — | |
| Amortization of deferred charges | | 3,041 |
| | 3,063 |
| | 3,247 |
| Amortization of deferred charges | | 3,757 | | | 3,319 | | | 3,081 | |
| Equity-based compensation expense | | 3,203 |
| | 2,520 |
| | 3,519 |
| Equity-based compensation expense | | 2,557 | | | 2,193 | | | 2,532 | |
Equity in earnings of equity method investments, net of distributions
| | (149 | ) | | 1,450 |
| | (2,032 | ) | Equity in earnings of equity method investments, net of distributions
| | — | | | 1,084 | | | (213) | |
| Loss on early extinguishment of debt | | — |
| | 12,225 |
| | — |
| Loss on early extinguishment of debt | | — | | | 25,915 | | | — | |
| (Increase) decrease in operating assets: | | | | | | | (Increase) decrease in operating assets: | |
| Accounts receivable—trade | | 471 |
| | (38 | ) | | 279 |
| Accounts receivable—trade | | 1,798 | | | 4,188 | | | (6,399) | |
| Accounts receivable—affiliates | | 4,715 |
| | (8,939 | ) | | (10,080 | ) | Accounts receivable—affiliates | | (8,182) | | | 1,744 | | | (2,930) | |
| Prepaid and other current assets | | (2,000 | ) | | 830 |
| | 1,598 |
| Prepaid and other current assets | | (255) | | | (1,272) | | | (372) | |
| Increase (decrease) in operating liabilities: | | | | | | | Increase (decrease) in operating liabilities: | |
| Accounts payable—trade | | (329 | ) | | (1,975 | ) | | (365 | ) | Accounts payable—trade | | 912 | | | 2,208 | | | 5,823 | |
| Accounts payable—affiliates | | 6,497 |
| | (8,699 | ) | | (16 | ) | Accounts payable—affiliates | | (6,417) | | | 1,383 | | | 2,515 | |
| Accrued interest | | 46 |
| | (4,813 | ) | | 11,317 |
| Accrued interest | | 366 | | | (2,314) | | | (96) | |
| Deferred revenue | | 1,862 |
| | (1,267 | ) | | 7,058 |
| Deferred revenue | | (1,144) | | | (4,122) | | | (151) | |
| Accrued property taxes | | (2,873 | ) | | (2,179 | ) | | 1,633 |
| Accrued property taxes | | 550 | | | 193 | | | 2,020 | |
| Other current liabilities | | (2,081 | ) | | 2,091 |
| | (553 | ) | Other current liabilities | | (724) | | | 200 | | | (220) | |
| Other, net | | (1,873 | ) | | (398 | ) | | 75 |
| Other, net | | 424 | | | 1,303 | | | (2,935) | |
| Net cash provided by operating activities | | 295,213 |
| | 238,487 |
| | 243,548 |
| Net cash provided by operating activities | | 294,095 | | | 315,627 | | | 297,061 | |
| | | | | | | | |
| Cash flows from investing activities | | | | | | | Cash flows from investing activities | |
| Additions to properties and equipment | | (47,300 | ) | | (44,810 | ) | | (59,704 | ) | Additions to properties and equipment | | (89,995) | | | (59,283) | | | (30,112) | |
| Business and asset acquisitions | | (5,051 | ) | | — |
| | (44,119 | ) | |
| Purchase of interest in Cheyenne Pipeline | | — |
| | — |
| | (42,627 | ) | |
| Purchase of controlling interests in SLC Pipeline and Frontier Aspen | | (1,790 | ) | | (245,446 | ) | | — |
| |
| Proceeds from sale of assets | | 210 |
| | 849 |
| | 427 |
| |
| | Purchase of interest in Cushing Connect Pipeline & Terminal | | Purchase of interest in Cushing Connect Pipeline & Terminal | | — | | | (2,438) | | | (17,886) | |
| Proceeds from sales of assets | | Proceeds from sales of assets | | 7,365 | | | 1,089 | | | 532 | |
| Distributions in excess of equity in earnings of equity investments | | 1,588 |
| | 3,134 |
| | 2,993 |
| Distributions in excess of equity in earnings of equity investments | | 4,165 | | | 882 | | | 1,206 | |
| | Net cash used for investing activities | | (52,343 | ) | | (286,273 | ) | | (143,030 | ) | Net cash used for investing activities | | (78,465) | | | (59,750) | | | (46,260) | |
| | | | | | | | |
| Cash flows from financing activities | | | | | | | Cash flows from financing activities | |
| Borrowings under credit agreement | | 337,000 |
| | 969,000 |
| | 554,000 |
| Borrowings under credit agreement | | 480,500 | | | 258,500 | | | 365,500 | |
| Repayments of credit agreement borrowings | | (426,000 | ) | | (510,000 | ) | | (713,000 | ) | Repayments of credit agreement borrowings | | (554,000) | | | (310,500) | | | (323,000) | |
| Redemption of 6.5% Senior Notes | | — |
| | (309,750 | ) | | — |
| |
| Proceeds from issuance of 6% Senior Notes | | — |
| | 101,750 |
| | 394,000 |
| |
| Proceeds from issuance of common units | | 114,771 |
| | 52,110 |
| | 125,870 |
| |
| Redemption of senior notes | | Redemption of senior notes | | — | | | (522,500) | | | — | |
| Proceeds from issuance of senior notes | | Proceeds from issuance of senior notes | | — | | | 500,000 | | | — | |
| | Contributions from general partner | | 882 |
| | 1,072 |
| | 2,577 |
| Contributions from general partner | | — | | | 988 | | | 320 | |
| Contribution from noncontrolling interests | | Contribution from noncontrolling interests | | 23,194 | | | 23,899 | | | 3,210 | |
| Distributions to HEP unitholders | | (264,979 | ) | | (234,575 | ) | | (192,037 | ) | Distributions to HEP unitholders | | (149,432) | | | (174,443) | | | (273,225) | |
| Distributions to noncontrolling interest | | (7,500 | ) | | (6,500 | ) | | (5,750 | ) | |
| Distribution to HFC for acquisitions | |
|
| | — |
| | (317,500 | ) | |
| Contributions from HFC for acquisitions | | — |
| | — |
| | 51,262 |
| |
| Contributions to HFC for El Dorado Operating Tanks | | — |
| | (103 | ) | | — |
| |
| Distributions to HFC for Osage acquisition | | — |
| | — |
| | (1,245 | ) | |
| Distributions to noncontrolling interests | | Distributions to noncontrolling interests | | (10,743) | | | (9,770) | | | (9,000) | |
| Payments on finance leases | | Payments on finance leases | | (3,549) | | | (3,602) | | | (2,471) | |
| Purchase of units for incentive grants | | — |
| | — |
| | (3,521 | ) | Purchase of units for incentive grants | | (1,958) | | | (698) | | | (1,470) | |
| Units withheld for tax withholding obligations | | (568 | ) | | (605 | ) | | (800 | ) | Units withheld for tax withholding obligations | | (590) | | | (334) | | | (423) | |
| Deferred financing costs | | 6 |
| | (9,382 | ) | | (3,995 | ) | Deferred financing costs | | (6,661) | | | (8,714) | | | — | |
| Other | | (1,213 | ) | | (1,112 | ) | | (1,735 | ) | |
| Net cash provided by (used for) financing activities | | (247,601 | ) | | 51,905 |
| | (111,874 | ) | |
| | Net cash used for financing activities | | Net cash used for financing activities | | (223,239) | | | (247,174) | | | (240,559) | |
| | | | | | | | | | | | | |
| Cash and cash equivalents | | | | | | | Cash and cash equivalents | |
| Increase (decrease) for the year | | (4,731 | ) | | 4,119 |
| | (11,356 | ) | Increase (decrease) for the year | | (7,609) | | | 8,703 | | | 10,242 | |
| Beginning of year | | 7,776 |
| | 3,657 |
| | 15,013 |
| Beginning of year | | 21,990 | | | 13,287 | | | 3,045 | |
| End of year | | $ | 3,045 |
| | $ | 7,776 |
| | $ | 3,657 |
| End of year | | $ | 14,381 | | | $ | 21,990 | | | $ | 13,287 | |
| | Supplemental disclosure of cash flow information: | | Supplemental disclosure of cash flow information: | |
| Cash paid during the period for interest | | Cash paid during the period for interest | | $ | 49,990 | | | $ | 58,138 | | | $ | 73,868 | |
See accompanying notes.
HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
| | | | | | | | | | | | | | | | | | | | |
| | | Common
Units | | Noncontrolling
Interests | | Total |
| Balance December 31, 2018 | | $ | 427,435 | | | $ | 88,126 | | | $ | 515,561 | |
| Capital contribution | | 320 | | | — | | | 320 | |
| Capital contribution-Cushing Connect | | — | | | 22,548 | | | 22,548 | |
| Distributions to HEP unitholders | | (273,225) | | | — | | | (273,225) | |
| Distributions to noncontrolling interests | | — | | | (9,000) | | | (9,000) | |
| Purchase of units for incentive grants | | (1,470) | | | — | | | (1,470) | |
| Amortization of restricted and performance units | | 2,532 | | | — | | | 2,532 | |
| Class B unit accretion | | (3,231) | | | — | | | (3,231) | |
| Other | | 627 | | | — | | | 627 | |
| Net income | | 228,115 | | | 4,981 | | | 233,096 | |
| Balance December 31, 2019 | | 381,103 | | | 106,655 | | | 487,758 | |
| Capital contribution-Cushing Connect | | — | | | 23,899 | | | 23,899 | |
| Capital contribution - Cheyenne | | 988 | | | — | | | 988 | |
| Distributions to HEP unitholders | | (174,443) | | | — | | | (174,443) | |
| Distributions to noncontrolling interests | | — | | | (9,770) | | | (9,770) | |
| Purchase of units for incentive grants | | (698) | | | — | | | (698) | |
| Amortization of restricted and performance units | | 2,193 | | | — | | | 2,193 | |
| Class B unit accretion | | (3,458) | | | — | | | (3,458) | |
| Other | | (334) | | | — | | | (334) | |
| Net income | | 173,941 | | | 5,282 | | | 179,223 | |
| Balance December 31, 2020 | | 379,292 | | | 126,066 | | | 505,358 | |
| Capital contribution - Cushing Connect | | — | | | 23,194 | | | 23,194 | |
| | | | | | |
| Distributions to HEP unitholders | | (149,432) | | | — | | | (149,432) | |
| Distributions to noncontrolling interests | | — | | | (10,743) | | | (10,743) | |
| Purchase of units for incentive grants | | (1,958) | | | — | | | (1,958) | |
| Amortization of restricted and performance units | | 2,557 | | | — | | | 2,557 | |
| Class B unit accretion | | (3,699) | | | — | | | (3,699) | |
| Other | | (2,388) | | | 1,797 | | | (591) | |
| Net income | | 218,645 | | | 7,218 | | | 225,863 | |
| Balance December 31, 2021 | | 443,017 | | | 147,532 | | | 590,549 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Holly Energy Partners, L.P. Partners’ Equity (Deficit): | | | | |
| | | Common Units | | General Partner Interest | | Accumulated Other Comprehensive Income/(Loss) | | Noncontrolling Interest | | Total |
| Balance December 31, 2015 | | $ | 428,019 |
| | $ | 103,584 |
| | $ | 190 |
| | $ | 94,429 |
| | $ | 626,222 |
|
| Issuance of common units | | 125,870 |
| | — |
| | — |
| | — |
| | 125,870 |
|
| Capital contribution | | — |
| | 2,577 |
| | — |
| | — |
| | 2,577 |
|
| Distributions to HEP unitholders | | (138,779 | ) | | (53,258 | ) | | — |
| | — |
| | (192,037 | ) |
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | (5,750 | ) | | (5,750 | ) |
| Contribution from HFC for acquisitions | | — |
| | 82,549 |
| | — |
| | — |
| | 82,549 |
|
| Distribution to HFC for acquisitions | | — |
| | (317,500 | ) | | — |
| | — |
| | (317,500 | ) |
| Purchase of units for incentive grants | | (3,521 | ) | | — |
| | — |
| | — |
| | (3,521 | ) |
| Amortization of restricted and performance units | | 3,519 |
| | — |
| | — |
| | — |
| | 3,519 |
|
| Class B unit accretion | | (6,250 | ) | | (128 | ) | | — |
| | — |
| | (6,378 | ) |
| Other | | (800 | ) | | (451 | ) | | — |
| | — |
| | (1,251 | ) |
| Net income | | 102,917 |
| | 49,795 |
| | — |
| | 4,878 |
| | 157,590 |
|
| Other comprehensive income | | — |
| | — |
| | (99 | ) | | — |
| | (99 | ) |
| Balance December 31, 2016 | | $ | 510,975 |
| | $ | (132,832 | ) | | $ | 91 |
| | $ | 93,557 |
| | $ | 471,791 |
|
| Issuance of common units | | 52,100 |
| | — |
| | — |
| | — |
| | 52,100 |
|
| Capital contribution | | — |
| | 1,072 |
| | — |
| | — |
| | 1,072 |
|
| Distributions to HEP unitholders | | (181,439 | ) | | (53,136 | ) | | — |
| | — |
| | (234,575 | ) |
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | (6,500 | ) | | (6,500 | ) |
| Distribution to HFC for acquisitions | | — |
| | (103 | ) | | — |
| | — |
| | (103 | ) |
| Amortization of restricted and performance units | | 2,520 |
| | — |
| | — |
| | — |
| | 2,520 |
|
| Class B unit accretion | | (2,780 | ) | | (42 | ) | | — |
| | — |
| | (2,822 | ) |
| Other | | (238 | ) | | — |
| | — |
| | — |
| | (238 | ) |
| Net income | | 162,815 |
| | 35,047 |
| | — |
| | 4,049 |
| | 201,911 |
|
| Equity restructuring transaction | | (149,994 | ) | | 149,994 |
| | — |
| | — |
| | — |
|
| Other comprehensive income | | — |
| | — |
| | (91 | ) | | — |
| | (91 | ) |
| Balance December 31, 2017 | | $ | 393,959 |
| | $ | — |
| | $ | — |
| | $ | 91,106 |
| | $ | 485,065 |
|
| Issuance of common units | | 114,771 |
| | — |
| | — |
| | — |
| | 114,771 |
|
| Distributions to HEP unitholders | | (264,979 | ) | | — |
| | — |
| | — |
| | (264,979 | ) |
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | (7,500 | ) | | (7,500 | ) |
| Amortization of restricted and performance units | | 3,203 |
| | — |
| | — |
| | — |
| | 3,203 |
|
| Class B unit accretion | | (3,020 | ) | | — |
| | — |
| | — |
| | (3,020 | ) |
| Other | | 1,634 |
| | — |
| | — |
| | — |
| | 1,634 |
|
| Net income | | 181,867 |
| | — |
| | — |
| | 4,520 |
| | 186,387 |
|
| Balance December 31, 2018 | | $ | 427,435 |
| | $ | — |
| | $ | — |
| | $ | 88,126 |
| | $ | 515,561 |
|
See accompanying notes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 20182021
| |
Note 1: | Description of Business and Summary of Significant Accounting Policies |
Note 1:Description of Business and Summary of Significant Accounting Policies
Holly Energy Partners, L.P. (“HEP”) together with its consolidated subsidiaries, is a publicly held master limited partnership. As of December 31, 2018,2021, HollyFrontier Corporation (“HFC”) and its subsidiaries own a 57% limited partner interest and the non-economic general partner interest in HEP. We commenced operations on July 13, 2004, upon the completion of our initial public offering. In these consolidated financial statements, the words “we,” “our,” “ours” and “us” refer to HEP unless the context otherwise indicates.
On October 31, 2017, we closed on an equity restructuring transaction with HEP Logistics Holdings, L.P. (“HEP Logistics”), a wholly-owned subsidiary of HFC and the general partner of HEP, pursuant to which the incentive distribution rights ("IDRs") held by HEP Logistics were canceled, and HEP Logistics' 2% general partner interest in HEP was converted into a non-economic general partner interest in HEP. In consideration, we issued 37,250,000 of our common units to HEP Logistics. In addition, HEP Logistics agreed to waive $2.5 million of limited partner cash distributions for each of twelve consecutive quarters beginning with the first quarter the units issued as consideration were eligible to receive distributions. As a result of this transaction, no distributions were made on the general partner interest after October 31, 2017.
On January 25, 2018, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,700,000 common units representing limited partner interests, at a price of $29.73 per common unit. The private placement closed on February 6, 2018, and we received proceeds of approximately $110 million, which were used to repay indebtedness under our revolving credit facility.
We own and operate petroleum product and crude oil pipelines, terminal, tankage and loading rack facilities and refinery processing units that support HFC’sthe refining and marketing operations of HFC and other refineries in the Mid-Continent, Southwest and Northwest regions of the United States and Delek US Holdings, Inc.’s (“Delek”) refinery in Big Spring, Texas.States. Additionally, we own a 75% interest in the UNEV Pipeline, LLC (“UNEV”), a 50% interestinterest in Osage Pipe Line Company, LLC (“Osage”), a 50% interest in Cheyenne Pipeline LLC, and a 50% interest in Cushing Connect Pipeline & Terminal LLC.
On June 1, 2020, HFC announced plans to permanently cease petroleum refining operations at its Cheyenne Pipeline LLC.refinery (the “Cheyenne Refinery”) and to convert certain assets at that refinery to renewable diesel production. HFC subsequently began winding down petroleum refining operations at the Cheyenne refinery on August 3, 2020.
On February 8, 2021, HEP and HFC finalized and executed new agreements for HEP’s Cheyenne assets with the following terms, in each case effective January 1, 2021: (1) a ten-year lease with 2 five-year renewal option periods for HFC’s use of certain HEP tank and rack assets in the Cheyenne refinery to facilitate renewable diesel production with an annual lease payment of approximately $5 million, (2) a five-year contango service fee arrangement that will utilize HEP tank assets inside the Cheyenne refinery where HFC will pay a base tariff to HEP for available crude oil storage and HFC and HEP will split any profits generated on crude oil contango opportunities and (3) a $10 million one-time cash payment from HFC to HEP for the termination of the existing minimum volume commitment.
On April 1, 2021, we sold our 156-mile, 6-inch refined product pipeline that connected HFC’s Navajo refinery to terminals in El Paso for gross proceeds of $7.0 million and recognized a gain on sale of $5.3 million.
We operate in two2 reportable segments, a Pipelines and Terminals segment and a Refinery Processing Unit segment. Disclosures around these segments are discussed in Note 15.16.
Our Pipelines and Terminals segment consists of:
•26 main pipeline segments
•Crude gathering networks in Texas and New Mexico
•10 refined product terminals
•1 crude terminal
•1 lube terminal
•31,800 track feet of rail storage located at two2 facilities
•7 locations with truck and/or rail racks
•Tankage at all six6 of HFC's refining and renewable diesel facility locations
Our Refinery Processing Unit segment consists of five5 refinery processing units at two2 of HFC's refining facility locations.
We generate revenues by charging tariffs for transporting petroleum products and crude oil through our pipelines, by charging fees for terminalling and storing refined products and other hydrocarbons, providing other services at our storage tanks and terminals and by charging fees for processing hydrocarbon feedstocks through our refinery processing units. We do not take ownership of products that we transport, terminal, store or process, and therefore, we are not exposed directly to changes in commodity prices.
Principles of Consolidation and Common Control Transactions
The consolidated financial statements include our accounts our Predecessor's (defined below) and those of subsidiaries and joint ventures that we control.control through an ownership interest greater than 50% or through a controlling financial interest with respect to variable interest entities. All
significant intercompany transactions and balances have been eliminated. Certain prior period balances have been reclassified for consistency with current year presentation.
Most of our acquisitions from HFC occurred while we were a consolidated variable interest entity of HFC. Therefore, as an entity under common control with HFC, we recorded these acquisitions on our balance sheets at HFC's historical basis instead of our purchase price or fair value. U.S. generally accepted accounting principles ("GAAP") require transfers of a business between entities under common control to be accounted for as though the transfer occurred as of the beginning of the period of transfer, and prior period financial statements and financial information are retrospectively adjusted to include the historical results and
assets of the acquisitions from HFC for all periods presented prior to the effective dates of each acquisition. We refer to the historical results of the acquisitions prior to their respective acquisition dates as those of our "Predecessor." Many of these transactions are cash purchases and do not involve the issuance of equity; however, GAAP requires the retrospective adjustment of financial statements. Therefore, in such transactions, the prior year balance sheet includes as equity the amount of cost incurred by HFC to that date.
Use of Estimates
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Cash and Cash Equivalents
For purposes of the statements of cash flows, we consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. The carrying amounts reported on the balance sheets approximate fair value due to the short-term maturity of these instruments.
Accounts Receivable
The majority of the accounts receivable are due from affiliates of HFC Delek or independent companies in the petroleum industry. Credit is extended based on evaluation of the customer's financial condition, and in certain circumstances, collateral such as letters of credit or guarantees, may be required. We reserve for doubtful accounts based on our historical loss experience as well as expected credit losses from current economic conditions and management’s expectations of future economic conditions. Credit losses are charged to incomethe allowance for doubtful accounts when accounts arean account is deemed uncollectible and historically have been minimal.
Properties and Equipment
Properties and equipment are stated at cost. Properties and equipment acquired from HFC while under common control of HFC are stated at HFC's historical basis. Depreciation is provided by the straight-line method over the estimated useful lives of the assets, primarily 15 to 25 years for terminal facilities and tankage, 25 to 3230 years for pipelines, 25 years for refinery processing units and 53 to 10 years for corporate and other assets. We depreciate assets acquired under capital leases over the lesser of the lease term or the economic life of the assets. Maintenance, repairs and minor replacements are expensed as incurred. Costs of replacements constituting improvements are capitalized.
Intangible Assets
Intangible assets include transportation agreements and acquired customer relationship intangible assets. Intangible assets are stated at acquisition date fair value and are being amortized over their useful lives using the straight-line method.
Goodwill and Long-Lived Assets
Goodwill represents the excess of our cost of an acquired business over the fair value of the assets acquired, less liabilities assumed. Goodwill is not amortized. We test goodwill at the reporting unit level for impairment annually and between annual tests if events or changes in circumstances indicate the carrying amount may exceed fair value. Our goodwill impairment testing first entails a comparison of our reporting unit fair values relative to their respective carrying values, including goodwill. If carrying value exceeds the estimated fair value for a reporting unit, we measure goodwill impairment as the excess of the carrying amount of the reporting unit goodwill over the impliedestimated fair value of that goodwill based on estimates of the fair value of all assets and liabilities in the reporting unit.
In 2018, we usedThe changes due to our new agreements with HFC related to our Cheyenne assets resulted in an increase in the presentnet book value of our Cheyenne reporting unit during the first quarter of 2021 due to sales-type lease accounting, which led us to determine indicators of potential goodwill impairment for our Cheyenne reporting unit were present. Therefore, we performed an interim quantitative review of our Cheyenne reporting unit goodwill for the first quarter of 2021.
The estimated fair value of our Cheyenne reporting unit was derived using a combination of income and market approaches. The income approach reflects expected future net cash flows based on anticipated gross margins, operating costs, and capital expenditures. The market multiple analyses to determineapproaches include both the estimatedguideline public company and guideline transaction methods. Both methods utilize pricing multiples derived from historical market transactions of other like-kind assets. These fair valuesvalue measurements involve significant unobservable inputs (Level 3 inputs). See Note 6 for further discussion of the reporting units. TheLevel 3 inputs.
Our interim impairment test requires the use of projections, estimates and assumptions as to the future performancetesting of our operations. Actual results could differ from projections resulting in revisions to our assumptions, and if required, could resultCheyenne reporting unit goodwill identified an impairment charge of $11.0 million, which was recorded in the recognitionthree months ended March 31, 2021.
Our annual goodwill impairment testing for 2021 and 2019 was performed on a qualitative basis during the third quarters of an impairment loss. In 2017, we2021 and 2019. We assessed qualitative factors such as macroeconomic conditions, industry considerations, cost factors and reporting unit financial performance and determined it was not more likely than not that the fair value of our reporting units were less than the respective carrying value. Therefore, in accordance with GAAP, further testing was not required.
Our annual impairment testing for 2020 was performed on a quantitative basis during the third quarter of 2020. The estimated fair value of our reporting units were derived using a combination of both income and market approaches as described above. Our annual testing of goodwill in 2020 identified an impairment charge of $35.7 million, which was recorded in the third quarter of 2020, related to our Cheyenne reporting unit.
The following is a summary of our goodwill balances:
| | | | | | | | | | | | | | |
| | December 31,
2021 | | December 31,
2020 |
| | | (In thousands) |
| Goodwill | | $ | 270,336 | | | $ | 270,336 | |
| Accumulated impairment losses | | (46,686) | | | (35,652) | |
| | $ | 223,650 | | | $ | 234,684 | |
We evaluate long-lived assets, including finitefinite-lived intangible assets, for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset'sasset’s carrying value exceeds its fair value.
There have been no impairments to goodwill or our long-lived assets through December 31, 2018.
Investment in Equity Method Investments
We account for our interests in noncontrolling joint venture interests using the equity method of accounting, whereby we record our pro-rata share of earnings of these companies, and contributions to and distributions from the joint ventures as adjustments to our investment balances. The difference between the cost of an investment and our proportionate share of the underlying equity in net assets recorded on the investee's books is allocated to the various assets and liabilities of the equity method investment.
The following table summarizes our recorded investments compared to our share of underlying equity for each investee. We are amortizing the differences as adjustments to our pro-rata share of earnings over the useful lives of the underlying assets of these joint ventures.
| | | | | | | | | | | | | | | | | | | | |
| | Balance at December 31, 2021 |
| | Underlying Equity | | Recorded Investment Balance | | Difference |
| | (In thousands) |
| Equity Method Investments | | | | | | |
| Osage Pipe Line Company, LLC | | $ | 9,996 | | | $ | 37,782 | | | $ | (27,786) | |
| Cheyenne Pipeline LLC | | 28,557 | | | 41,091 | | | (12,534) | |
| Cushing Connect Terminal Holdings LLC | | 52,203 | | | 37,505 | | | 14,698 | |
| Total | | $ | 90,756 | | | $ | 116,378 | | | $ | (25,622) | |
| | | | | Balance at December 31, 2018 | | Balance at December 31, 2020 |
| | | Underlying Equity | | Recorded Investment Balance | | Difference | | Underlying Equity | | Recorded Investment Balance | | Difference |
| | | (in thousands) | | (In thousands) |
| Equity Method Investments | | | | | | | Equity Method Investments | |
| Osage Pipe Line Company, LLC | | $ | 9,964 |
| | $ | 40,483 |
| | $ | (30,519 | ) | Osage Pipe Line Company, LLC | | $ | 10,044 | | | $ | 38,743 | | | $ | (28,699) | |
| Cheyenne Pipeline LLC | | 29,358 |
| | 43,357 |
| | (13,999 | ) | Cheyenne Pipeline LLC | | 29,103 | | | 42,345 | | | (13,242) | |
| Cushing Connect Terminal Holdings LLC | | Cushing Connect Terminal Holdings LLC | | 54,049 | | | 39,456 | | | 14,593 | |
| Total | | $ | 39,322 |
| | $ | 83,840 |
| | $ | (44,518 | ) | Total | | $ | 93,196 | | | $ | 120,544 | | | $ | (27,348) | |
|
| | | | | | | | | | | | |
| | | Balance at December 31, 2017 |
| | | Underlying Equity | | Recorded Investment Balance | | Difference |
| | | (in thousands) |
| Equity Method Investments | | | | | | |
| Osage Pipe Line Company, LLC | | $ | 10,631 |
| | $ | 42,071 |
| | $ | (31,440 | ) |
| Cheyenne Pipeline LLC | | 28,706 |
| | 43,208 |
| | (14,502 | ) |
| Total | | $ | 39,337 |
| | $ | 85,279 |
| | $ | (45,942 | ) |
Asset Retirement Obligations
We record legal obligations associated with the retirement of certain of our long-lived assets that result from the acquisition, construction, development and/or the normal operation of our long-lived assets. The fair value of the estimated cost to retire a tangible long-lived asset is recorded in the period in which the liability is incurred and when a reasonable estimate of the fair value of the liability can be made. For our pipeline assets, the right-of-way agreements typically do not require the dismantling, removal and reclamation of the right-of-way upon cessation of the pipeline service. Additionally, management is unable to predict when, or if, our pipelines and related facilities would become obsolete and require decommissioning. Accordingly, we have recorded no liability or corresponding asset related to an asset retirement obligation for the majority of our pipelines as both the amounts and timing of such potential future costs are indeterminable. For our remaining assets, at December 31, 20182021 and 2017,2020, we have asset retirement obligations of $8.9$8.7 million and $8.6$9.0 million,, respectively, that are recorded under “Other long-term liabilities” in our consolidated balance sheets.
Class B Unit
Under the terms of the transaction to acquire HFC's 75% interest in UNEV, we issued HFC a Class B unit comprising a noncontrolling equity interest in a wholly-owned subsidiary subject to redemption to the extent that HFC is entitled to a 50% interest in our share of annual UNEV earnings before interest, income taxes, depreciation, and amortization above $30 million beginning July 1, 2016,2015, and ending in June 2032, subject to certain limitations. Such contingent redemption payments are limited to the unredeemed value of the Class B Unit. However, to the extent earnings thresholds are not achieved, no redemption payments are required. No redemption payments have been required to date.
Contemporaneously with this transaction, HFC (our general partner) agreed to forego its right to incentive distributions of up to $1.25 million per quarter over twelve consecutive quarterly periods following the closing of the transaction and up to an additional
four quarters if HFC's Woods Cross refinery expansion did not attain certain thresholds. HEP Logistics' waiver of its right to incentive distributions of $1.25 million per quarter ended with the distribution paid in the third quarter of 2016.
Pursuant to the terms of the transaction agreements, the Class B unit increases by the amount of each foregone incentive distribution and by a 7% factor compounded annually on the outstanding unredeemed balance through its expiration date. At our option, we may redeem, in whole or in part, the Class B unit at the current unredeemed value based on the calculation described. The Class B unit had a carrying value of $46.2$56.5 million at December 31, 2018,2021, and $43.1$52.9 million at December 31, 2017.2020.
Revenue Recognition
Revenues are generally recognized as products are shipped through our pipelines and terminals, feedstocks are processed through our refinery processing units or other services are rendered. The majority of our contracts with customers meet the definition of a lease since (1) performance of the contracts is dependent on specified property, plant, or equipment and (2) it is remote that one or more parties other than the customer will take more than a minor amount of the output associated with the specified property, plant, or equipment. As a result,Prior to the adoption of the new lease standard (see below), we bifurcatebifurcated the consideration received between lease and service revenue. The service component is withinnew lease standard allows the scopeelection of a practical expedient whereby a lessor does not have to separate non-lease (service) components from lease components under certain conditions. The majority of our contracts meet these conditions, and we have made this election for those contracts. Under this practical expedient, we treat the combined components as a single performance obligation in accordance with Accounting Standards Codification (“ASC”) 606, which largely codified ASU 2014-09.2014-09, if the non-lease (service) component is the dominant component. If the lease component is the dominant component, we treat the combined components as a lease in accordance with ASC 842, which largely codified ASU 2016-02.
Several of our contracts include incentive or reduced tariffs once a certain quarterly volume is met. Revenue from the variable element of these transactions is recognized based on the actual volumes shipped as it relates specifically to rendering the services during the applicable quarter.
The majority of our long-term transportation contracts specify minimum volume requirements, whereby, we bill a customer for a minimum level of shipments in the event a customer ships below their contractual requirements. If there are no future performance obligations, we will recognize these deficiency payments in revenue.
In certain of these throughput agreements, a customer may later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum levels within its respective contractual shortfall make-up period. Such amounts represent an obligation to perform future services, which may be initially deferred and later recognized as revenue based on estimated future shipping levels, including the likelihood of a customer’s ability to utilize such amounts prior to the end of the contractual shortfall make-up period. We recognize the service portion of these deficiency payments in revenue when we do not expect we will be required to satisfy these performance obligations in the future based on the pattern of rights projected to be exercised by the customer.
Prior During the years ended December 31, 2021, 2020 and 2019, we recognized $17.5 million, $20.8 million and $16.0 million, respectively, of these deficiency payments in revenue, of which $0.5 million, $0.7 million and $0.6 million, respectively, related to the adoption of ASC 606 on January 1, 2018, billings to customers for their obligations under their quarterly minimum revenue commitments were recorded as deferred revenue liabilities if the customer had the right to receive future services for these billings. The revenue was recognized at the earlier of:
the customer receiving the future services provided by these billings,
the perioddeficiency payments billed in which the customer was contractually allowed to receive the services expired, or
our determination that we would not be required to provide services within the allowed period.
We determined that we would not be required to provide services within the allowed period when, based on current and projected shipping levels, our pipeline systems would not have the necessary capacity to enable a customer to exceed its minimum volume levels to such a degree as to utilize the shortfall credit within its respective contractual shortfall make-up period.
We have additional revenues under an operating lease to a third party of an interest in the capacity of one of our pipelines.
prior periods. As of December 31, 2018, customers' minimum2021, deferred revenue commitments per the terms of long-term throughput agreements expiringreflected in 2019 through 2036 and the third party operating lease require minimum annualized paymentsour consolidated balance sheet related to us in the aggregate of $2.3 billion including $356 million for the year ending December 31, 2019, $308 million for the year ending December 31, 2020, $298 million for the year ending December 31, 2021, $271 million for the year ending December 31, 2022 and $236 million for the year ending December 31, 2023. These agreements provide for changes in the minimum revenue guarantees annually for increases or decreases in the PPI or the FERC index, with certain contracts having provisions that limit the level of the rate increases or decreases.
shortfalls billed was $4.2 million.
We have other cost reimbursement provisions in our throughput / throughput/storage agreements providing that customers (including HFC) reimburse us for certain costs. Such reimbursements are recorded as revenue or deferred revenue depending on the nature of the cost. Deferred revenue is recognized over the remaining contractual term of the related throughput agreement.
Taxes billed and collected from our pipeline and terminal customers are recorded on a net basis with no effect on net income.
Leases
We adopted ASC 842 effective January 1, 2019, and elected to adopt using the modified retrospective transition method and practical expedients, both of which are provided as options by the standard and further defined below.
Lessee Accounting - At inception, we determine if an arrangement is or contains a lease. Right-of-use assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our payment obligation under the leasing arrangement. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We use our estimated incremental borrowing rate (“IBR”) to determine the present value of lease payments as most of our leases do not contain an implicit rate. Our IBR represents the interest rate which we would pay to borrow, on a collateralized basis, an amount equal to the lease payments over a similar term in a similar economic environment. We use the implicit rate when readily determinable.
Operating leases are recorded in operating lease right-of-use assets and current and noncurrent operating lease liabilities on our consolidated balance sheet. Finance leases are included in properties and equipment, current finance lease liabilities and noncurrent finance lease liabilities on our consolidated balance sheet.
When renewal options are defined in a lease, our lease term includes an option to extend the lease when it is reasonably certain we will exercise that option. Leases with a term of 12 months or less are not recorded on our balance sheet, and lease expense is accounted for on a straight-line basis. In addition, as a lessee, we separate non-lease components that are identifiable and exclude them from the determination of net present value of lease payment obligations.
Lessor Accounting - Customer contracts that contain leases are generally classified as either operating leases, direct finance leases or sales-type leases. We consider inputs such as the lease term, fair value of the underlying asset and residual value of the underlying assets when assessing the classification.
Environmental Costs
Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation, cleanup and other obligations are either known or considered probable and can be reasonably estimated. Such estimates require judgment with respect to costs, time frame and extent of required remedial and clean-up activities and are subject to periodic adjustments based on currently available information.
Under the Omnibus Agreement and certain transportation agreements and purchase agreements with HFC, HFC has agreed to indemnify us, subject to certain monetary and time limitations, for environmental noncompliance and remediation liabilities associated with certain assets transferred to us from HFC occurring or existing prior to the date of such transfers. We have an
environmental agreement with Delek with respect to pre-closing environmental costs and liabilities relating to the pipelines and terminals acquired from Delek in 2005, under which Delek will indemnify us subject to certain monetary and time limitations. Environmental costs recoverable through insurance, indemnification agreements or other sources are included in other assets to the extent such recoveries are considered probable.
Income Tax
We are subject to the Texas margin tax that is based on our Texas sourced taxable margin. The tax is calculated by applying a tax rate to a base that considers both revenues and expenses and therefore has the characteristics of an income tax.
We are organized as a pass-through entity for U.S. federal income tax purposes. As a result, our partners are responsible for U.S. federal income taxes based on their respective share of taxable income.
Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.
Net Income per Limited Partners' Unit
We use the two-class method when calculating the net income per unit applicable to limited partners since we had more than one class of participating securities prior to the October 31, 2017 equity restructuring transaction discussed above. Under the two-class method, net income per unit applicable to limited partners is computed by dividing limited partners' interest in net income, after adjusting for the allocation of net income or loss attributable to the Predecessor, the allocation of net income or loss attributable to noncontrolling interests and the general partner's 2% interest and incentive distributions, both of which were applicable prior to the October 31, 2017 equity restructuring transaction discussed above, and other participating securities, by the weighted-average number of common units outstanding during the year and other dilutive securities. Other participating securities and dilutive securities are not significant.
Accounting Pronouncement Adopted During the Periods Presented
Revenue RecognitionGoodwill Impairment Testing
In May 2014, an accounting standard updateJanuary 2017, Accounting Standard Update (“ASU”) 2017-04, “Simplifying the Test for Goodwill Impairment,” was issued requiring revenue to be recognized when promised goods or services are transferred to customers in anamending the testing for goodwill impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measured a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that reflectsgoodwill. Under this standard, goodwill impairment is measured as the expected consideration for these goods or services. This standard had an effective date of January 1, 2018, and we accounted for the new guidance using the modified retrospective implementation method, whereby a cumulative effect adjustment was recorded to retained earnings asexcess of the datecarrying amount of initial application. In preparing forthe reporting unit over the related fair value. We adopted this standard effective in the second quarter of 2019, and the adoption we evaluated the terms, conditions and performance obligations under our existing contracts with customers. Furthermore, we implemented policies to comply withof this new standard. See above and Note 3 for additional information on our revenue recognition policies.
Business Combinations
In December 2014, an accounting standard update was issued to provide new guidance on the definition of a business in relation to accounting for identifiable intangible assets in business combinations. This standard had an effective date of January 1, 2018, and had no effect on our financial condition, results of operations or cash flows.flows for the year ended December 31, 2019.
Financial Assets and Liabilities
In January 2016, an accounting standard update was issued requiring changes in the accounting and disclosures for financial instruments. This standard was effective beginning with our 2018 reporting year and had no effect on our financial condition, results of operations or cash flows.
Accounting Pronouncements Not Yet Adopted
Leases
In February 2016, an accounting standard updateASU No. 2016-02, “Leases” (“ASC 842”) was issued requiring leases to be measured and recognized as a lease liability, with a corresponding right-of-use asset on the balance sheet. ThisWe adopted this standard has an effective date of January 1, 2019, and we planelected to applyadopt using the modified retrospective transition method, whereby comparative prior period financial information will not be restated and will continue to be reported under the lease accounting standard in effect during those periods. We also elected practical expedients provided in the standards update that allow us, among other things, not to reassess contracts that commenced prior to the adoption. The primary effect of adoptingby the new standard, will beincluding the package of practical expedients and the short-term lease recognition practical expedient, which allows an entity to recordnot recognize on the balance sheet leases with a term of 12 months or less. Upon adoption of this standard, we recognized $78.4 million of lease liabilities and corresponding right-of-use assets and obligations for current operating leases on our consolidated balance sheet. See Notes 4 and 5 of Notes to the Consolidated Financial Statements for additional information on our lease policies.
Credit Losses Measurement
In June 2016, ASU 2016-13, “Measurement of Credit Losses on Financial Instruments,” was issued requiring measurement of all expected credit losses for certain types of financial instruments, including trade receivables, held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. This standard was effective January 1, 2020. Adoption of the standard isdid not expected to have a material impact on our financial condition, results of operations or cash flows.
Accounting Pronouncements - Not Yet Adopted
In preparingOctober 2021, Accounting Standards Update 2021-08, “Accounting for Contract Assets and Contract Liabilities from Contracts with Customers” was issued requiring that an acquiring entity recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Accounting Standards Codification (“ASC”) 606 – Revenue from Contracts with Customers. This standard is effective for fiscal years beginning after December 15, 2022, and early adoption we have identified, reviewedis permitted. We will evaluate the impact of this standard and evaluated contracts containing lease and embedded lease arrangements. Additionally, we have acquired and implemented software and systems to facilitate lease capture and related accounting treatment.consider early adoption, if applicable.
OsageNote 2:Sinclair Acquisition
HEP Transaction
On February 22, 2016, HFC obtained a 50% membership interest in Osage in a non-monetary exchange for a 20-year terminalling services agreement, whereby a subsidiary of Magellan Midstream PartnersAugust 2, 2021, HEP, The Sinclair Companies (“Magellan”Sinclair”) will provide terminalling services for all HFC products originating in Artesia, New Mexico requiring terminalling in or through El Paso, Texas. Osage is the owner of the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to HFC’s El Dorado Refinery in Kansas and also connects to the Jayhawk pipeline serving the CHS Inc. refinery in McPherson, Kansas. The Osage Pipeline is the primary pipeline supplying HFC’s El Dorado refinery with crude oil.
Concurrent with this transaction, we entered into a non-monetary exchange with HFC, whereby we received HFC’s interest in Osage in exchange for our El Paso terminal. Under this exchange, we agreed to build two connections on our south products pipeline system that permit HFC access to Magellan’s El Paso terminal. These connections were in service in the fourth quarter of 2017. Effective upon the closing of this exchange, we are the named operator of the Osage Pipeline and transitioned into that role on September 1, 2016. Since we are a consolidated variable interest entity ("VIE") of HFC, this transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basis of its 50% membership interest in Osage of $44.5 million offset by our net carrying basis in the El Paso terminal of $12.1 million with the difference recorded as a contribution from HFC. However, since these transactions were concurrent, there was no impact on periods prior to February 22, 2016.
Tulsa Tanks
On March 31, 2016, we acquired crude oil tanks (the "Tulsa Tanks") located at HFC’s Tulsa refinery from an affiliate of Plains All American pipeline, L. P. ("Plains") for cash consideration of $39.5 million. In 2009, HFC sold these tanks to Plains and leased them back, and due to HFC’s continuing interest in the tanks, HFC accounted for the transaction as a financing arrangement. Accordingly, the tanks remained on HFC’s balance sheet and were depreciated for accounting purposes. As we are a consolidated VIE of HFC, this transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basis in the net assets acquired.
Cheyenne Pipeline
On June 3, 2016, we acquired a 50% interest in Cheyenne Pipeline LLC, owner of the Cheyenne pipeline, in exchange for a contribution of $42.6 million in cash to Cheyenne Pipeline LLC. Cheyenne Pipeline LLC is operated by an affiliate of Plains, which owns the remaining 50% interest. The 87-mile crude oil pipeline runs from Fort Laramie to Cheyenne, Wyoming and has an 80,000 barrel per day (“bpd”) capacity.
Woods Cross Operating
Effective October 1, 2016, we acquired all the membership interests of Woods Cross Operating LLC (“Woods Cross Operating”),Sinclair Transportation Company, a wholly owned subsidiary of Sinclair (“STC”), entered into a Contribution Agreement (the “Contribution Agreement”) pursuant to which HEP will acquire all of the outstanding shares of STC in exchange for 21 million newly issued common units of HEP and cash consideration equal to $325 million (the “HEP Transaction”). On the same date, HFC, Sinclair and certain other parties entered into a Business Combination Agreement pursuant to which Sinclair will contribute all of the equity interests of Hippo Holding LLC, which owns Sinclair Oil Corporation, to a new HFC parent holding company that will be named “HF Sinclair Corporation” in exchange for 60,230,036 shares of common stock in HF Sinclair Corporation (the “HFC Transaction”, and together with the newly constructed atmospheric distillation tower, fluid catalytic cracking unit, and polymerization unit located at HFC’s Woods Cross refinery, forHEP Transaction, the “Sinclair Transactions”).
The cash consideration for the HEP Transaction is subject to customary adjustments at closing for working capital of $278 million.STC. The consideration was funded with $103 million in proceeds from a private placementnumber of 3,420,000HEP common units to be issued to Sinclair at closing is subject to downward adjustment if, as a condition to obtaining antitrust clearance for the Sinclair Transactions, HEP agrees to divest a portion of its equity interest in UNEV Pipeline, LLC and the sales price for such interests does not exceed the threshold provided in the Contribution Agreement.
The Contribution Agreement contains customary representations, warranties and covenants of HEP, Sinclair, and STC. The HEP Transaction is expected to close in 2022, subject to the satisfaction or waiver of certain customary conditions, including, among others, the receipt of certain required regulatory consents and clearance, including the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (the “HSR Act”), and the consummation of the HFC Transaction. On August 23, 2021, each of HFC and Sinclair filed its respective premerger notification and report regarding the Sinclair Transactions with the balance funded with borrowingsU.S. Department of Justice and the U.S. Federal Trade Commission (the “FTC”) under our credit facility. Inthe HSR Act. On September 22, 2021, HFC and Sinclair each received a request for additional information and documentary material (“Second Request”) from the FTC in connection with this transaction, wethe FTC’s review of the Sinclair Transactions. Issuance of the Second Request extends the waiting period under the HSR Act until 30 days after both HFC and Sinclair have substantially complied with the Second Request, unless the waiting period is terminated earlier by the FTC or the parties otherwise commit not to close the Sinclair Transactions for some additional period of time. HFC and Sinclair are cooperating with the FTC staff in its review and are working diligently to satisfy the closing conditions as soon as possible.
The Contribution Agreement automatically terminates if the HFC Transaction is terminated, and contains other customary termination rights, including a termination right for each of HEP and Sinclair if, under certain circumstances, the closing does not occur by May 2, 2022 (the “Outside Date”), except that the Outside Date can be extended by either party by up to 2 90 day periods to obtain any required antitrust clearance.
Upon closing of the HEP Transaction, HEP’s existing senior management team will continue to operate HEP. Under the definitive agreements, Sinclair will be granted the right to nominate 1 director to the HEP board of directors at the closing. The Sinclair stockholders have also agreed to certain customary lock-up restrictions and registration rights for the HEP common units to be issued to the stockholders of Sinclair. HEP will continue to operate under the name Holly Energy Partners, L.P.
See Note 12 for a description of the Letter Agreement between HFC and HEP entered into 15-year tolling agreements containing minimum quarterly throughput commitments from HFC that provide minimum annualized revenues of $57 million as ofin connection with the acquisition date. As we are a consolidated VIE of HFC, this transaction was recorded as a transfer between entities under common control and reflect HFC’s carrying basisContribution Agreement.
Note 3:Investment in the net assets acquired.Joint Venture
SLC Pipeline and Frontier Aspen
On October 31, 2017,2, 2019, HEP Cushing LLC (“HEP Cushing”), a wholly-owned subsidiary of HEP, and Plains Marketing, L.P. (“PMLP”), a wholly-owned subsidiary of Plains All American Pipeline, L.P. (“Plains”), formed a 50/50 joint venture, Cushing Connect Pipeline & Terminal LLC (the “Cushing Connect Joint Venture”), for (i) the development and construction of a new 160,000 barrel per day common carrier crude oil pipeline (the “Cushing Connect Pipeline”) that connected the Cushing, Oklahoma crude oil hub to the Tulsa, Oklahoma refining complex owned by a subsidiary of HFC and (ii) the ownership and operation of 1.5 million barrels of crude oil storage in Cushing, Oklahoma (the “Cushing Connect JV Terminal”). The Cushing Connect JV Terminal went in service during the second quarter of 2020, and the Cushing Connect Pipeline was placed into service during the third quarter of 2021. Long-term commercial agreements were entered into to support the Cushing Connect Joint Venture assets.
The Cushing Connect Joint Venture contracted with an affiliate of HEP to manage the construction and operation of the Cushing Connect Pipeline and with an affiliate of Plains to manage the operation of the Cushing Connect JV Terminal. The total Cushing Connect Joint Venture investment will generally be shared equally among the partners. However, we acquiredare solely responsible for any Cushing Connect Pipeline construction costs that exceed the remaining 75%budget by more than 10%. HEP estimates its share of the cost of the Cushing Connect JV Terminal contributed by Plains and Cushing Connect Pipeline construction costs are approximately $70 million to $75 million, including $4 million to $6 million of Cushing Connect Pipeline construction costs exceeding the budget by more than 10% to be borne solely by HEP.
The Cushing Connect Joint Venture legal entities are variable interest entities (“VIEs”) as defined under GAAP. A VIE is a legal entity if it has any one of the following characteristics: (i) the entity does not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support; (ii) the at risk equity holders, as a group, lack the characteristics of a controlling financial interest; or (iii) the entity is structured with non-substantive voting rights. The Cushing Connect Joint Venture legal entities did not have sufficient equity at risk to finance their activities without additional financial support. Since HEP constructed and is operating the Cushing Connect Pipeline, HEP has more ability to direct the activities that most significantly impact the financial performance of the Cushing Connect Joint Venture and Cushing Connect Pipeline legal entities. Therefore, HEP consolidates those legal entities. We do not have the ability to direct the activities that most significantly impact the Cushing Connect JV Terminal legal entity, and therefore, we account for our interest in SLC Pipeline LLC ("SLC Pipeline") and the remaining 50% interest in Frontier Aspen LLC ("Frontier Aspen") from subsidiariesCushing Connect JV Terminal legal entity using the equity method of Plains, for cash consideration of $250 million. Prioraccounting. HEP's maximum exposure to this acquisition, we held noncontrolling interests of 25% of SLC Pipeline and 50% of Frontier Aspen. Asloss as a result of its involvement with the acquisitions, SLC Pipeline and Frontier Aspen are wholly-owned subsidiaries of HEP.
These acquisitions were accounted for as a business combination achieved in stages. Our preexisting equity method investments in SLC Pipeline and Frontier Aspen were remeasured at an acquisition date fair value of $112 million since we now have a controlling interest, and we recognized a gain on the remeasurement in the fourth quarter of 2017 of $36.3 million. The fair value of our preexisting equity method investments in SLC Pipeline and Frontier Aspen was estimated using Level 3 Inputs under the income method for these entities, adjusted for lack of control and marketability.
The total consideration of $363.8 million, consisting of cash consideration of $250 million, working capital adjustments of $1.8 million and the fair value of our preexisting equity method investments in SLC Pipeline and Frontier Aspen of $112 million, was allocatedCushing Connect JV Terminal legal entity is not expected to be material due to the acquisition date fair value of assets and liabilities acquired aslong-term terminalling agreements in place to support its operations.
With the exception of the October 31, 2017 acquisition date, with the excess purchase price recorded as goodwill.
The following summarizes the final estimated valueassets of assets and liabilities acquired:
|
| | | |
| | (in thousands) |
| Cash and cash equivalents | $ | 4,609 |
|
| Accounts receivable | 5,164 |
|
| Prepaid and other current assets | 8 |
|
| Properties and equipment | 275,061 |
|
| Intangible assets | 70,182 |
|
| Goodwill | 13,845 |
|
| Accounts payable | (3,598 | ) |
| Accrued property taxes | (1,438 | ) |
| Net assets acquired | $ | 363,833 |
|
During 2018, goodwill was increased by $3.6 million in connection with our finalization of preliminary estimates recorded in 2017 for the purchase price allocation.
Our consolidated financial and operating results reflect the SLC Pipeline and Frontier Aspen operations beginning November 1, 2017. Our results of operations for the year ended December 31, 2017 included revenues of $7.9 million and net income of $4.1 million, excluding the $36.3 million remeasurement gain asHEP Cushing, creditors of the acquisition date discussed above, forCushing Connect Joint Venture legal entities have no recourse to our assets. Any recourse to HEP Cushing would be limited to the period from November 1, 2017 through December 31, 2017.
SLC Pipeline isextent of HEP Cushing's assets, which other than its investment in Cushing Connect Joint Venture, are not significant. Furthermore, our creditors have no recourse to the owner of a 95-mile crude pipeline that transports crude oil into the Salt Lake City area from the Utah terminalassets of the Frontier Pipeline (defined below) and from Wahsatch Station. Frontier Aspen is the owner of a 289-mile crude pipeline from Casper, Wyoming to Frontier Station, Utah (the "Frontier Pipeline") that supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.Cushing Connect Joint Venture legal entities.
The following unaudited pro forma financial information combines the historical operations of HEP, SLC Pipeline and Frontier Aspen as if the acquisition had occurred on January 1, 2016:
|
| | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 |
| | | (in thousands) |
| Revenues | | $ | 489,382 |
| | $ | 445,017 |
|
| Net income attributable to the partners | | $ | 161,900 |
| | $ | 162,862 |
|
The unaudited pro forma net income attributable to the partners reflects the following adjustments:
| |
(1) | To retrospectively reflect depreciation and amortization of intangible assets based on the preliminary fair value of the assets as if that fair value had been reflected January 1, 2016; |
| |
(2) | To eliminate HEP's equity income previously recorded on its equity method investments in SLC Pipeline and Frontier Aspen; and |
| |
(3) | To eliminate the remeasurement gain on preexisting equity interests in SLC Pipeline and Frontier Aspen. |
Effective January 1, 2018, as described in Note 1, we adopted ASC 606, using the modified retrospective method, whereby the cumulative effect of applying the new standard was recorded as an adjustment to the opening balance of retained earnings as well as the carrying amounts of assets and liabilities as of January 1, 2018, which had no impact on our cash flows. The following table reflects the cumulative effect of adoption as of January 1, 2018:
|
| | | | | | | | | | | | |
| | | Prior to Adoption | | Increase (Decrease) | | As Adjusted |
| | | (In thousands) |
| Deferred revenue | | $ | 9,598 |
| | $ | (1,320 | ) | | $ | 8,278 |
|
| Partners’ equity: Common unitholders | | $ | 393,959 |
| | $ | 1,320 |
| | $ | 395,279 |
|
Revenues are generally recognized as products are shipped through our pipelines and terminals, feedstocks are processed through our refinery processing units or other services are rendered. The majoritySee Note 1 for further discussion of revenue recognition.
Disaggregated revenues are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| | (In thousands) |
| Pipelines | | $ | 263,110 | | | $ | 265,834 | | | $ | 292,631 | |
| Terminals, tanks and loading racks | | 142,267 | | | 151,692 | | | 160,467 | |
| Refinery processing units | | 89,118 | | | 80,322 | | | 79,679 | |
| | $ | 494,495 | | | $ | 497,848 | | | $ | 532,777 | |
Affiliates and third parties revenues on our contracts with customers meet the definitionconsolidated statements of a lease since (1) performanceincome were composed of the contracts is dependent on specified property, plant, or equipment and (2) it is remote that one or more parties other than the customer will take more than a minor amount of the output associated with the specified property, plant, or equipment. Therefore, we bifurcate the consideration received betweenfollowing lease and service revenue. The service component is within the scope of ASC 606, which largely codified ASU 2014-09.revenues:
Several of our contracts include incentive or reduced tariffs once a certain quarterly volume is met. Revenue from the variable element of these transactions is recognized based on the actual volumes shipped as it relates specifically to rendering the services during the applicable quarter.
The majority of our long-term transportation contracts specify minimum volume requirements, whereby, we bill a customer for a minimum level of shipments in the event a customer ships below their contractual requirements. If there are no future performance obligations, we will recognize these deficiency payments in revenue.
In certain of these throughput agreements, a customer may later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum levels within its respective contractual shortfall make-up period. Such amounts represent an obligation to perform future services, which may be initially deferred and later recognized as revenue based on estimated future shipping levels, including the likelihood of a customer’s ability to utilize such amounts prior to the end of the contractual shortfall make-up period. We recognize the service portion of these deficiency payments in revenue when we do not expect we will be required to satisfy these performance obligations in the future based on the pattern of rights exercised by the customer. During the twelve months ended December 31, 2018, 2017 and 2016, we recognized $17.6 million, $11.9 million and $10.5 million, respectively, of these deficiency payments in revenue, of which $3.3 million, $5.6 million and $7.8 million, respectively, related
to deficiency payments billed in prior periods. As of December 31, 2018, deferred revenue reflected in our consolidated balance sheet related to shortfalls billed was $1.8 million. | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| | (In thousands) |
| Lease revenues | | $ | 336,062 | | | $ | 360,598 | | | $ | 378,311 | |
| Service revenues | | 158,433 | | | 137,250 | | | 154,466 | |
| | $ | 494,495 | | | $ | 497,848 | | | $ | 532,777 | |
A contract liability exists when an entity is obligated to perform future services to a customer for which the entity has received consideration. Since HEP may be required to perform future services for these deficiency payments received, the deferred revenues on our balance sheet as of December 31, 2018sheets were considered contract liabilities. A contract asset exists when an entity has a right to consideration in exchange for goods or services transferred to a customer. Our consolidated balance sheet as of December 31, 2018,sheets included the contract assets and liabilities in the table below.
| | | | | | | | | | | | | | |
| | December 31,
2021 | | December 31,
2020 |
| | | (In thousands) |
| Contract assets | | $ | 6,637 | | | $ | 6,306 | |
| Contract liabilities | | $ | (4,185) | | | $ | (500) | |
|
| | | | | | | | |
| | | December 31,
2018 | | January 1,
2018 |
| | | (In thousands) |
| Contract assets | | $ | 1,818 |
| | $ | — |
|
| Contract liabilities | | $ | (1,821 | ) | | $ | (2,713 | ) |
The contract assets and liabilities include both lease and service components. WeDuring the years ended December 31, 2021 and 2020, we recognized $2.7$0.5 million and $0.7 million, respectively, of revenue that was previously included in contract liability as of January 1, 2018, duringDecember 31, 2020 and 2019, respectively. During the twelve months ended December 31, 2018.2021, 2020 and 2019, we also recognized $0.3 million and $0.6 million and $3.9 million, respectively, of revenue included in contract assets at December 31, 2021.
As of December 31, 2018,2021, we expect to recognize $2.3$1.6 billion in revenue related to our unfulfilled performance obligations under the terms of our long-term throughput agreements and operating leases expiring in 20192022 through 2036. These agreements provide for changes in the minimum revenue guarantees annually for increases or decreases in the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”) index, with certain contracts having provisions that limit the level of the rate increases or decreases. We expect to recognize revenue for these unfulfilled performance obligations as shown in the table below (amounts shown in table include both service and lease revenues):
| | | Years Ending December 31, | | (In millions) | Years Ending December 31, | | (In millions) |
| 2019 | | $ | 356 |
| |
| 2020 | | 308 |
| |
| 2021 | | 298 |
| |
| 2022 | | 271 |
| 2022 | | 312 | |
| 2023 | | 236 |
| 2023 | | 275 | |
| 2024 | | 2024 | | 238 | |
| 2025 | | 2025 | | 172 | |
| 2026 | | 2026 | | 157 | |
| Thereafter | | 838 |
| Thereafter | | 484 | |
| Total | | $ | 2,307 |
| Total | | $ | 1,638 | |
Payment terms under our contracts with customers are consistent with industry norms and are typically payable within 10 to 30 days of the date of invoice.