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.
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 2017)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.
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, 2017, Delek accounted for 8% 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, 2017,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 $1,512 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, 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 institutionalsuppliers;
•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or•market-related increases 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 newa 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 pipeline 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 strict 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 EPA and the Corps have proposed to repeal the May 2015 rule and have separately announced their intention to issue a revised rule defining the scope of the CWA's jurisdiction. The agencies have also issued a stay delaying implementation of the rule for two years. To the extent any final rule on the scope of the CWA expands jurisdictional waters, 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 but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. 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 2018. 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.
GrowingWe 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.
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 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. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders 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 on our true costs or may delay the use of rates that reflect increased costs. On October 20, 2016, the FERC issued an Advance Notice of Proposed Rulemaking regarding Revisions to Indexing Policies and Page 700 of FERC Form No. 6, 157 FERC ¶ 61, 047 (2016) (“ANOPR”). If final rules are implemented as proposed in that ANOPR, such rules would create new tests for whether our pipelines providing service subject to FERC tariffs could increase rates in accordance with the FERC index in a given year and could restrict our ability to increase our rates as a result, in addition to increasing our annual reporting burdens and the associated costs. Any of the foregoing would adversely affect our revenues andmake cash flow.
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. Also relevantdistributions to our rates and cost of service, on December 15, 2016, the FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs, 157 FERC ¶ 61,210 (2016) (the “NOI”). The NOI sought comments on how the FERC should address any double recovery for partnership pipelines resulting from the FERC’s current income tax allowance and rate of return policies. If the NOI results in final regulations or policy changes that alter the FERC’s current approach to liquids pipeline ratemaking and the relevant components of our interstate pipeline transportation rates, those changes could require us to change our rate design and potentially lower our rates. 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.unitholders.
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 realize 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 to 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 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 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 rescind 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 to us and may adversely affect our business, financial position, results of operations and cash flows. Relatedly, the defense or settlement of any lawsuit or claim that remains unresolved at the time the Sinclair Transactions are completed may adversely affect our business, financial condition, results of operations and cash flows and 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 encountered 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 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 difficulties in the integration process could adversely affect our business, financial results, financial condition and common unit price. Even if we are able to integrate our business operations successfully, there can be no assurance that this integration will result in the realization of the full benefits of synergies, cost savings, innovation and operational efficiencies that we currently expect or have communicated from this integration or that these benefits will be achieved within the anticipated time frame.
RISKS RELATED TO GOVERNMENT REGULATION
Our operations are subject to evolving federal, state and local laws, regulations and permit/authorization requirements regarding our business, capital projects atand environmental protection, health, operational safety and product quality. Potential liabilities arising from these laws, regulations and requirements could affect our operations and have a material adverse effect on our business.
Our pipelines and terminal, tankage and loading rack operations are subject to increasingly stringent federal, state, and local laws, 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 have raised operating costs for the oil and refined products 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 more stringent requirements on our assets and operations and require us to incur potentially material expenditures to comply. Failure to comply with any applicable laws, regulations, and requirements 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 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. 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 result 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 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 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 expectedrates 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 a timely manner, ifrates. 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 incur increased maintenanceare 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 repairby 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 on assets, or if the market conditions assumedand our ability to recover any increases in our project economics deteriorate,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 flowsflows.
Cyberattacks or security breaches could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and increased maintenance or repair expenditureshave a material adverse effect on our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of numerous factors, such as:
denial or delay in issuing requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
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) affecting 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 complete capital projects at their expected costs or in a timely manner ourbusiness, financial condition, results of operations or cash flows could be materially and adversely affected.flows.
We do not own all of the land on which our pipelineOur 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, are located,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 disruptions to our operations. Additionally, a change in the regulations related to a state’s usetheft or loss of eminent domain could inhibitthe stored information, misappropriation of assets, disruption of transactions and reporting functions, our ability to secure rights-of-wayprotect 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 future pipeline construction projects. Finally, certaincyberattacks, data breaches or unauthorized access of our assetsinformation 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 located on tribal lands.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.
WeThe 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 own allcollect 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 land on whichcosts 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 systemsowners to comply with mandatory reporting measures, including, among other things, to appoint personnel, report confirmed and other assets are located, and we are, therefore, subjectpotential cybersecurity incidents to the risk of increased costs or more burdensome termsDHS Cybersecurity and Infrastructure Security Agency (“CISA”) and provide vulnerability assessments. As legislation continues to maintain necessary land use. We obtain the rightdevelop and cyber incidents continue 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,evolve, we may be required to relocateexpend 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 couldand 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 adversely affected. Additionally, it may become more expensive for usable to obtain new rights-of-wayfunding on acceptable terms or leasesat 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 renew existing rights-of-way or leases. Iftime 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 renewing such agreements increases, itat 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 operationsbusiness.
We use both fixed and variable rate debt, and we are exposed to market risk due to 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 and other projects.
Certain offloating interest rates on 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.credit facility. 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 from federal, state and local statutes and regulations. Following a recent 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, 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 businessrates on Native American tribal lands.
Our business may suffer due to a change in the composition 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, 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 operationsdebt offerings could be materially adversely affected. We do not maintain any “key man” life insurance for any executives. Furthermore,higher, causing our operations require skilled and experienced laborers with proficiency in multiple tasks.
Our general partner shares officers and administrative personnel with HFCfinancing costs 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 ourincrease accordingly. Our results of operations, cash flows and financial condition.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 HFC's employeesour 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 secondednot transitioned to usa 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 timeoperations, 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 timepay 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 representedbeyond 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 labor unionsour 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 collective bargaining agreements with various expiration dates. HFC may notits 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 renegotiatemake comparably profitable arrangements with other customers.
Mergers among our existing customers could provide strong economic incentives for the collective bargaining agreements when they expirecombined 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 satisfactory termstheir obligations, our financial results could be adversely affected. Furthermore, some of our or at all. A failureour joint ventures' customers may be highly leveraged and subject to do so may increase our costs.their own operating and regulatory risks. In addition, existing labor agreements may not preventnonperformance 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 future strike or work stoppage, and any work stoppage could negatively affectmaterial 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.
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 be factors in credit evaluations of us as a master limited partnership due to the significant influence of our general partner and its indirect ownership over our business activities, including our cash distribution policy, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition.condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.
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 indirectly ownsand 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 will beis 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, 2017,2021, HEP has issued 2.22.4 million units under this program for gross consideration of $77$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, 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 proposals that would eliminate our ability to qualify for partnership tax treatment.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. AlthoughThere can be no assurance that there is no current legislative proposal, a prior legislative proposal would have eliminatedwill not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income exceptionrules in a manner that could impact our ability to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatmentqualify as a partnership for federal income tax purposes.
We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changesin 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.
On January 24, 2017, the U.S. Treasury Department and the IRS published final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for federal income tax purposes.
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 and 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. Further, with respect to taxable years beginning after December 31, 2017, 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.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. The U.S. Department of the Treasury adopted final Treasury Regulations allowingallow 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, Arizona, 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.
| |
Item 1B. | Unresolved Staff Comments |
Item 1B.Unresolved Staff Comments
We do not have any unresolved SEC staff comments.
We are aItem 3.Legal Proceedings
In the ordinary course of business, we may become party to various legal, regulatory or administrative proceedings or governmental investigations, including environmental and regulatory proceedings.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 legalproceedings and regulatory proceedingsinvestigations, 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.
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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.” The following table sets forth the range of the daily high and low sales prices per common unit, cash distributions per common unit and the trading volume of common units for the periods indicated.
|
| | | | | | | | | | | | | | | |
| Years Ended December 31, | | High | | Low | | Cash Distributions | | Trading Volume |
| 2017 | | | | | | | | |
| Fourth quarter | | $ | 35.84 |
| | $ | 31.56 |
| | $ | 0.6500 |
| | 9,662,789 |
|
| Third quarter | | $ | 36.05 |
| | $ | 30.11 |
| | $ | 0.6450 |
| | 16,750,589 |
|
| Second quarter | | $ | 37.56 |
| | $ | 30.36 |
| | $ | 0.6325 |
| | 8,644,252 |
|
| First quarter | | $ | 38.09 |
| | $ | 32.06 |
| | $ | 0.6200 |
| | 8,883,617 |
|
| 2016 | | | | | | | | |
| Fourth quarter | | $ | 34.87 |
| | $ | 29.53 |
| | $ | 0.6075 |
| | 7,029,100 |
|
| Third quarter | | $ | 36.98 |
| | $ | 31.30 |
| | $ | 0.5950 |
| | 6,599,800 |
|
| Second quarter | | $ | 36.99 |
| | $ | 31.75 |
| | $ | 0.5850 |
| | 8,201,400 |
|
| First quarter | | $ | 34.50 |
| | $ | 21.44 |
| | $ | 0.5750 |
| | 11,258,800 |
|
The cash distribution for the fourth quarter of 2017 was declared on January 26, 2018, and paid on February 14, 2018, to all unitholders of record on February 5, 2018.
As of February 13, 2018,15, 2022, we had approximately 19,65017,216 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.
Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable laws, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.
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 2017 | | — |
| | $ | — |
| | — |
| | $ | — |
|
| November 2017 | | — |
| | $ | — |
| | — |
| | $ | — |
|
| December 2017 | | 16,818 |
| | $ | 33.90 |
| | — |
| | $ | — |
|
| Total for October to December 2017 | | 16,818 |
| | | | — |
| | |
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 16,81831,734 common units (which units were previously issued to certain officers and other employees pursuant to restrictedphantom 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.
We have a Long-Term Incentive Plan for employees and non-employee directors who perform services for us. The units reported represent common units purchased in the open market for delivery to recipients of our restricted unit and performance unit awards under our Long-Term Incentive Plan at the time of grant or settlement, as applicable.
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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, |
| | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | | (In thousands, except per unit data) |
| Statement of Income Data: | | | | | | | | | | |
| Revenues | | $ | 454,362 |
| | $ | 402,043 |
| | $ | 358,875 |
| | $ | 332,545 |
| | $ | 305,182 |
|
| Operating costs and expenses | | | | | | | | | | |
| Operations (exclusive of depreciation and amortization) | | 137,605 |
| | 123,986 |
| | 105,556 |
| | 106,185 |
| | 100,131 |
|
| Depreciation and amortization | | 79,278 |
| | 70,428 |
| | 63,306 |
| | 62,529 |
| | 65,783 |
|
| General and administrative | | 14,323 |
| | 12,532 |
| | 12,556 |
| | 10,824 |
| | 11,749 |
|
| | | 231,206 |
| | 206,946 |
| | 181,418 |
| | 179,538 |
| | 177,663 |
|
| Operating income | | 223,156 |
| | 195,097 |
| | 177,457 |
| | 153,007 |
| | 127,519 |
|
| Equity in earnings of equity method investments | | 12,510 |
| | 14,213 |
| | 4,803 |
| | 2,987 |
| | 2,826 |
|
| Interest expense | | (58,448 | ) | | (52,552 | ) | | (37,418 | ) | | (36,101 | ) | | (47,010 | ) |
| Interest income | | 491 |
| | 440 |
| | 526 |
| | 3 |
| | 161 |
|
| 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 | | 422 |
| | 677 |
| | 486 |
| | 82 |
| | 1,871 |
|
| | | (20,996 | ) | | (37,222 | ) | | (31,603 | ) | | (40,706 | ) | | (42,152 | ) |
| Income before income taxes | | 202,160 |
| | 157,875 |
| | 145,854 |
| | 112,301 |
| | 85,367 |
|
| State income tax expense | | (249 | ) | | (285 | ) | | (228 | ) | | (235 | ) | | (333 | ) |
| Net income | | 201,911 |
| | 157,590 |
| | 145,626 |
| | 112,066 |
| | 85,034 |
|
| Allocation of net loss attributable to Predecessor | | — |
| | 10,657 |
| | 2,702 |
| | 1,747 |
| | 1,047 |
|
| Allocation of net income attributable to noncontrolling interests | | (6,871 | ) | | (10,006 | ) | | (11,120 | ) | | (8,288 | ) | | (6,632 | ) |
| Net income attributable to the partners | | 195,040 |
| | 158,241 |
| | 137,208 |
| | 105,525 |
| | 79,449 |
|
General partner interest in net income, including incentive distributions(1) | | (35,047 | ) | | (57,173 | ) | | (42,337 | ) | | (34,667 | ) | | (27,523 | ) |
| Limited partners’ interest in net income | | $ | 159,993 |
| | $ | 101,068 |
| | $ | 94,871 |
| | $ | 70,858 |
| | $ | 51,926 |
|
Limited partners’ earnings per unit – basic and diluted(1) | | $ | 2.28 |
| | $ | 1.69 |
| | $ | 1.60 |
| | $ | 1.20 |
| | $ | 0.88 |
|
| Distributions per limited partner unit | | $ | 2.5475 |
| | $ | 2.3625 |
| | $ | 2.2025 |
| | $ | 2.0750 |
| | $ | 1.9550 |
|
| | | | | | | | | | | |
| Other Financial Data: | | | | | | | | | | |
| Cash flows from operating activities | | $ | 238,487 |
| | $ | 243,548 |
| | $ | 231,442 |
| | $ | 185,256 |
| | $ | 182,393 |
|
| Cash flows from investing activities | | $ | (286,273 | ) | | $ | (143,030 | ) | | $ | (246,680 | ) | | $ | (198,423 | ) | | $ | (90,704 | ) |
| Cash flows from financing activities | | $ | 51,905 |
| | $ | (111,874 | ) | | $ | 27,421 |
| | $ | 9,645 |
| | $ | (90,574 | ) |
EBITDA(2) | | $ | 344,749 |
| | $ | 277,545 |
| | $ | 237,180 |
| | $ | 211,701 |
| | $ | 192,054 |
|
Distributable cash flow(3) | | $ | 242,955 |
| | $ | 218,810 |
| | $ | 197,046 |
| | $ | 172,718 |
| | $ | 146,579 |
|
Maintenance capital expenditures(4) | | $ | 7,748 |
| | $ | 9,658 |
| | $ | 8,926 |
| | $ | 4,616 |
| | $ | 8,683 |
|
| Expansion capital expenditures | | 37,062 |
| | 50,046 |
| | 30,467 |
| | 75,343 |
| | 43,418 |
|
| Acquisition capital expenditures | | 245,446 |
| | 44,119 |
| | 153,728 |
| | 118,727 |
| | 41,635 |
|
| Total capital expenditures | | $ | 290,256 |
| | $ | 103,823 |
| | $ | 193,121 |
| | $ | 198,686 |
| | $ | 93,736 |
|
| | | | | | | | | | | |
| Balance Sheet Data (at period end): | | | | | | | | | | |
| Net property, plant and equipment | | $ | 1,569,471 |
| | $ | 1,328,395 |
| | $ | 1,293,060 |
| | $ | 1,163,631 |
| | $ | 1,018,854 |
|
| Total assets | | $ | 2,154,114 |
| | $ | 1,884,237 |
| | $ | 1,777,646 |
| | $ | 1,584,114 |
| | $ | 1,442,573 |
|
Long-term debt(5) | | $ | 1,507,308 |
| | $ | 1,243,912 |
| | $ | 1,008,752 |
| | $ | 866,986 |
| | $ | 806,655 |
|
| Total liabilities | | $ | 1,669,049 |
| | $ | 1,412,446 |
| | $ | 1,151,424 |
| | $ | 989,324 |
| | $ | 914,656 |
|
Total equity(6) | | $ | 485,065 |
| | $ | 471,791 |
| | $ | 626,222 |
| | $ | 594,790 |
| | $ | 527,917 |
|
- 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 Holly Energy Partners plus (i) interest expense net of interest income and loss on early extinguishment of debt, (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 HEP 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, |
| | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | | (In thousands) |
| Net income attributable to the partners | | $ | 195,040 |
| | $ | 158,241 |
| | $ | 137,208 |
| | $ | 105,525 |
| | $ | 79,449 |
|
| Add (subtract): | | | | | | | | | | |
| Interest expense | | 55,385 |
| | 49,306 |
| | 35,490 |
| | 34,280 |
| | 44,041 |
|
| Interest income | | (491 | ) | | (440 | ) | | (526 | ) | | (3 | ) | | (161 | ) |
| Amortization of discount and deferred debt issuance costs | | 3,063 |
| | 3,246 |
| | 1,928 |
| | 1,821 |
| | 2,120 |
|
| Loss on early extinguishment of debt | | 12,225 |
| | — |
| | — |
| | 7,677 |
| | — |
|
| Amortization of unrealized loss attributable to discontinued cash flow hedge | | — |
| | — |
| | — |
| | — |
| | 849 |
|
| State income tax expense | | 249 |
| | 285 |
| | 228 |
| | 235 |
| | 333 |
|
| Depreciation and amortization | | 79,278 |
| | 70,428 |
| | 63,306 |
| | 62,529 |
| | 65,783 |
|
| Predecessor depreciation and amortization | | — |
| | (3,521 | ) | | (454 | ) | | (363 | ) | | (360 | ) |
| EBITDA | | $ | 344,749 |
| | $ | 277,545 |
| | $ | 237,180 |
| | $ | 211,701 |
| | $ | 192,054 |
|
| |
(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, |
| | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | | (In thousands) |
| Net income attributable to the partners | | $ | 195,040 |
| | $ | 158,241 |
| | $ | 137,208 |
| | $ | 105,525 |
| | $ | 79,449 |
|
| Add (subtract): | | | | | | | | | | |
| Depreciation and amortization | | 79,278 |
| | 70,428 |
| | 63,306 |
| | 62,529 |
| | 65,783 |
|
| Remeasurement gain on preexisting equity interests | | (36,254 | ) | | — |
| | — |
| | — |
| | — |
|
| Amortization of discount and deferred debt issuance costs | | 3,063 |
| | 3,246 |
| | 1,928 |
| | 1,821 |
| | 2,120 |
|
| Amortization of unrealized loss attributable to discontinued cash flow hedge | | — |
| | — |
| | — |
| | — |
| | 849 |
|
| Loss on early extinguishment of debt | | 12,225 |
| | — |
| | — |
| | 7,677 |
| | — |
|
| Increase (decrease) in deferred revenue related to minimum revenue commitments | | (1,283 | ) | | (1,292 | ) | | (1,233 | ) | | (2,503 | ) | | 3,686 |
|
Maintenance capital expenditures (4) | | (7,748 | ) | | (9,658 | ) | | (8,926 | ) | | (4,616 | ) | | (8,683 | ) |
| Crude revenue settlement | | — |
| | — |
| | — |
| | — |
| | 918 |
|
| Increase (decrease) in environmental liability | | (581 | ) | | (584 | ) | | 1,107 |
| | 1,596 |
| | 619 |
|
| Increase (decrease) in reimbursable deferred revenue | | (3,679 | ) | | (2,733 | ) | | 176 |
| | (2,274 | ) | | (1,642 | ) |
| Other non-cash adjustments | | 2,894 |
| | 4,683 |
| | 3,934 |
| | 3,326 |
| | 3,840 |
|
| Predecessor depreciation and amortization | | — |
| | (3,521 | ) | | (454 | ) | | (363 | ) | | (360 | ) |
| Distributable cash flow | | $ | 242,955 |
| | $ | 218,810 |
| | $ | 197,046 |
| | $ | 172,718 |
| | $ | 146,579 |
|
| |
(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 $1,012 million, $553 million, $712 million, $571 million and $363 million in Credit Agreement advances that were classified as long-term debt at December 31, 2017, 2016, 2015, 2014 and 2013, respectively. |
| |
(6) | As a master limited partnership, we distribute our available cash, which historically has exceeded our net income attributable to HEP 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 HEP. 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, Arizona, Washington, Idaho, Oklahoma, Utah, Nevada, Wyoming and Kansas as well as refinery processing units in Utah and Kansas. HFC owned 59%57% of our outstanding common units and the non-economic general partner interest as of December 31, 2017.2021.
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 will 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 total 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, 2017,2021, these agreements with HFC requirerequired minimum annualized payments to us of $324$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 under this lease agreement expire beginning in 2018 through 2022. As of December 31, 2017, these agreements with Delek require minimum annualized payments to us of $33 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 2017)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, 2017, 20162021, 2020 and 2015. 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 |
| | | 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) | | $ | 344,749 |
| | $ | 277,545 |
| | $ | 67,204 |
|
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 and terminal and refinery processing unit assets (bpd) | | 1,216,623 |
| | 1,156,278 |
| | 60,345 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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.
| | | | | | | | | | | | | | |
| | 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 | |
|
| | | | | | | | | | | | |
| | | Years Ended December 31, | | Change from |
| | | 2016 | | 2015 | | 2015 |
| | | (In thousands, except per unit data) |
| Revenues | | | | | | |
| Pipelines: | | | | | | |
| Affiliates—refined product pipelines | | $ | 83,102 |
| | $ | 81,294 |
| | $ | 1,808 |
|
| Affiliates—intermediate pipelines | | 26,996 |
| | 28,943 |
| | (1,947 | ) |
| Affiliates—crude pipelines | | 70,341 |
| | 67,088 |
| | 3,253 |
|
| | | 180,439 |
| | 177,325 |
| | 3,114 |
|
| Third parties—refined product pipelines | | 52,195 |
| | 51,022 |
| | 1,173 |
|
| | | 232,634 |
| | 228,347 |
| | 4,287 |
|
| Terminals, tanks and loading racks: | | | | | | |
| Affiliates | | 119,633 |
| | 111,933 |
| | 7,700 |
|
| Third parties | | 16,732 |
| | 15,632 |
| | 1,100 |
|
| | | 136,365 |
| | 127,565 |
| | 8,800 |
|
| | | | | | | |
| Affiliates—refinery processing units | | 33,044 |
| | 2,963 |
| | 30,081 |
|
| | | | | | | |
| Total revenues | | 402,043 |
| | 358,875 |
| | 43,168 |
|
| Operating costs and expenses | | | | | | |
| Operations (exclusive of depreciation and amortization) | | 123,986 |
| | 105,556 |
| | 18,430 |
|
| Depreciation and amortization | | 70,428 |
| | 63,306 |
| | 7,122 |
|
| General and administrative | | 12,532 |
| | 12,556 |
| | (24 | ) |
| | | 206,946 |
| | 181,418 |
| | 25,528 |
|
| Operating income | | 195,097 |
| | 177,457 |
| | 17,640 |
|
| Other income (expense): | | | | | | |
| Equity in earnings of equity method investments | | 14,213 |
| | 4,803 |
| | 9,410 |
|
| Interest expense, including amortization | | (52,552 | ) | | (37,418 | ) | | (15,134 | ) |
| Interest income | | 440 |
| | 526 |
| | (86 | ) |
| Gain on sale of assets and other | | 677 |
| | 486 |
| | 191 |
|
| | | (37,222 | ) | | (31,603 | ) | | (5,619 | ) |
| Income before income taxes | | 157,875 |
| | 145,854 |
| | 12,021 |
|
| State income tax expense | | (285 | ) | | (228 | ) | | (57 | ) |
| Net income | | 157,590 |
| | 145,626 |
| | 11,964 |
|
| Allocation of net loss attributable to Predecessor | | 10,657 |
| | 2,702 |
| | 7,955 |
|
| Allocation of net income attributable to noncontrolling interests | | (10,006 | ) | | (11,120 | ) | | 1,114 |
|
| Net income attributable to the partners | | 158,241 |
| | 137,208 |
| | 21,033 |
|
General partner interest in net income attributable to the partners (1) | | (57,173 | ) | | (42,337 | ) | | (14,836 | ) |
| Limited partners’ interest in net income | | $ | 101,068 |
| | $ | 94,871 |
| | $ | 6,197 |
|
Limited partners’ earnings per unit—basic and diluted (1) | | $ | 1.69 |
| | $ | 1.60 |
| | $ | 0.09 |
|
| Weighted average limited partners’ units outstanding | | 59,872 |
| | 58,657 |
| | 1,215 |
|
EBITDA (2) | | $ | 277,545 |
| | $ | 237,180 |
| | $ | 40,365 |
|
Distributable cash flow (3) | | $ | 218,810 |
| | $ | 197,046 |
| | $ | 21,764 |
|
| | | | | | | |
| Volumes (bpd) | | | | | | |
| Pipelines: | | | | | | |
| Affiliates—refined product pipelines | | 128,140 |
| | 124,061 |
| | 4,079 |
|
| Affiliates—intermediate pipelines | | 137,381 |
| | 142,475 |
| | (5,094 | ) |
| Affiliates—crude pipelines | | 277,241 |
| | 291,491 |
| | (14,250 | ) |
| | | 542,762 |
| | 558,027 |
| | (15,265 | ) |
| Third parties—refined product pipelines | | 75,909 |
| | 73,555 |
| | 2,354 |
|
| | | 618,671 |
| | 631,582 |
| | (12,911 | ) |
| Terminals and loading racks: | | | | | |
|
| Affiliates | | 413,487 |
| | 391,292 |
| | 22,195 |
|
| Third parties | | 72,342 |
| | 78,403 |
| | (6,061 | ) |
| | | 485,829 |
| | 469,695 |
| | 16,134 |
|
| | | | | | | |
| Affiliates—refinery processing units | | 51,778 |
| | 6,774 |
| | 45,004 |
|
| | | | | | | |
| Total for pipelines and terminal and refinery processing unit assets (bpd) | | 1,156,278 |
| | 1,108,051 |
| | 48,227 |
|
| |
(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 and loss on early extinguishment of debt, 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.” |
| |
(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, 20172021 Compared with Year Ended December 31, 20162020
Summary
Net income attributable to the partners for the year ended December 31, 2017,2021, was $195.0$214.9 million, a $36.8$44.5 million increase compared to the year ended December 31, 2016. The increase in earnings is primarily due to (a) the Woods Cross processing units acquired in the fourth quarter of 2016, (b) the gain recognized on the acquisition of SLC Pipeline and Frontier Aspen2020. Results for the remeasurementyear ended December 31, 2021 reflect special items that collectively increased net income attributable to HEP by a total of preexisting equity interests, offset by (c)$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 $12.2$25.9 million related to the early redemption of our previously outstanding $300$500 million 6.5%aggregate principal amount of 6% Senior Notes (the “6.5% Senior Notes”), due in 20202024, 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. Excluding these items, net income attributable to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Revenuesthe partners for the year ended December 31, 2017, include the recognition of $9.72021 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 and 2016. As of December 31, 2017, deferred revenue on our consolidated balance sheet related to shortfalls billed was $4.0 million.2020.
Revenues
Revenues for the year ended December 31, 2017,2021, were $454.4$494.5 million, a $52.3$3.4 million increasedecrease compared to the same period in 2020. The decrease was mainly attributable to lower on-going revenues from our Cheyenne assets as a result of 2016. The increase is primarilythe conversion of the HFC 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 year 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 the $43.5 millionhigher recovery of revenue recorded for the Woods Cross processing units acquired in the fourth quarter of 2016 as well as revenues from the SLC and Frontier Aspen pipelines acquired in the fourth quarter of 2017.natural gas costs.
Revenues from our refined product pipelines were $132.4$107.4 million, a decrease of $2.9$9.5 million, on shipments averaging 211.8158.1 mbpd compared to 204.0161.5 mbpd for the year ended December 31, 2016.2020. 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 in the first quarter of 2017 as well as a decrease of $2.3 million in previously deferred revenue realized. The increase in volumes is primarily due to higher volumes on relatively short pipelines with lower tariff rates.and Delek's Big Spring refinery.
Revenues from our intermediate pipelines were $28.7$30.1 million, an increase of $1.7$0.1 million, on shipments averaging 141.6125.2 mbpd compared to 137.4137.1 mbpd for the year ended December 31, 2016.2020. The increasedecrease in revenue isvolumes was mainly due to higher volumes from
lower throughputs on our intermediate pipelines servicing HFC's Tulsa and Navajo refinery after its turnaround in the first quarter of 2017 as well as an increase of $1.5 million in previously deferredrefineries while revenue realized.remained relatively constant mainly due to contractual minimum volume guarantees.
Revenues from our crude pipelines were $73.9$125.6 million, an increase of $3.6$6.7 million, on shipments averaging 302.9408.6 mbpd compared to 277.2387.7 mbpd for the year ended December 31, 2016. Revenues2020. The increases were mainly attributable to increased volumes on our crude pipeline systems in Wyoming and volumes increased mainly due to revenues from the fourth quarter of 2017 acquisition of the remaining interests in SLC Pipeline and Frontier AspenUtah partially offset by lower throughputvolumes on our pipeline systems servicing HFC's Navajo refinery. Volumes also increased due to HFC's Navajo refinery turnaroundthe addition of volumes on our Cushing Connect Pipeline in Oklahoma which went into service at the firstend of the third quarter of 2017.2021.
Revenues from terminal, tankage and loading rack fees were $142.4$142.3 million, an increasea decrease of $6.1$9.4 million compared to the year ended December 31, 2016.2020. Refined products and crude oil terminalled in ourthe facilities increased to an average of 496.7averaged 442.9 mbpd compared to 485.8442.2 mbpd for the year ended December 31, 2016. The volume and revenue increases are2020. Revenues decreased mainly due to lower on-going revenues on our Tulsa crude tanks acquired on the last dayCheyenne assets as a result of the first quarterconversion of 2016, higher throughput on the UNEV terminals,HFC's Cheyenne refinery to renewable diesel production and higher reimbursablerecording certain tariffs and fees as interest income under sales-type lease accounting that were previously recorded as revenue related to tank inspections and repairs, offset by the transfer of the El Paso terminal to HollyFrontier in the first quarter of 2016.year ended December 31, 2020.
Revenues from refinery processing units were $76.9$89.1 million, an increase of $43.9$8.8 million on throughputs averaging 63.669.6 mbpd compared to 51.861.4 mbpd for 2016.the year ended December 31, 2020. The increase in revenues and volumes is primarilywas mainly due to theincreased throughput for both our Woods Cross refineryand El Dorado processing units acquired in the fourth quarterunits. Revenues increased mainly due to higher recovery of 2016.natural gas costs as well as higher throughputs.
Operations Expense
Operations (exclusive(exclusive of depreciation and amortization) expense for the year ended December 31, 2017,2021, increased by $13.6$22.8 million compared to the year ended December 31, 2016.2020. The increase is primarilywas mainly due to operating expenses for the Woods Cross refinery processing units acquiredan increase in the fourth quarter of 2016.employee costs, maintenance costs, pipeline rental costs and natural gas costs.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2017, increased2021, decreased by $8.9$5.8 million compared to the year ended December 31, 2016.2020. The increase isdecrease was mainly due to depreciation from the Woods Cross refinery processing units acquiredretirements in the fourth quarterCheyenne operations and sale of 2016.El Paso 6-inch pipeline assets.
General and Administrative
General and administrative costs for the year ended December 31, 2017,2021, increased by $1.8$2.6 million compared to the year ended December 31, 2016, mainly2020 primarily due to higher legal and consulting costs offset by decreased employee compensation.related to the HEP 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 | 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 equityEquity in earnings of Osage Pipe Line Company, LLC increased for the year ended December 31, 2017, reflect the ten months before we purchased their remaining interests on October 31, 2017. SLC2021, mainly due to higher throughput volumes. Equity in earnings of Cheyenne Pipeline and Frontier Aspen operationsLLC increased for the two monthsyear ended December 31, 2021, mainly due to the recognition in revenue of November andprior contractual minimum commitment billings. Equity in earnings of Cushing Connect Terminal Holdings LLC increased for the year ended December 2017, are included31, 2021 as the terminal started operations in HEP's consolidated results.the second quarter of 2020.
Interest Expense
Interest expense for the year ended December 31, 2017,2021, totaled $58.4$53.8 million, an increasea decrease of $5.9$5.6 million compared to the year ended December 31, 2016.2020. The increase is primarilydecrease was mainly due to the issuance of new 6% Senior Notes in July 2016.lower outstanding balances under our senior secured revolving credit facility. Our aggregate effectiveweighted-average interest rate was 4.4%rates were 3.7% and 4.7%3.8% for the years ended December 31, 20172021 and 2016,2020, 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 $249,000$32,000 and $285,000$167,000 for the years ended December 31, 20172021 and 2016,2020, respectively. All state income tax expense is solely attributable to the Texas margin tax.
ResultsResults of Operations—Year Ended December 31, 20162020 Compared with Year Ended December 31, 20152019
Summary
Net income attributable to the partners for the year ended December 31, 2016,2020, was $158.2$170.5 million, a $21.0$54.4 million increasedecrease compared to the year ended December 31, 2015. The increase in earnings is primarily due to the newly constructed and acquired Woods Cross refinery processing units and recent acquisitions including interests in the Osage and Cheyenne pipelines, the Tulsa crude tanks acquired in the first quarter of 2016, and the El Dorado refinery process units dropped down in the fourth quarter of 2015 as well as increased earnings from our 75% interest in the UNEV products pipeline, offset by higher interest expense associated with our private placement of $400 million in aggregate principal amount of 6% senior unsecured notes due in 2024, which we issued in July and the proceeds of which were used to partially fund our Woods Cross processing units acquisition.
Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Revenues2019. Results for the year ended December 31, 2016,2020 reflect special items that collectively decreased net income attributable to HEP by a total of $21.7 million. These items include 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 $10.0our previously outstanding $500 million aggregate principal amount of prior shortfalls billed6% Senior Notes due in 2024, a gain on sales type leases of $33.8 million and a $6.1 million gain related to shippers in 2016 and 2015. AsHEP's pro-rata share of a business interruption insurance claim settlement resulting from a loss at HFC's Woods Cross refinery. In addition, net income attributable to HEP for the year ended December 31, 2016, deferred revenue2019 included a gain on our consolidated balance sheet related to shortfalls billed was $5.6sales-type leases of $35.2 million. Such deferred revenue will be recognized in earnings either as (a) payment for shipments in excess of guaranteed levels, if andExcluding these items, net income attributable to the extentpartners for the pipeline system will have the necessary capacity for shipmentsyear ended December 31, 2020 was $192.1 million ($1.82 per basic and diluted limited partner unit) compared to $189.7 million ($1.80 per basic and diluted limited partner unit) in excess of guaranteed levels, or (b) when shipping rights expire unused over the contractual make-up period.2019.
Revenues
Revenues for the year ended December 31, 2016,2020, were $402.0$497.8 million, a $43.2$34.9 million increasedecrease compared to the same period of 2015.2019. The revenue increasedecrease was primarily duemainly attributable to the Woods Cross processing units acquiredan 18% reduction in the fourth quarter of 2016, the El Dorado processing units acquiredoverall crude and product pipeline volumes predominantly in the fourth quarter of 2015, higher UNEV pipeline revenues,our Southwest and revenues from the Tulsa crude tanks acquired in the first quarter of 2016.Northwest regions.
Revenues from our refined product pipelines were $135.3$116.9 million, an increasea decrease of $3.0$15.4 million, primarily due to increased revenue from the UNEV pipeline of $4.0 million offset by PPI driven tariff rates decreases. Shipments averaged 204.0on shipments averaging 161.5 mbpd compared to 197.6195.5 mbpd for the year ended December 31, 2015, largely2019. The volume and revenue decreases were mainly due to higherlower volumes on pipelines servicing HFC's Navajo refinery, Delek's Big Spring refinery and our UNEV pipeline.pipeline largely as a result of demand destruction associated with the COVID-19 pandemic as well as the recording of certain pipeline tariffs as interest income as the related throughput contract renewals were determined to be sales-type leases.
Revenues from our intermediate pipelines were $27.0$30.0 million, a decreasean increase of $1.9$0.5 million, on shipments averaging 137.4137.1 mbpd compared to 142.5140.6 mbpd for the year ended December 31, 2015. The decrease in revenue is mainly due to lower volumes from pipelines servicing HFC's Navajo refinery and a $0.7 million decrease in previously deferred revenue realized.2019.
Revenues from our crude pipelines were $70.3$118.9 million, an increasea decrease of $3.3$11.8 million, on shipments averaging 277.2387.7 mbpd compared to 291.5501.2 mbpd for the year ended December 31, 2015. Revenues increased largely due2019. The decreases were mainly attributable to an increase in deferred revenue recognized and to a surchargedecreased volumes on our Beeson expansion. Volumes were lower due to lower throughput at HFC's Navajo refinery.crude pipeline systems in the Permian Basin, Wyoming and Utah largely as a result of demand destruction associated with the COVID-19 pandemic.
Revenues from terminal, tankage and loading rack fees were $136.4$151.7 million, an increasea decrease of $8.8 million compared to the year ended December 31, 2015. This increase is due principally to increased revenues from the El Dorado tanks and the newly acquired Tulsa crude tanks.2019. Refined products and crude oil terminalled in ourthe facilities increased to an average of 485.8averaged 442.2 mbpd compared to 469.7 483.2
mbpd for the year ended December 31, 2015, largely due to2019. The revenue and volume decreases were mainly as a result of demand destruction associated with the inclusionCOVID-19 pandemic across many of volumes from our Tulsa crude tanks acquired in the first quarter of 2016 and our El Dorado crude tanks acquired late in the first quarter of 2015, offset by the transfer of the El Paso terminal to HFC in the first quarter of 2016.facilities.
Revenues from refinery processing units were $33.0$80.3 million, an increase of $30.1$0.6 million on throughputs averaging 51.861.4 mbpd compared to 6.868.8 mbpd for 2015. This increase2019. The decrease in revenue is primarilyvolumes was 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 and an increase in revenue from the El Dorado refinery units acquired late in 2015.COVID-19 pandemic. Revenues remained relatively constant due to contractual minimum volume guarantees.
Operations Expense
Operations (exclusive(exclusive of depreciation and amortization) expense for the year ended December 31, 2016, increased2020, decreased by $18.4$14.3 million compared to the year ended December 31, 2015. 2019. The increase isdecrease was mainly due to operatinglower rental expenses, from the newly constructedproperty taxes and acquired Woods Cross processing unitsvariable costs such as electricity and El Dorado refinery processing units.chemicals associated with lower volumes.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2016,2020, increased by $7.1$2.9 million compared to the year ended December 31, 2015.2019. The increase is principallywas mainly due to higherthe acceleration of depreciation fromon certain of our newly acquired Woods Cross refinery processing units.Cheyenne tanks.
General and Administrative
General and administrative costs for the year ended December 31, 2016, was in line with2020, decreased by $0.3 million compared to the year ended December 31, 2015.2019, mainly due to lower legal 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 | 2016 | | 2015 |
| | (in thousands) |
| SLC Pipeline LLC | $ | 4,508 |
| | $ | 3,306 |
|
| Frontier Aspen LLC | 4,130 |
| | 1,497 |
|
| Osage Pipe Line Company, LLC | 3,250 |
| | — |
|
| Cheyenne Pipeline LLC | 2,325 |
| | — |
|
| Total | $ | 14,213 |
| | $ | 4,803 |
|
SLC Pipeline earnings for the year ended December 31, 2016, increased compared to the year ended December 31, 2015, due to higher pipeline throughput volumes. Frontier Aspen earnings for year ended December 31, 2016, include a full year of operations compared to the year ended December 31, 2015, as we acquired our 50% interest on August 31, 2015.
Interest Expense
Interest expense for the year ended December 31, 2016,2020, totaled $52.6$59.4 million, an increasea decrease of $15.1$17.4 million compared to the year ended December 31, 2015.2019. The increase is primarilydecrease was mainly 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 4.7%rates were 3.8% and 4.0%5.4% for the years ended December 31, 20162020 and 2015,2019, respectively.
State Income Tax
We recorded state income tax expense of $285,000$167,000 and $228,00041,000 for the years ended December 31, 20162020 and 2015,2019, 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, 2017,2021, we received advances totaling $969.0$480.5 million and repaid $510.0$554.0 million, resulting in a net increasedecrease of $459.0$73.5 million under the Credit Agreement and an outstanding balance of $1,012.0$840.0 million at December 31, 2017.2021. As of December 31, 2017,2021, we had no letters of credit outstanding under the Credit Agreement, and the available capacity under the Credit Agreement was $388$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, 2017,2021, HEP hashad issued 2,241,9072,413,153 units under this program, providing $77.1$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 6.5% senior notes due in 2020 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 2017,2021, we paid regular quarterly cash distributions of $0.6075, $0.6200, $0.6325$0.3500, $0.3500, $0.3500 and $0.6450,$0.3500, respectively, on all units in an aggregate amount of $234.6 million, including $49.7 million of incentive distribution payments to our general partner.$149.4 million. In February 2018,2022, we paid a regular quarterly cash distribution of $0.6500$0.3500 on all units in an aggregate amount of $63.5 million after deducting HEP Logistics' waiver of $2.5 million of limited partner cash distributions.$37.0 million.
Cash and cash equivalents increaseddecreased by $4.1$7.6 million during the year ended December 31, 2017.2021. The cash flows provided by operating and financing activities of $238.5$294.1 million and $51.9 million, respectively, were moreless than the cash flows used for investing and financing activities of $286.3 million.$78.5 million and $223.2 million, respectively. Working capital increased by $26.7$3.2 million to a surplus of $18.9$17.5 million at December 31, 20172021 from a deficiencysurplus of $7.8$14.2 million at December 31, 2016.2020.
Cash Flows—Operating Activities
Year Ended December 31, 20172021 Compared with Year Ended December 31, 20162020
Cash flows provided by operating activities decreased by $5.1$21.5 million from $243.5$315.6 million for the year ended December 31, 2016,2020, to $238.5$294.1 million for the year ended December 31, 2017. 2021. This decrease iswas mainly due principally to higher payments for operating expenses partially offset by higher cash receipts from customers and lower payments for interest expenses in the year ended December 31, 2021, as compared to the prior year.
Year Ended December 31, 2020 Compared with Year Ended December 31, 2019
Cash flows from operating activities increased by $18.6 million from $297.1 million for the year ended December 31, 2019, to $315.6 million for the year ended December 31, 2020. This increase was mainly due to lower 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.
Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Under certain agreements, these shippers have the right to recapture these amounts if future volumes exceed minimum levels. We billed $9.7 million during the year ended December 31, 2016, related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2017. Another $4.0 million is included as deferred revenue on our balance sheet at December 31, 2017, related to shortfalls billed during the year ended December 31, 2017.Cash Flows—Investing Activities
Year Ended December 31, 20162021 Compared with Year Ended December 31, 2015
Cash flows from operating activities increased by $12.1 million from $231.4 million for the year ended December 31, 2015, to $243.5 million for the year ended December 31, 2016. This increase is due principally to higher cash receipts for services performed and higher distributions received from equity investments partially offset by higher payments for interest and operating expenses in the year ended December 31, 2016, as compared to the prior year.
Our major shippers are obligated to make deficiency payments to us if they do not meet their minimum volume shipping obligations. Under certain agreements, these shippers have the right to recapture these amounts if future volumes exceed minimum levels. We billed $10.0 million during the year ended December 31, 2015 and 2016, related to shortfalls that subsequently expired without recapture and were recognized as revenue during the year ended December 31, 2016. Another $5.6 million is included as deferred revenue on our balance sheet at December 31, 2016, related to shortfalls billed during the year ended December 31, 2016
Cash Flows—Investing Activities
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% interest in SLC Pipeline and 50% interest in Frontier Aspen for $245.4 million in October 2017. We acquired a 50% interest in Cheyenne 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.year ended December 31, 2021.
Year Ended December 31, 20162020 Compared with Year Ended December 31, 20152019
Cash flows used for investing activities decreasedincreased by $103.7$13.5 million from $246.7$46.3 million for the year ended December 31, 2015,2019, to $143.0$59.8 million for the year ended December 31, 2016.2020. During the years ended December 31, 20162020 and 2015,2019, we invested $59.7$59.3 million and $39.4$30.1 million, respectively, in additions to properties and equipment, respectively. We acquired a 50% interest in Cheyenne Pipeline LLC for $42.6 million in June 2016, a 50% interest in Frontier Pipeline for $55.0 million in August 2015, and the El Dorado crude tank assets for $27.5 million in March 2015. We have retrospectively adjusted our historical financial results for all periods to include the Woods Cross refinery processing units and Tulsa tanks for the periods we were under common control of HFC. Therefore, cash flows from investing activities reflect outflows of $44.1 million for the Woods Cross refinery processing units and Tulsa tanks in 2016 and $98.6 million in 2015. The year ended December 31, 2015 also reflects outflows of $27.6 million related to our acquisition of the El Dorado refinery processing units. We received $3.0 million of distributions in excess of earnings of our equity method investments. We received $0.4 million in proceeds from the sale of assets duringequipment. During the year ended December 31, 2016.2020, we made payments of $2.4 million related to our 50% interest in Cushing Connect Pipeline & Terminal LLC.
Cash Flows—Financing Activities
Year Ended December 31, 20172021 Compared with Year Ended December 31, 20162020
Cash flows provided byused for financing activities were $51.9decreased by $23.9 million from $247.2 million for the year ended December 31, 2017, compared2020, to cash flows used by financing activities of $111.9$223.2 million for the year ended December 31, 2016, an increase of $163.8 million.2021. During the year ended December 31, 2017,2021, we received $969.0$480.5 million and repaid $510.0$554.0 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$149.4 million in regular quarterly cash distributions to our generalHEP unitholders and limited partners and $6.5$10.7 million to our noncontrolling interest.interests. We also paid $9.4received $23.2 million in deferred financing charges to amendcontributions from our noncontrolling interests during the Credit Agreement.year ended December 31, 2021. During the year ended December 31, 2016,2020, we received $554.0$258.5 million and repaid $713.0$310.5 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$174.4 million in regular quarterly cash distributions to our generalHEP unitholders and limited partners, paid $5.8$9.8 million to our noncontrolling interestinterests. We also received net proceeds of $491.3 million from the issuance of our 5% Senior Notes and paid $3.5$522.5 million for the purchase of common units for recipients ofto retire 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 the acquisitions of $317.5 million.6% Senior Notes.
Year Ended December 31, 20162020 Compared with Year Ended December 31, 20152019
Cash flows used for financing activities were $111.9increased by $6.6 million from $240.6 million for the year ended December 31, 2016, compared2019, to cash flows provided by financing activities of $27.4$247.2 million for the year ended December 31, 2015, a decrease of $139.3 million.2020. During the year ended December 31, 2016,2020, we received $554.0$258.5 million and repaid $713.0$310.5 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 issuance of common units. Additionally, we paid $192.0$174.4 million in regular quarterly cash distributions to our generalHEP unitholders and limited partners, $5.8$9.8 million to our noncontrolling interest and $3.5interest. We received $23.9 million forin contributions from our noncontrolling interests during the purchaseyear ended December 31, 2020. We also received net proceeds of common units for recipients$491.3 million from the issuance of our incentive grants. We have retrospectively adjusted our historical financial results for all periods to include the Woods Cross refinery processing units5% Senior Notes and Tulsa tanks for the periods we were under common control of HFC. Therefore, we recorded contributions from HFC for the Woods Cross Operating and Tulsa tank acquisitions of $51.3 million and recorded distributions to HFC for the acquisitions of $317.5 million. We paid $1.2$522.5 million to HFC related to the Osage acquisition. We also paid $4.0 million in deferred financing charges to amend the Credit Agreement.retire our 6% Senior Notes. During the year ended December 31, 2015,2019, we received $973.9$365.5 million and repaid $832.9$323.0 million in advances under the Credit Agreement. We alsoAdditionally, we paid $169.1$273.2 million in regular quarterly cash distributions to our generalHEP unitholders and limited partners, paid $4.6$9.0 million to our noncontrolling interest and paid $3.6 million for the purchase of common units for recipients of our incentive grants. In addition, we received $27.6 million for the El Dorado Operating acquisition, $0.9 million for Tulsa tank expenditures from HFC, $99.9 million for the Woods Cross Operating acquisition, and recorded distributions to HFC for the El Dorado Operating acquisition of $62.0 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 2018 Our current 2022 capital budgetforecast is comprised of $8approximately $15 million to $20 million for maintenance capital expenditures, $35 million to $50 million for refinery unit turnarounds and approximately $40$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, 2017,2021, we had outstanding borrowings of $1,012$840.0 million under the Credit Agreement, no letters of credit outstanding, and the available capacity was $388$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, 2017.2021.
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 in effect atfor the years ending December 31, 20172021 and 2016,2020, were 3.734%2.30% and 2.978%2.58%, respectively. We incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.30%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 the 6.5%5% Senior Notes maturingdue 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, 2017.2021. 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,
2017 | | December 31,
2016 |
| | | (In thousands) |
| Credit Agreement | | $ | 1,012,000 |
| | $ | 553,000 |
|
| | | | | |
| 6% Senior Notes | | | | |
| Principal | | 500,000 |
| | 400,000 |
|
| Unamortized debt issuance costs | | (4,692 | ) | | (6,607 | ) |
| | | 495,308 |
| | 393,393 |
|
| 6.5% Senior Notes | | | | |
| Principal | | — |
| | 300,000 |
|
| Unamortized discount and debt issuance costs | | — |
| | (2,481 | ) |
| | | — |
| | 297,519 |
|
| | | | | |
| Total long-term debt | | $ | 1,507,308 |
| | $ | 1,243,912 |
|
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, 2017.2021.
| | | | | | | 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 | | $ | 1,512,000 |
| | $ | — |
| | $ | — |
| | $ | 1,012,000 |
| | $ | 500,000 |
| Long-term debt – principal | | $ | 1,340,000 | | | $ | — | | | $ | — | | | $ | 840,000 | | | $ | 500,000 | |
| Long-term debt - interest | | 370,300 |
| | 67,800 |
| | 135,600 |
| | 119,400 |
| | 47,500 |
| Long-term debt - interest | | 222,456 | | | 44,700 | | | 89,400 | | | 61,273 | | | 27,083 | |
| Site service fees | | 243,772 |
| | 5,133 |
| | 10,266 |
| | 10,266 |
| | 218,107 |
| Site service fees | | 242,933 | | | 5,601 | | | 11,202 | | | 11,202 | | | 214,928 | |
| Pipeline operating lease | | 61,038 |
| | 6,425 |
| | 12,850 |
| | 12,850 |
| | 28,913 |
| |
| Pipeline finance lease | | Pipeline finance lease | | 36,115 | | | 6,566 | | | 13,133 | | | 13,133 | | | 3,283 | |
| Right-of-way agreements and other | | 20,035 |
| | 4,007 |
| | 5,792 |
| | 4,064 |
| | 6,172 |
| Right-of-way agreements and other | | 18,990 | | | 4,326 | | | 7,973 | | | 2,180 | | | 4,511 | |
| Total | | $ | 2,207,145 |
| | $ | 83,365 |
| | $ | 164,508 |
| | $ | 1,158,580 |
| | $ | 800,692 |
| 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 agreementCredit Agreement is calculated using the rate in effect at December 31, 2017.
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, 2017.2021. 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, 2017, 20162021, 2020 and 20152019. PPI has increased an average of 0.4%2.9% annually over the past five calendar years, including an increase of 3.2%8.9% in 2021 and a decrease of 1.0%1.3% in 2017 and 2016, 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, 2017,2021, we have an accrual of $6.5$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 or will expire.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, or feedstocks are processed bythrough our refinery processing units. Additional pipelineunits 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. Prior to the adoption of the new lease standard (see below), we bifurcated the consideration received between lease and service revenue. The new lease standard allows the election 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, 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 revenues result from an operating lease by Alon USA, L.P., which was acquired by Delek and is referred to herein as Delek,contracts specify minimum volume requirements, whereby, we bill a customer for a minimum level of an interestshipments in the capacity of one of our pipelines.
Billings to customers forevent a customer ships below their obligations under their quarterly minimum revenue commitmentscontractual requirements. If there are recorded as deferred revenue liabilities if the customer has the right to receiveno future services for these billings. The revenue is recognized at the earlier of:
the customer receiving the future services provided by these billings,
the period in which the customer is contractually allowed to receive the services expires, or
our determination thatperformance obligations, we will not be required to provide services within the allowed period.recognize these deficiency payments in revenue.
We determine that we will not be required to provide services within the allowed period when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enableIn certain of these throughput agreements, a customer to exceedmay later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum volume levels to such a degree as to utilize the shortfall credit 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 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.
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.
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. Recoverability is determined by comparingOur 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 over the estimated fair value of athe reporting unit.
The changes due to our new agreements with HFC related to our Cheyenne assets resulted in an increase in the net 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 carrying value, including the related goodwill,first quarter of that reporting unit. In prior years, we used the present2021.
The estimated fair value of theour 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, recognizingCheyenne reporting unit goodwill identified an impairment loss. In 2017, wecharge of $11.0 million, which was recorded in the three months ended March 31, 2021.
Our annual goodwill impairment testing was performed on a qualitative basis during the third quarter of 2021. We assessed qualitative factors such as macroeconomic conditions, industry considerations, cost factors, and reporting unit financial performance and determined it iswas not more likely than not that the fair value of our reporting units arewas less than the respective carrying value. Therefore, in accordance with generally accepted accounting principles,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, 2017.
Contingencies
It is common in our industry to be subject to proceedings, lawsuits and other claims related to environmental, labor, product and other matters. We are required to assess the likelihood of any adverse judgments or outcomes to these types of matters as well as potential ranges of probable losses. A determination of the amount of reserves required, if any, for these types of contingencies is made after careful analysis of each individual issue. The required reserves may change in the future due to developments in each matter or changes in approach such as a change in settlement strategy in dealing with these potential matters.
Accounting Pronouncement Adopted During the Periods Presented
Share-Based Compensation
In March 2016, an accounting standard update was issued which simplifies the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows. We adopted this standard effective January 1, 2017, with no impact to our financial condition or results of operations. The new standard also requires that employee taxes paid when an employer withholds units for tax-withholding purposes be reported as financing activities in the statement of cash flows on a retrospective basis. Previously, this activity was included in operating activities. The impact of this change for the years ended December 31, 2017, 2016 and 2015 was $0.6 million, $0.8 million and $0.7 million, respectively. Finally, consistent with our existing policy, we have elected to account for forfeitures on an estimated basis.
Accounting Pronouncements Not Yet Adopted
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 has an effective date of January 1, 2018, and we intend to account for the new guidance using the modified retrospective implementation method, whereby a cumulative effect adjustment is recorded to retained earnings as of the date of initial application. In preparing for adoption, we have evaluated the terms, conditions and performance obligations under our existing contracts with customers. Furthermore, we have implemented policies to comply with this new standard, which we do not anticipate will have a material impact on our financial condition, results of operations or cash flows.
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 has an effective date of January 1, 2018, and we are evaluating its impact.
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 will become effective beginning with our 2018 reporting year. We are evaluating the impact of this standard.
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 are evaluating the impact of this standard.
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, 2017,2021, 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, 2017,2021, the fair value of our 6%5% Senior Notes was $525$502.7 million. We estimate a hypothetical 10% change in the yield-to-maturity applicable to the 6%5% Senior Notes at December 31, 2017,2021, 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, 2017,2021, borrowings outstanding under the Credit Agreement were $1,012$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.
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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, 2017,2021, 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, 2017,2021, the Partnership maintained effective internal control over financial reporting.
Management excluded SLC Pipeline and Frontier Aspen, which were acquired on October 31, 2017, from our assessment of internal control over financial reporting as of December 31, 2017. See Note 2 of the 2017 consolidated financial statements for additional information. SLC Pipeline and Frontier Aspen represent approximately 17% of consolidated total assets as of December 31, 2017, and 2% of total revenues for the year ended December 31, 2017.
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, 2017.2021. That report appears on page 60.70.
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, 2017,2021, 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, 2017,2021, based on the COSO criteria.
As indicated in the accompanying Management’s Report on its Assessment of the Partnership’s Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of SLC Pipeline LLC and Frontier Aspen LLC acquired on October 31, 2017, which are included in the 2017 consolidated financial statements of the Partnership and constituted 17% of total assets as of December 31, 2017 and 2% of revenues for the year then ended. Our audit of internal control over financial reporting of the Partnership also did not include an evaluation of the internal control over financial reporting of SLC Pipeline LLC and Frontier Aspen LLC.
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, 20172021 and 2016,2020, the related consolidated statements of income, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2017,2021, and the related notes of the Partnership and our report dated February 21, 201823, 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 21, 201823, 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, 20172021 and 2016,2020, the related consolidated statements of income, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2017,2021, 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, 20172021 and 2016,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2021, 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, 2017,2021, 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 21, 201823, 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. |
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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 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. |
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| 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 21, 201823, 2022
HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(inIn thousands, except unit data)
| | | | | December 31, 2017 | | December 31, 2016 | | December 31, 2021 | | December 31, 2020 |
| ASSETS | | | | | ASSETS | | | | |
| Current assets: | | | | | Current assets: | |
| Cash and cash equivalents | | $ | 7,776 |
| | $ | 3,657 |
| |
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 | | 12,803 |
| | 7,846 |
| Trade | | 12,745 | | | 14,543 | |
| Affiliates | | 51,501 |
| | 42,562 |
| Affiliates | | 56,154 | | | 47,972 | |
| | | 64,304 |
| | 50,408 |
| | 68,899 | | | 62,515 | |
| Prepaid and other current assets | | 2,311 |
| | 2,888 |
| Prepaid and other current assets | | 11,033 | | | 9,487 | |
| Total current assets | | 74,391 |
| | 56,953 |
| Total current assets | | 94,313 | | | 93,992 | |
| | | | | | |
| Properties and equipment, net | | 1,569,471 |
| | 1,328,395 |
| |
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 | | 129,463 |
| | 66,856 |
| Intangible assets, net | | 73,307 | | | 87,315 | |
| Goodwill | | 266,716 |
| | 256,498 |
| Goodwill | | 223,650 | | | 234,684 | |
| Equity method investments | | 85,279 |
| | 165,609 |
| |
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 | | 28,794 |
| | 9,926 |
| Other assets | | 17,613 | | | 11,050 | |
| Total assets | | $ | 2,154,114 |
| | $ | 1,884,237 |
| Total assets | | $ | 2,165,867 | | | $ | 2,167,565 | |
| | | | | | | | | |
| LIABILITIES AND EQUITY | | | | | LIABILITIES AND EQUITY | |
| Current liabilities: | | | | | Current liabilities: | |
| Accounts payable: | | | | | Accounts payable: | |
| Trade | | $ | 14,547 |
| | $ | 10,518 |
| |
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 | | 7,725 |
| | 16,424 |
| Affiliates | | 11,703 | | | 18,120 | |
| | | 22,272 |
| | 26,942 |
| | 40,280 | | | 46,400 | |
| | | | | | |
| Accrued interest | | 13,256 |
| | 18,069 |
| Accrued interest | | 11,258 | | | 10,892 | |
| Deferred revenue | | 9,598 |
| | 11,102 |
| Deferred revenue | | 14,585 | | | 11,368 | |
| Accrued property taxes | | 4,652 |
| | 5,397 |
| 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 | | 5,707 |
| | 3,225 |
| Other current liabilities | | 1,781 | | | 2,505 | |
| Total current liabilities | | 55,485 |
| | 64,735 |
| Total current liabilities | | 76,852 | | | 79,745 | |
| | | | | | |
| Long-term debt | | 1,507,308 |
| | 1,243,912 |
| 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 | | 15,843 |
| | 16,445 |
| Other long-term liabilities | | 12,527 | | | 12,905 | |
| Deferred revenue | | 47,272 |
| | 47,035 |
| Deferred revenue | | 29,662 | | | 40,581 | |
| | | | | | |
| Class B unit | | 43,141 |
| | 40,319 |
| Class B unit | | 56,549 | | | 52,850 | |
| | | | | | |
| Equity: | | | | | Equity: | |
| Partners’ equity: | | | | | Partners’ equity: | |
Common unitholders (101,568,955 and 62,780,503 units issued and outstanding at December 31, 2017 and 2016, respectively) | | 393,959 |
| | 510,975 |
| |
| General partner interest | | — |
| | (132,832 | ) | |
| Accumulated other comprehensive income | | — |
| | 91 |
| |
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 | | 393,959 |
| | 378,234 |
| Total partners’ equity | | 443,017 | | | 379,292 | |
| Noncontrolling interest | | 91,106 |
| | 93,557 |
| |
| Noncontrolling interests | | Noncontrolling interests | | 147,532 | | | 126,066 | |
| Total equity | | 485,065 |
| | 471,791 |
| Total equity | | 590,549 | | | 505,358 | |
| Total liabilities and equity | | $ | 2,154,114 |
| | $ | 1,884,237 |
| 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, |
| | | 2017 | | 2016 | | 2015 |
| Revenues: | | | | | | |
| Affiliates | | $ | 377,136 |
| | $ | 333,116 |
| | $ | 292,221 |
|
| Third parties | | 77,226 |
| | 68,927 |
| | 66,654 |
|
| | | 454,362 |
| | 402,043 |
| | 358,875 |
|
| Operating costs and expenses: | | | | | | |
| Operations (exclusive of depreciation and amortization) | | 137,605 |
| | 123,986 |
| | 105,556 |
|
| Depreciation and amortization | | 79,278 |
| | 70,428 |
| | 63,306 |
|
| General and administrative | | 14,323 |
| | 12,532 |
| | 12,556 |
|
| | | 231,206 |
| | 206,946 |
| | 181,418 |
|
| Operating income | | 223,156 |
| | 195,097 |
| | 177,457 |
|
| | | | | | | |
| Other income (expense): | | | | | | |
| Equity in earnings of equity method investments | | 12,510 |
| | 14,213 |
| | 4,803 |
|
| Interest expense | | (58,448 | ) | | (52,552 | ) | | (37,418 | ) |
| Interest income | | 491 |
| | 440 |
| | 526 |
|
| Loss on early extinguishment of debt | | (12,225 | ) | | — |
| | — |
|
| Remeasurement gain on preexisting equity interests | | 36,254 |
| | — |
| | — |
|
| Gain on sale of assets and other | | 422 |
| | 677 |
| | 486 |
|
| | | (20,996 | ) | | (37,222 | ) | | (31,603 | ) |
| Income before income taxes | | 202,160 |
| | 157,875 |
| | 145,854 |
|
| State income tax expense | | (249 | ) | | (285 | ) | | (228 | ) |
| Net income | | 201,911 |
| | 157,590 |
| | 145,626 |
|
| Allocation of net loss attributable to Predecessor | | — |
| | 10,657 |
| | 2,702 |
|
| Allocation of net income attributable to noncontrolling interests | | (6,871 | ) | | (10,006 | ) | | (11,120 | ) |
| Net income attributable to the partners | | 195,040 |
| | 158,241 |
| | 137,208 |
|
| General partner interest in net income attributable to the Partnership, including incentive distributions | | (35,047 | ) | | (57,173 | ) | | (42,337 | ) |
| Limited partners’ interest in net income | | $ | 159,993 |
| | $ | 101,068 |
| | $ | 94,871 |
|
| Limited partners’ per unit interest in earnings—basic and diluted | | $ | 2.28 |
| | $ | 1.69 |
| | $ | 1.60 |
|
| Weighted average limited partners’ units outstanding | | 70,291 |
| | 59,872 |
| | 58,657 |
|
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, |
| | | 2017 | | 2016 | | 2015 |
| Net income | | $ | 201,911 |
| | $ | 157,590 |
| | $ | 145,626 |
|
| | | | | | | |
| Other comprehensive income: | | | | | | |
| Change in fair value of cash flow hedging instruments | | 88 |
| | (607 | ) | | (1,864 | ) |
| Reclassification adjustment to net income on partial settlement of cash flow hedge | | (179 | ) | | 508 |
| | 2,100 |
|
| Other comprehensive income (loss) | | (91 | ) | | (99 | ) | | 236 |
|
| Comprehensive income before noncontrolling interest | | 201,820 |
| | 157,491 |
| | 145,862 |
|
| Allocation of net loss attributable to Predecessor | | — |
| | 10,657 |
| | 2,702 |
|
| Allocation of comprehensive income to noncontrolling interests | | (6,871 | ) | | (10,006 | ) | | (11,120 | ) |
| | | | | | | |
| Comprehensive income attributable to the partners | | $ | 194,949 |
| | $ | 158,142 |
| | $ | 137,444 |
|
See accompanying notes.
HOLLY ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In (In thousands)
| | | | | Years Ended December 31, | | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | | 2021 | | 2020 | | 2019 |
| Cash flows from operating activities | | | | | | | Cash flows from operating activities | | | | | | |
| Net income | | $ | 201,911 |
| | $ | 157,590 |
| | $ | 145,626 |
| 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 | | 79,278 |
| | 70,428 |
| | 63,306 |
| Depreciation and amortization | | 93,800 | | | 99,578 | | | 96,705 | |
| Gain on sale of assets | | (319 | ) | | (150 | ) | | (375 | ) | 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 | | 3,063 |
| | 3,247 |
| | 1,928 |
| Amortization of deferred charges | | 3,757 | | | 3,319 | | | 3,081 | |
| Equity-based compensation expense | | 2,520 |
| | 3,519 |
| | 4,180 |
| Equity-based compensation expense | | 2,557 | | | 2,193 | | | 2,532 | |
Equity in earnings of equity method investments, net of distributions
| | 1,450 |
| | (2,032 | ) | | (122 | ) | 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 | | (38 | ) | | 279 |
| | (1,820 | ) | Accounts receivable—trade | | 1,798 | | | 4,188 | | | (6,399) | |
| Accounts receivable—affiliates | | (8,939 | ) | | (10,080 | ) | | 1,419 |
| Accounts receivable—affiliates | | (8,182) | | | 1,744 | | | (2,930) | |
| Prepaid and other current assets | | 830 |
| | 1,598 |
| | (626 | ) | Prepaid and other current assets | | (255) | | | (1,272) | | | (372) | |
| Increase (decrease) in operating liabilities: | | | | | | | Increase (decrease) in operating liabilities: | |
| Accounts payable—trade | | (1,975 | ) | | (365 | ) | | (1,996 | ) | Accounts payable—trade | | 912 | | | 2,208 | | | 5,823 | |
| Accounts payable—affiliates | | (8,699 | ) | | (16 | ) | | 6,396 |
| Accounts payable—affiliates | | (6,417) | | | 1,383 | | | 2,515 | |
| Accrued interest | | (4,813 | ) | | 11,317 |
| | 137 |
| Accrued interest | | 366 | | | (2,314) | | | (96) | |
| Deferred revenue | | (1,267 | ) | | 7,058 |
| | 9,255 |
| Deferred revenue | | (1,144) | | | (4,122) | | | (151) | |
| Accrued property taxes | | (2,179 | ) | | 1,633 |
| | 1,061 |
| Accrued property taxes | | 550 | | | 193 | | | 2,020 | |
| Other current liabilities | | 2,091 |
| | (553 | ) | | (499 | ) | Other current liabilities | | (724) | | | 200 | | | (220) | |
| Other, net | | (398 | ) | | 75 |
| | 3,572 |
| Other, net | | 424 | | | 1,303 | | | (2,935) | |
| Net cash provided by operating activities | | 238,487 |
| | 243,548 |
| | 231,442 |
| 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 | | (44,810 | ) | | (59,704 | ) | | (39,393 | ) | Additions to properties and equipment | | (89,995) | | | (59,283) | | | (30,112) | |
| Acquisition of tanks and refinery processing units | | — |
| | (44,119 | ) | | (153,728 | ) | |
| Purchase of interest in Cheyenne Pipeline | | — |
| | (42,627 | ) | | — |
| |
| Purchase of interest in Frontier Aspen | | — |
| | — |
| | (55,032 | ) | |
| Purchase of controlling interests in SLC Pipeline and Frontier Aspen | | (245,446 | ) | | — |
| | — |
| |
| Proceeds from sale of assets | | 849 |
| | 427 |
| | 1,279 |
| |
| | 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 | | 3,134 |
| | 2,993 |
| | 194 |
| Distributions in excess of equity in earnings of equity investments | | 4,165 | | | 882 | | | 1,206 | |
| | Net cash used for investing activities | | (286,273 | ) | | (143,030 | ) | | (246,680 | ) | 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 | | 969,000 |
| | 554,000 |
| | 973,900 |
| Borrowings under credit agreement | | 480,500 | | | 258,500 | | | 365,500 | |
| Repayments of credit agreement borrowings | | (510,000 | ) | | (713,000 | ) | | (832,900 | ) | 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 | | 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 | | 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 | | (234,575 | ) | | (192,037 | ) | | (169,063 | ) | Distributions to HEP unitholders | | (149,432) | | | (174,443) | | | (273,225) | |
| Distributions to noncontrolling interest | | (6,500 | ) | | (5,750 | ) | | (4,625 | ) | |
| Distribution to HFC for acquisitions | | — |
| | (317,500 | ) | | (62,000 | ) | |
| Contributions from HFC for acquisitions | | — |
| | 51,262 |
| | 128,476 |
| |
| 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 | ) | | (3,555 | ) | Purchase of units for incentive grants | | (1,958) | | | (698) | | | (1,470) | |
| Units withheld for tax withholding obligations | | (605 | ) | | (800 | ) | | (696 | ) | Units withheld for tax withholding obligations | | (590) | | | (334) | | | (423) | |
| Deferred financing costs | | (9,382 | ) | | (3,995 | ) | | (962 | ) | Deferred financing costs | | (6,661) | | | (8,714) | | | — | |
| Other | | (1,112 | ) | | (1,735 | ) | | (1,154 | ) | |
| Net cash provided by (used for) financing activities | | 51,905 |
| | (111,874 | ) | | 27,421 |
| |
| | 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 | | 4,119 |
| | (11,356 | ) | | 12,183 |
| Increase (decrease) for the year | | (7,609) | | | 8,703 | | | 10,242 | |
| Beginning of year | | 3,657 |
| | 15,013 |
| | 2,830 |
| Beginning of year | | 21,990 | | | 13,287 | | | 3,045 | |
| End of year | | $ | 7,776 |
| | $ | 3,657 |
| | $ | 15,013 |
| 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, 2014 | | $ | 468,813 |
| | $ | 30,941 |
| | $ | (46 | ) | | $ | 95,082 |
| | $ | 594,790 |
|
| Distributions to HEP unitholders | | (127,152 | ) | | (41,911 | ) | | — |
| | — |
| | (169,063 | ) |
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | (4,625 | ) | | (4,625 | ) |
| Contribution from HFC for acquisitions | | — |
| | 128,477 |
| | — |
| | — |
| | 128,477 |
|
| Distribution to HFC for acquisitions | | — |
| | (62,000 | ) | | — |
| | — |
| | (62,000 | ) |
| Purchase of units for incentive grants | | (3,555 | ) | | — |
| | — |
| | — |
| | (3,555 | ) |
| Amortization of restricted and performance units | | 3,484 |
| | — |
| | — |
| | — |
| | 3,484 |
|
| Class B unit accretion | | (7,005 | ) | | (143 | ) | | — |
| | — |
| | (7,148 | ) |
| Net income | | 93,434 |
| | 48,220 |
| | — |
| | 3,972 |
| | 145,626 |
|
| Other comprehensive income | | — |
| | — |
| | 236 |
| | — |
| | 236 |
|
| 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 | ) |
| Contributions 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 | | 2,719 |
| | — |
| | — |
| | — |
| | 2,719 |
|
| Class B unit accretion | | (6,250 | ) | | (128 | ) | | — |
| | — |
| | (6,378 | ) |
| Other | | — |
| | (451 | ) | | — |
| | — |
| | (451 | ) |
| 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 | | 1,915 |
| | — |
| | — |
| | — |
| | 1,915 |
|
| Class B unit accretion | | (2,780 | ) | | (42 | ) | | — |
| | — |
| | (2,822 | ) |
| Other | | 367 |
| | — |
| | — |
| | — |
| | 367 |
|
| Net income | | 162,815 |
| | 35,047 |
| | — |
| | 4,049 |
| | 201,911 |
|
| Equity restructuring transaction | | (149,994 | ) | | 149,994 |
| | — |
| | — |
| | — |
|
| Other comprehensive loss | | — |
| | — |
| | (91 | ) | | — |
| | (91 | ) |
| Balance December 31, 2017 | | $ | 393,959 |
| | $ | — |
| | $ | — |
| | $ | 91,106 |
| | $ | 485,065 |
|
See accompanying notes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 20172021
| |
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 which is 59% owned (including the non-economic general partner interest) bypartnership. As of December 31, 2021, HollyFrontier Corporation (“HFC”) and its subsidiaries.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 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 of October 31, 2017, HFC held approximately 59.6 million HEP common units, representing approximately 59% of the outstanding common units. As a result of this transaction, no distributions were made on the general partner interest after October 31, 2017.
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 14.16.
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.
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 Certain prior period financial statements and financial information are retrospectively adjusted to include the historical results and assets of the acquisitions from HFCbalances have been reclassified 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 priorconsistency with current year balance sheet includes as equity the amount of cost incurred by HFC to that date.presentation.
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. Recoverability is determined by comparingOur 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 over the estimated fair value of athe reporting unit.
The changes due to our new agreements with HFC related to our Cheyenne assets resulted in an increase in the net 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 carrying value, including the related goodwill,first quarter of that reporting unit. In prior years, we used the present2021.
The estimated fair value of theour 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, recognizingCheyenne reporting unit goodwill identified an impairment loss. In 2017charge of $11.0 million, which was recorded in the three months ended March 31, 2021.
Our annual goodwill impairment testing for 2021 and 2016, we2019 was performed on a qualitative basis during the third quarters of 2021 and 2019. We assessed qualitative factors such as macroeconomic conditions, industry considerations, cost factors and reporting unit financial performance and determined it iswas not more likely than not that the fair value of our reporting units arewere 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, 2017.
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. See SLC Pipeline LLC ("SLC Pipeline") and Frontier Aspen LLC ("Frontier Aspen") discussion in Note 2 regarding our purchase of a controlling interest in joint ventures previously accounted for under the equity method.
| | | | | | | | | | | | | | | | | | | | |
| | 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, 2017 | | 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 | | $ | 10,631 |
| | $ | 42,071 |
| | $ | (31,440 | ) | Osage Pipe Line Company, LLC | | $ | 10,044 | | | $ | 38,743 | | | $ | (28,699) | |
| Cheyenne Pipeline LLC | | 28,706 |
| | 43,208 |
| | (14,502 | ) | 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 | | $ | 39,337 |
| | $ | 85,279 |
| | $ | (45,942 | ) | Total | | $ | 93,196 | | | $ | 120,544 | | | $ | (27,348) | |
|
| | | | | | | | | | | | |
| | | Balance at December 31, 2016 |
| | | Underlying Equity | | Recorded Investment Balance | | Difference |
| | | (in thousands) |
| Equity Method Investments | | | | | | |
| SLC Pipeline LLC | | $ | 57,273 |
| | $ | 24,417 |
| | $ | 32,856 |
|
| Frontier Aspen LLC | | 11,630 |
| | 53,160 |
| | (41,530 | ) |
| Osage Pipe Line Company, LLC | | 10,730 |
| | 43,375 |
| | (32,645 | ) |
| Cheyenne Pipeline LLC | | 29,658 |
| | 44,657 |
| | (14,999 | ) |
| Total | | $ | 109,291 |
| | $ | 165,609 |
| | $ | (56,318 | ) |
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, 20172021 and 2016,2020, we have asset retirement obligations of $8.6$8.7 million and $8.0$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 $43.1$56.5 million at December 31, 2017,2021, and $40.3$52.9 million at December 31, 2016.2020.
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. BillingsThe 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. Prior to customersthe adoption of the new lease standard (see below), we bifurcated the consideration received between lease and service revenue. The new lease standard allows the election 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 their obligations under their quarterly minimum revenue commitments are recordedthose contracts. Under this practical expedient, we treat the combined components as deferred revenue liabilitiesa single performance obligation in accordance with Accounting Standards Codification (“ASC”) 606, which largely codified ASU 2014-09, if the customer hasnon-lease (service) component is the right to receive future services fordominant 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 billings. The revenuetransactions is recognized atbased on the earlier of:
the customer receiving the future services provided by these billings,
the period in which the customer is contractually allowedactual volumes shipped as it relates specifically to receiverendering the services expires, orduring the applicable quarter.
The majority of our determination thatlong-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 not be required to provide services within the allowed period.recognize these deficiency payments in revenue.
We determine that we will not be required to provide services within the allowed period when, based on current and projected shipping levels, our pipeline systems will not have the necessary capacity to enableIn certain of these throughput agreements, a customer to exceedmay later utilize such shortfall billings as credit towards future volume shipments in excess of its minimum volume levels to such a degree as to utilize the shortfall credit 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 have additional revenues under an operating leaserecognize these deficiency payments in revenue when we do not expect we will be required to a third party of an interestsatisfy these performance obligations in the capacityfuture based on the pattern of onerights projected to be exercised by the customer. During the years ended December 31, 2021, 2020 and 2019, we recognized $17.5 million, $20.8 million and $16.0 million, respectively, of our pipelines.
these deficiency payments in revenue, of which $0.5 million, $0.7 million and $0.6 million, respectively, related to deficiency payments billed in prior periods. As of December 31, 2017, 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 $2.6 billion including $367 million for the year ending December 31, 2018, $341 million for the year ending December 31, 2019, $291 million for the year ending December 31, 2020, $284 million for the year ending December 31, 2021 and $258 million for the year ending December 31, 2022. 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
Share-Based CompensationGoodwill Impairment Testing
In March 2016, an accounting standard updateJanuary 2017, Accounting Standard Update (“ASU”) 2017-04, “Simplifying the Test for Goodwill Impairment,” was issued which simplifiesamending the accountingtesting for employee share-based payment transactions, includinggoodwill impairment by eliminating Step 2 from the accounting for income taxes, forfeitures and statutory tax withholding requirements,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 goodwill. Under this standard, goodwill impairment is measured as well as classification in the statementexcess of cash flows.the carrying amount of the reporting unit over the related fair value. We adopted this standard effective January 1, 2017, with no impact to our financial condition or results of operations. The new standard also requires that employee taxes paid when an employer withholds units for tax-withholding purposes be reported as financing activities in the statementsecond quarter of cash flows on a retrospective basis. Previously, this activity was included in operating activities. The impact2019, and the adoption of this change for the years ended December 31, 2017, 2016 and 2015 was $0.6 million, $0.8 million and $0.7 million, respectively. Finally, consistent with our existing policy, we have elected to account for forfeitures on an estimated basis.
Accounting Pronouncements Not Yet Adopted
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 has an effective date of January 1, 2018, and we intend to account for the new guidance using the modified retrospective implementation method, whereby a cumulativehad no effect adjustment is recorded to retained earnings as of the date of initial application. In preparing for adoption, we have evaluated the terms, conditions and performance obligations under our existing contracts with customers. Furthermore, we have implemented policies to comply with this new standard, which we do not anticipate will have a material impact on our financial condition, results of operations or cash flows.flows for the year ended December 31, 2019.
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 has an effective date of January 1, 2018, and we are evaluating its impact.
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 will become effective beginning with our 2018 reporting year. We are evaluating the impact of this standard.
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 are evaluatingelected to adopt 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 by the new standard, including the package of practical expedients and the short-term lease recognition practical expedient, which allows an entity to not 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 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 did not have a material impact on our financial condition, results of operations or cash flows.
Accounting Pronouncements - Not Yet Adopted
In October 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 is permitted. We will evaluate the impact of this standard.standard and consider early adoption, if applicable.
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El Dorado Tank Farm
On March 6, 2015, we completed the acquisition of an existing crude tank farm adjacent to HFC's El Dorado Refinery from an unrelated third-party for $27.5 million in cash. Substantially all of the purchase price was allocated to properties and equipment and no goodwill was recorded. HFC is the main customer of this crude tank farm.Note 2:Sinclair Acquisition
Frontier PipelineHEP Transaction
On August 31, 2015, we purchased a 50% interest in Frontier Aspen (formerly known as Frontier Pipeline Company), which owns a 289-mile crude oil pipeline running from Casper, Wyoming to Frontier Station, Utah (the "Frontier Pipeline"), from an affiliate of Enbridge, Inc. for cash consideration of $54.6 million. As described below, on October 31, 2017, we acquired the remaining 50% interest in this entity.2, 2021, HEP, The Frontier Pipeline supplies CanadianSinclair Companies (“Sinclair”) and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.
El Dorado Operating
On November 1, 2015, we acquired fromSinclair Transportation Company, a wholly owned subsidiary of HFC,Sinclair (“STC”), entered into a Contribution Agreement (the “Contribution Agreement”) pursuant to which HEP will acquire all of the outstanding membershipshares 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 in El Dorado Operatingof Hippo Holding LLC, (“El Dorado Operating”), 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 newlyHEP Transaction, the “Sinclair Transactions”).
The cash consideration for the HEP Transaction is subject to customary adjustments at closing for working capital of STC. The number of HEP 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 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.
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 in connection with the Contribution Agreement.
Note 3:Investment in Joint Venture
On October 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 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 $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 naphtha fractionation and hydrogen generationis 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 the Cushing Connect JV Terminal legal entity using the equity method of accounting. HEP's maximum exposure to loss as a result of its involvement with the Cushing Connect JV Terminal legal entity is not expected to be material due to the long-term terminalling agreements in place to support its operations.
With the exception of the assets of HEP Cushing, creditors of the Cushing Connect Joint Venture legal entities have no recourse to our assets. Any recourse to HEP Cushing would be limited to the extent 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 assets of the Cushing Connect Joint Venture legal entities.
Note 4:Revenues
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. See 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 consolidated statements of income were composed of the following lease and service revenues:
| | | | | | | | | | | | | | | | | | | | |
| | 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 sheets 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 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) | |
The contract assets and liabilities include both lease and service components. During the years ended December 31, 2021 and 2020, we recognized $0.5 million and $0.7 million, respectively, of revenue that was previously included in contract liability as of December 31, 2020 and 2019, respectively. During the twelve months ended December 31, 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, 2021, we expect to recognize $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 2022 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) |
| 2022 | | 312 | |
| 2023 | | 275 | |
| 2024 | | 238 | |
| 2025 | | 172 | |
| 2026 | | 157 | |
| Thereafter | | 484 | |
| 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.
Note 5: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 in Note 1. See Note 1 for further discussion of lease accounting.
Lessee Accounting
As a lessee, we lease land, buildings, pipelines, transportation and other equipment to support our operations. These leases can be categorized into operating and finance leases.
Our leases have remaining terms of less than 1 year to 23 years, some of which include options to extend the leases for up to 10 years.
Finance Lease Obligations
We have finance lease obligations related to vehicle leases with initial terms of 33 to 48 months. The total cost of assets under finance leases was $6.0 million and $6.4 million as of December 31, 2021 and December 31, 2020, respectively, with accumulated depreciation of $3.6 million and $3.4 million as of December 31, 2021 and December 31, 2020, respectively. We include depreciation of finance leases in depreciation and amortization in our consolidated statements of income.
In addition, we have a finance lease obligation related to a pipeline lease with an initial term of 10 years with 1 remaining subsequent renewal option for an additional 10 years.
Supplemental balance sheet information related to leases was as follows (in thousands, except for lease term and discount rate):
| | | | | | | | | | | | | | |
| | December 31, 2021 | | December 31, 2020 |
| | | | |
| Operating leases: | | | | |
| Operating lease right-of-use assets, net | | $ | 2,275 | | | $ | 2,979 | |
| | | | |
| Current operating lease liabilities | | 620 | | | 875 | |
| Noncurrent operating lease liabilities | | 2,030 | | | 2,476 | |
| Total operating lease liabilities | | $ | 2,650 | | | $ | 3,351 | |
| | | | |
| Finance leases: | | | | |
| Properties and equipment | | $ | 6,031 | | | $ | 6,410 | |
| Accumulated amortization | | (3,632) | | | (3,390) | |
| Properties and equipment, net | | $ | 2,399 | | | $ | 3,020 | |
| | | | |
| Current finance lease liabilities | | 3,786 | | | 3,713 | |
| Noncurrent finance lease liabilities | | 64,649 | | | 68,047 | |
| Total finance lease liabilities | | $ | 68,435 | | | $ | 71,760 | |
| | | | |
| Weighted average remaining lease term (in years) | | | | |
| Operating leases | | 5.8 | | 5.9 |
| Finance leases | | 15.0 | | 15.9 |
| | | | |
| Weighted average discount rate | | | | |
| Operating leases | | 4.8% | | 4.8% |
| Finance leases | | 5.6% | | 5.6% |
Supplemental cash flow and other information related to leases were as follows:
| | | | | | | | | | | | | | |
| | Year Ended
December 31, 2021 | | Year Ended
December 31, 2020 |
| | (In thousands) |
| Cash paid for amounts included in the measurement of lease liabilities: | | | | |
| Operating cash flows on operating leases | | $ | 1,142 | | | $ | 1,024 | |
| Operating cash flows on finance leases | | $ | 4,104 | | | $ | 4,312 | |
| Financing cash flows on finance leases | | $ | 3,549 | | | $ | 3,602 | |
Maturities of lease liabilities were as follows:
| | | | | | | | | | | | | | |
| | December 31, 2021 |
| | Operating | | Finance |
| | (In thousands) |
| 2022 | | $ | 690 | | | $ | 7,228 | |
| 2023 | | 603 | | | 7,374 | |
| 2024 | | 497 | | | 6,929 | |
| 2025 | | 443 | | | 6,470 | |
| 2026 | | 289 | | | 6,425 | |
| 2027 and thereafter | | 501 | | | 67,463 | |
| Total lease payments | | 3,023 | | | 101,889 | |
| Less: Imputed interest | | (373) | | | (33,454) | |
| Total lease obligations | | 2,650 | | | 68,435 | |
| Less: Current lease liabilities | | (620) | | | (3,786) | |
| Long-term lease liabilities | | $ | 2,030 | | | $ | 64,649 | |
The components of lease expense were as follows:
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, | | |
| | 2021 | | 2020 | | | |
| | (In thousands) | | |
| Operating lease costs | | $ | 1,077 | | | $ | 983 | | | | |
| Finance lease costs | | | | | | | |
| Amortization of assets | | 803 | | | 1,001 | | | | |
| Interest on lease liabilities | | 3,953 | | | 4,126 | | | | |
| Variable lease cost | | 215 | | | 222 | | | | |
| Total net lease cost | | $ | 6,048 | | | $ | 6,332 | | | | |
Lessor Accounting
As discussed in Note 1, the majority of our contracts with customers meet the definition of a lease. See Note 1 for further discussion of the impact of adoption of this standard on our activities as a lessor.
Substantially all of the assets supporting contracts meeting the definition of a lease have long useful lives, and we believe these assets will continue to have value when the current agreements expire due to our risk management strategy for protecting the residual fair value of the underlying assets by performing ongoing maintenance during the lease term. HFC generally has the option to purchase assets located within HFC refinery boundaries, including refinery tankage, truck racks and refinery processing units, at HFC’s El Dorado refinery, for cash consideration of $62.0 million. In connection with this transaction,fair market value when the related agreements expire.
During the year ended December 31, 2021, we entered into 15-year tollingnew agreements, containing minimum quarterly throughput commitments fromand amended other agreements, with HFC that provide minimum annualized revenuesrelated to our Cheyenne assets, Tulsa West lube racks, various crude tanks and new Navajo tanks, and the agreements we previously entered into relating to the Cushing Connect Pipeline became effective. These agreements met the criteria of $15 million assales-type leases since the underlying assets are not expected to have an alternative use at the end of the acquisition date. As we arelease terms to anyone other than HFC. Under sales-type lease accounting, at the commencement date, the lessor recognizes a consolidated VIE of HFC, this transaction was recorded as a transfer between entities under common control and reflects HFC’s carrying basisnet investment in El Dorado Operating’s assets and liabilities.
Osage
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 Partners (“Magellan”) will provide terminalling services for all HFC products originating in Artesia, New Mexico requiring terminalling in or through El Paso, Texas. Osage is the ownerlease, based on the estimated fair value of the Osage Pipeline, a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to HFC’s El Dorado Refinery in Kansasunderlying leased assets at contract inception, and also connects toderecognizes 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 will 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 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 millionunderlying assets with the difference recorded as a contributionselling profit or loss arising 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”), a wholly owned subsidiary of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit, and polymerization unit located at HFC’s Woods Cross refinery, for cash consideration of $278 million. The consideration was funded with $103 million in proceeds from a private placement of 3,420,000 common units with the balance funded with borrowings under our credit facility. In connection with this transaction, we entered into 15-year tolling agreements containing minimum quarterly throughput commitments from HFC that provide minimum annualized revenues of $57 million as of the acquisition date. As we are a consolidated variable interest entity (“VIE”) of HFC, this transaction was recorded as a transfer between entities under common control and reflect HFC’s carrying basis in the net assets acquired.
SLC Pipeline and Frontier Aspen
On October 31, 2017, we acquired the remaining 75% interest in SLC Pipeline LLC 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.
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, andlease. Therefore, we recognized a gain on sales-type leases during the remeasurementyear ended December 31, 2021 composed of the following:
| | | | | | | | |
| | (In thousands) |
| | |
| Net investment in leases | | $ | 148,419 | |
| Properties and equipment, net | | (130,301) | |
| Deferred Revenue | | 6,559 | |
| Gain on sales-type leases | | $ | 24,677 | |
During the year ended December 31, 2020, one of our throughput agreements with Delek US Holdings, Inc. (“Delek”) was partially renewed. A component of this agreement met the criteria of a sales-type lease since the underlying asset is not expected to have an alternative use at the end of the lease term to anyone other than Delek. We recognized a gain on sales-type leases during the year ended December 31, 2020 composed of the following:
| | | | | | | | |
| | (In thousands) |
| | |
| Net investment in leases | | $ | 35,319 | |
| Properties and equipment, net | | (1,485) | |
| | |
| Gain on sales-type leases | | $ | 33,834 | |
These sales-type lease transactions, including the related gains, were non-cash transactions.
Lease income recognized was as follows:
| | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, | | | | | |
| | 2021 | | 2020 | | | | | |
| | (In thousands) |
| Operating lease revenues | | $ | 326,902 | | | $ | 350,668 | | | | | | |
| Direct financing lease interest income | | 2,089 | | | 2,096 | | | | | | |
| Gain on sales-type leases | | 24,677 | | | 33,834 | | | | | | |
| Sales-type lease interest income | | 27,836 | | | 8,481 | | | | | | |
| Lease revenues relating to variable lease payments not included in measurement of the sales-type lease receivable | | 9,160 | | | 9,929 | | | | | | |
For our sales-type leases, we included customer obligations related to minimum volume requirements in guaranteed minimum lease payments. Portions of our minimum guaranteed pipeline tariffs for assets subject to sales-type lease accounting are recorded as interest income with the fourth quarterremaining amounts recorded as a reduction in net investment in leases. We recognized any billings for throughput volumes in excess of 2017minimum volume requirements as variable lease payments, and these variable lease payments were recorded in lease revenues.
Annual minimum undiscounted lease payment receipts under our leases were as follows as of $36.3 million. TheDecember 31, 2021:
| | | | | | | | | | | | | | | | | | | | |
| | Operating | | Finance | | Sales-type |
| Years Ending December 31, | | (In thousands) |
| 2022 | | $ | 283,882 | | | $ | 2,171 | | | $ | 42,102 | |
| 2023 | | 253,424 | | | 2,175 | | | 38,196 | |
| 2024 | | 217,321 | | | 2,192 | | | 34,967 | |
| 2025 | | 153,900 | | | 2,209 | | | 31,539 | |
| 2026 | | 139,983 | | | 2,227 | | | 31,539 | |
| Thereafter | | 418,354 | | | 36,610 | | | 247,867 | |
| Total lease payment receipts | | $ | 1,466,864 | | | 47,584 | | | 426,210 | |
| Less: Imputed interest | | | | (31,213) | | | (357,682) | |
| | | | 16,371 | | | 68,528 | |
| Unguaranteed residual assets at end of leases | | | | — | | | 229,337 | |
| Net investment in leases | | | | $ | 16,371 | | | $ | 297,865 | |
Net investments in leases recorded on our balance sheet were composed of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 | | December 31, 2020 |
| | Sales-type Leases | | Direct Financing Leases | | Sales-type Leases | | Direct Financing Leases |
| | (In thousands) | | (In thousands) |
Lease receivables (1) | | $ | 207,768 | | | $ | 16,371 | | | $ | 88,922 | | | $ | 16,452 | |
| Unguaranteed residual assets | | 90,097 | | | — | | | 64,551 | | | — | |
| Net investment in leases | | $ | 297,865 | | | $ | 16,371 | | | $ | 153,473 | | | $ | 16,452 | |
(1) Current portion of lease receivables included in prepaid and other current assets on the balance sheet.
Note 6:Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability) including assumptions about risk. GAAP categorizes inputs used in fair value of our preexisting equity method investmentsmeasurements into three broad levels as follows:
•(Level 1) Quoted prices in SLC Pipelineactive markets for identical assets or liabilities.
•(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and Frontier Aspen was estimated using liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.
•(Level 3 Inputs under the income method for these entities, adjusted for lack of control3) Unobservable inputs that are supported by little or no market activity and marketability.
The total consideration of $362 million, consisting of cash consideration of $250 million andthat are significant to the fair value of our preexisting equity method investments in SLC Pipeline and Frontier Aspen of $112 million, was allocated to the acquisition date fair value of assets and liabilities acquired as of the October 31, 2017 acquisition date, with the excess purchase price recorded as goodwill.
The following summarizes the value of assets and liabilities acquired:
|
| | | |
| | (in thousands) |
| Cash and cash equivalents | $ | 4,609 |
|
| Accounts receivable | 4,919 |
|
| Prepaid and other current assets | 253 |
|
| Properties and equipment | 277,016 |
|
| Intangible assets | 70,182 |
|
| Goodwill | 10,218 |
|
| Accounts payable | (3,694 | ) |
| Accrued property taxes | (1,438 | ) |
| Other current liabilities | (65 | ) |
| Net assets acquired | $ | 362,000 |
|
We have assigned a preliminary estimate of fair value to the assets acquired and liabilities assumed, and, therefore, our allocation may change once all needed information has become available and we complete our valuations.or liabilities. This includes valuation techniques that involve significant unobservable inputs.
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 ending December 31, 2017 included revenues of $7.9 million and net income of $4.1 million, excluding the $36.3 million remeasurement gain as of the acquisition date discussed above, for the period from November 1, 2017 through December 31, 2017.
SLC Pipeline is the owner of a 95-mile crude pipeline that transports crude oil into the Salt Lake City area from the Utah terminal of the Frontier Pipeline and from Wahsatch Station. Frontier Aspen is the owner of a 289-mile crude pipeline from Casper, Wyoming to Frontier Station, Utah that supplies Canadian and Rocky Mountain crudes to Salt Lake City area refiners through a connection to the SLC Pipeline.
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 |
| |
(3) | To eliminate the remeasurement gain on preexisting equity interests in SLC Pipeline and Frontier Aspen |
| |
Note 3: | Financial Instruments |
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, debt and interest rate swaps.debt. The carrying amounts of cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturity of these instruments. Debt consists of outstanding principal under our revolving credit agreement (which approximates fair value as interest rates are reset frequently at current interest rates) and our fixed interest rate senior notes.
Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability) including assumptions about risk. GAAP categorizes inputs used in fair value measurements into three broad levels as follows:
(Level 1) Quoted prices in active markets for identical assets or liabilities.
(Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data.
(Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs.
The carrying amounts and estimated fair values of our senior notes and interest rate swaps were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | December 31, 2021 | | December 31, 2020 |
| Financial Instrument | | Fair Value Input Level | | Carrying
Value | | Fair Value | | Carrying
Value | | Fair Value |
| | | | (In thousands) |
| Liabilities: | | | | | | | | | | |
| | | | | | | | | | |
| 5% Senior Notes | | Level 2 | | $ | 493,049 | | | $ | 502,705 | | | $ | 492,103 | | | $ | 506,540 | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | December 31, 2017 | | December 31, 2016 |
| Financial Instrument | | Fair Value Input Level | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | (In thousands) |
| Assets: | | | | | | | | | | |
| Interest rate swaps | | Level 2 | | $ | — |
| | $ | — |
| | $ | 91 |
| | $ | 91 |
|
| | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| 6.0% Senior Notes | | Level 2 | | $ | 495,308 |
| | $ | 525,120 |
| | $ | 393,393 |
| | $ | 415,500 |
|
| 6.5% Senior Notes | | Level 2 | | — |
| | — |
| | 297,519 |
| | 308,250 |
|
| | | | | $ | 495,308 |
| | $ | 525,120 |
| | $ | 690,912 |
| | $ | 723,750 |
|
Level 2 Financial Instruments
Our senior notes and interest rate swaps are measured at fair value using Level 2 inputs. The fair value of the senior notes is based on market values provided by a third-party bank, which were derived using market quotes for similar type debt instruments. See Note 10 for additional information.
Non-Recurring Fair Value Measurements
For gains on sales-type leases recognized during the years ended December 31, 2021 and 2020, the estimated fair value of the underlying leased assets at contract inception and the present value of the estimated unguaranteed residual asset at the end of the lease term are used in determining the net investment in leases and related gain on sales-type leases recorded. The asset valuation estimates include Level 3 inputs based on a replacement cost valuation method.
During the years ended December 31, 2021 and 2020, we recognized goodwill impairment based on fair value measurements utilized during our goodwill testing (see Note 1). The fair value of our interest rate swaps ismeasurements were based on the net present valuea combination of expected futurevaluation methods including discounted cash flows related to both variable and fixed-rate legsthe guideline public company and guideline transaction methods; all of the swap agreement. This measurement is computed using the forward London Interbank Offered Rate (“LIBOR”) yield curve, a market-based observable input.which are Level 3 inputs.
See
Note 7 for additional information on these instruments.7:Properties and Equipment
| |
Note 4: | Properties and Equipment
|
The carrying amounts of our properties and equipment are as follows:
| | | | | | | | | | | | | | |
| | December 31,
2021 | | December 31,
2020 |
| | | (In thousands) |
| Pipelines, terminals and tankage | | $ | 1,527,697 | | | $ | 1,575,815 | |
| Refinery assets | | 348,882 | | | 348,882 | |
| Land and right of way | | 98,837 | | | 87,076 | |
| Construction in progress | | 26,446 | | | 58,467 | |
| Other | | 48,203 | | | 46,201 | |
| | 2,050,065 | | | 2,116,441 | |
| Less accumulated depreciation | | (721,037) | | | (665,756) | |
| | $ | 1,329,028 | | | $ | 1,450,685 | |
|
| | | | | | | | |
| | | December 31,
2017 | | December 31,
2016 |
| | | (In thousands) |
| Pipelines, terminals and tankage | | $ | 1,541,722 |
| | $ | 1,246,746 |
|
| Refinery assets | | 347,338 |
| | 346,058 |
|
| Land and right of way | | 86,484 |
| | 65,331 |
|
| Construction in progress | | 12,029 |
| | 28,753 |
|
| Other | | 35,659 |
| | 27,133 |
|
| | | 2,023,232 |
| | 1,714,021 |
|
| Less accumulated depreciation | | 453,761 |
| | 385,626 |
|
| | | $ | 1,569,471 |
| | $ | 1,328,395 |
|
We capitalized $1.0 million and $0.7 million in interest related to construction projects during the years ended December 31, 2017 and 2016, respectively.
Depreciation expense was $71.1$79.2 million, $62.9$85.0 million,, and $55.8$82.6 million for the years ended December 31, 2017, 20162021, 2020 and 2015,2019, respectively, and includes depreciation of assets acquired under capital leases. Asset abandonment charges of $0.3$1.1 million, $0.6$1.0 million and $1.1$1.3 million for assets permanently removed from service were included in depreciation expense for the years ended December 31, 2017, 20162021, 2020 and 2015,2019, respectively.
Note 8:Intangible Assets
Intangible assets include transportation agreements and customer relationships that represent a portion of the total purchase price of certain assets acquired from Delek in 2005,, from HFC in 2008 prior to HEP becoming a consolidated VIE of HFC, and from Plains in 2017.2017, and from other minor acquisitions in 2018.
The carrying amounts of our intangible assets are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Useful Life | | December 31,
2021 | | December 31,
2020 |
| | | | | (In thousands) |
| Delek transportation agreement | | 30 years | | $ | 59,933 | | | $ | 59,933 | |
| HFC transportation agreements | | 10-15 years | | 75,131 | | | 75,131 | |
| Customer relationships | | 10 years | | 69,683 | | | 69,683 | |
| Other | | 20 years | | 50 | | | 50 | |
| | | | 204,797 | | | 204,797 | |
| Less accumulated amortization | | | | (131,490) | | | (117,482) | |
| Intangible assets, net | | | | $ | 73,307 | | | $ | 87,315 | |
|
| | | | | | | | | | |
| | | Useful Life | | December 31,
2017 | | December 31,
2016 |
| | | | | (In thousands) |
| Delek transportation agreement | | 30 years | | $ | 59,933 |
| | $ | 59,933 |
|
| HFC transportation agreements | | 10-15 years | | 75,131 |
| | 74,231 |
|
| Customer relationships | | 10 years | | 69,282 |
| | — |
|
| Other | | | | 50 |
| | 50 |
|
| | | | | 204,396 |
| | 134,214 |
|
| Less accumulated amortization | | | | 74,933 |
| | 67,358 |
|
| | | | | $ | 129,463 |
| | $ | 66,856 |
|
Amortization expense was $7.6 million for the year ended December 31, 2017, and $6.9$14.0 million for the years endingended December 31, 20162021, 2020 and 2015.2019, respectively. We estimate amortization expense to be $14$14.0 million for each of the next five years.2022, $9.9 million for 2023, and $9.1 million for 2024, 2025, and 2026.
We have additional transportation agreements with HFC resulting from historical transactions consisting of pipeline, terminal and tankage assets contributed to us or acquired from HFC. These transactions occurred while we were a consolidated variable interest entity of HFC; therefore, our basis in these agreements is zero and does not reflect a step-up in basis to fair value.
| |
Note 6: | Employees, Retirement and Incentive Plans |
Note 9: Employees, Retirement and Incentive Plans
Direct support for our operations is provided by Holly Logistic Services, L.L.C., ("HLS"(“HLS”), an HFC subsidiary, which utilizes personnel employed by HFC who are dedicated to performing services for us. Their costs, including salaries, bonuses, payroll taxes, benefits and other direct costs, are charged to us monthly in accordance with an omnibus agreement that we have with HFC. These employees participate in the retirement and benefit plans of HFC. Our share of retirement and benefit plan costs was $5.9$8.7 million, $5.7$7.9 million and $5.4$7.3 million for the years ended December 31, 2017, 20162021, 2020 and 2015,2019, respectively. These costs include retirement costs of $2.7$3.7 million, $2.6$3.4 million and $2.2$3.4 million for the years ended December 31, 2017, 20162021, 2020 and 2015,2019, respectively.
Under HLS’s secondment agreement with HFC (the “Secondment Agreement”), 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 related to these employees.
We have a Long-Term Incentive Plan for employees and non-employee directors who perform services for us. The Long-Term Incentive Plan consists of four5 components: restricted or phantom units, performance units, unit options, and unit appreciation rights.rights and cash awards. Our accounting policy for the recognition of compensation expense for awards with pro-rata vesting (a significant proportion of our awards) is to expense the costs ratably over the vesting periods.
As of December 31, 2017,2021, we have two2 types of incentive-basedunit-based awards outstanding, which are described below. The compensation cost charged against income was $2.7$2.6 million, $2.7$2.2 million and $3.4$2.5 million for the years ended December 31, 2017, 20162021, 2020 and 2015,2019, respectively. We currently purchase units in the open market instead of issuing new units for settlement of all unit awards under our Long-Term Incentive Plan. As of December 31, 2017, 2021, 2,500,000 units were authorized to be granted under our Long-Term Incentive Plan, of which 1,338,743753,425 have not yet been granted, assuming no forfeitures of the unvested units and full achievement of goals for the unvested performance units.
Restricted and Phantom Units
Under our Long-Term Incentive Plan, we grant restrictedphantom units to non-employee directors and phantom units to selected employees who perform services for us, with most awards vesting over a period of one to three years. We previously granted restricted units to selected employees who perform services for us, which vest over a period of three years. Although full ownership of the units does not transfer to the recipients until the units vest, the recipients have distribution rights on these units from the date of grant, and the recipients of the restricted units have voting rights on the restricted units from the date of grant.
The fair value of each restricted or phantom unit award is measured at the market price as of the date of grant and is amortized on a straight-line basis over the requisite service period for each separately vesting portion of the award.
A summary of restricted and phantom unit activity and changes during the year ended December 31, 2017,2021, is presented below:
| | | | | | | | | | | | | | |
| Phantom Units | | Units | | Weighted-
Average
Grant-Date
Fair Value |
| Outstanding at January 1, 2021 (nonvested) | | 295,992 | | | $ | 14.48 | |
| | | | |
| Granted | | 51,670 | | | 18.93 | |
| Vesting and transfer of common units to recipients | | (137,566) | | | 15.56 | |
| Forfeited | | (6,833) | | | 15.54 | |
| Outstanding at December 31, 2021 (nonvested) | | 203,263 | | | 14.85 | |
|
| | | | | | | |
| Restricted and Phantom Units | | Units | | Weighted- Average Grant-Date Fair Value |
| Outstanding at January 1, 2017 (nonvested) | | 123,988 |
| | $ | 32.96 |
|
| Granted | | 81,883 |
| | 35.59 |
|
| Vesting and transfer of common units to recipients | | (59,241 | ) | | 33.97 |
|
| Forfeited | | (27,621 | ) | | 30.79 |
|
| Outstanding at December 31, 2017 (nonvested) | | 119,009 |
| | $ | 34.77 |
|
The grant date fair values of restricted or phantom units that were vested and transferred to recipients during the years ended December 31, 2017, 20162021, 2020 and 20152019 were $2.1 million, $2.0 million $2.0and $2.1 million, and $2.5 million respectively. As of December 31, 2017,2021, there was $2.9$1.8 million of total unrecognized compensation expense related to unvested restricted and phantom unit grants, which is expected to be recognized over a weighted-average period of 1.61.4 years. For the years ended December 31, 20162020 and 2015,2019, the grant date price applied to the number of restricted or phantom units awarded was $32.16$11.92 and $34.16$23.52, respectively.
Performance Units
Under our Long-Term Incentive Plan, we grant performance units to selected executives who perform services for us. Performance units granted are payable in common units at the end of a three-yearthree-year performance period based upon meeting certain criteria over the performance period. Under the terms of our performance unit grants, some awards are subject to the growth in our distributable cash flow per common unit over the performance period. Asperiod while other awards are subject to “financial performance” and “market performance.” Financial performance is based on meeting certain earnings before interest, taxes, depreciation and amortization (“EBITDA”) targets, while market performance is based on the relative standing of December 31, 2017, estimated unit payouts for outstanding nonvested performance unit awards ranged between 100% and 150% of the target number of performance units granted.
We granted 10,881 performance units during the year ended December 31, 2017. Performance units granted in 2016 and 2017 vest over a three-year performance period ending December 31, 2019 and 2020, respectively, and are payable intotal unitholder return achieved by HEP common units.compared to peer group companies. The number of units actually earned will be based on the growth of our distributable cash flow per common unit over the performance period, andultimately issued under these awards can range from 50%0% to 150% of the target number of performance units granted. 200%.
Although common units are not transferred to the recipients until the performance units vest, the recipients have distribution rights with respect to the commontarget number of performance units subject to the award from the date of grant. The fair value of these performance units is basedgrant at the same rate as distributions paid on the grant date closing unit price of $35.62 and will apply to the number of units ultimately awarded. For the year ended December 31, 2016, the grant date closing unit price applied to the number of units awarded was $24.48 and $33.33 for the performance units granted in February and October, respectively, and for the year ended December 31, 2015, the grant date closing unit price was $34.21.our common units.
A summary of performance unit activity and changes for the year ended December 31, 2017,2021, is presented below: |
| | | | | | | |
| Performance Units | | Units |
Outstanding at January 1, 20172021 (nonvested) | | 49,52077,472 |
|
| Granted | | 10,88110,128 |
|
| Vesting and transfer of common units to recipients | | (2,262(10,881) | ) |
Forfeited | | (21,228 | ) |
Outstanding at December 31, 20172021 (nonvested) | | 36,91176,719 |
|
The grant date fair valuevalues of performance units vested and transferred to recipients was $0.1were $0.4 million, $0.4 million and $0.3 million for the yearyears ended December 31, 2017, $1.1 million for the year ended December 31, 2016,2021, 2020 and $0.5 million for the year ended December 31, 2015.2019, respectively. Based on the weighted average fair value of performance units outstanding at December 31, 2017,2021, of $1.3$1.4 million, there was $0.9$0.6 million of total unrecognized compensation expense related to nonvested performance units, which is expected to be recognized over a weighted-average period of 1.6 1.5 years.
During the year ended December 31, 2017,2021, we did notpaid $2.0 million for the purchase anyof our common units in the open market for the issuance and settlement of all unit awards under our Long-Term Incentive Plan.
Note 10:Debt
Credit Agreement
In July 2017,April 2021, we amended our senior secured revolving credit facility (the “Credit Agreement”) increasingdecreasing the size of the Credit Agreementfacility from $1.2$1.4 billion to $1.4$1.2 billion and extending the expirationmaturity date to July 2022.27, 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.
Our obligations under the Credit Agreement are collateralized by substantially all of our assets. Indebtednessassets, 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.
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 in effect at December 31, 2017 and 2016, were 3.734% and 2.978%, respectively. We incur a commitment fee on the unused portion of the Credit Agreement at an annual rate ranging from 0.30% to 0.50% based upon the ratio of our funded debt to EBITDA for the four most recently completed fiscal quarters.
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 exercising other rights and remedies. We were in compliance with the covenants as of December 31, 2017.2021.
Senior Notes
On July 19, 2016,February 4, 2020, we closed a private placement of $400$500 million in aggregate principal amount of 6%5% senior unsecured notes due in 20242028 (the “6%“5% Senior Notes”Notes”). On September 22, 2017,February 5, 2020, we closed a private placement of an additional $100redeemed the existing $500 million in aggregate offering of the 6% Senior Notes forat a combined aggregate principal amount outstandingredemption cost of $500$522.5 million, maturing in 2024.at which time we recognized a $25.9 million early extinguishment 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.
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% Senior Notes as of December 31, 2017. 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 our wholly-owned subsidiaries.subsidiaries (other than Holly Energy Finance Corp. and certain immaterial subsidiaries).
On January 4, 2017, we redeemed the $300 million aggregate principal amount of 6.5% senior notes (the "6.5% Senior Notes") at a redemption cost of $309.8 million, at which time we recognized a $12.2 million early extinguishment loss consisting of a $9.8 million debt redemption premium and unamortized discount and financing costs of $2.4 million. We funded the redemption with borrowings under our Credit Agreement.
Our purchase and contribution agreements with HFC with respect to the intermediate pipelines acquired in 2005 and the crude pipelines and tankage assets acquired in 2008, restrict us from selling these pipelines and terminals acquired from HFC. Under these agreements, we are restricted from prepaying borrowings and long-term debt to below $171 million prior to 2018, subject to certain limited exceptions.
Long-term Debt
The carrying amounts of our long-term debt are as follows:
| | | | | | | | | | | | | | |
| | December 31,
2021 | | December 31,
2020 |
| | (In thousands) |
| Credit Agreement | | | | |
| Amount outstanding | | $ | 840,000 | | | $ | 913,500 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| 5% Senior Notes | | | | |
| Principal | | 500,000 | | | 500,000 | |
| Unamortized premium and debt issuance costs | | (6,951) | | | (7,897) | |
| | 493,049 | | | 492,103 | |
| | | | |
| Total long-term debt | | $ | 1,333,049 | | | $ | 1,405,603 | |
|
| | | | | | | | |
| | | December 31,
2017 | | December 31,
2016 |
| | | (In thousands) |
| Credit Agreement | | | | |
| Amount outstanding | | $ | 1,012,000 |
| | $ | 553,000 |
|
| | | | | |
| 6% Senior Notes | | | | |
| Principal | | 500,000 |
| | 400,000 |
|
| Unamortized debt issuance costs | | (4,692 | ) | | (6,607 | ) |
| | | 495,308 |
| | 393,393 |
|
| 6.5% Senior Notes | | | | |
| Principal | | — |
| | 300,000 |
|
| Unamortized discount and debt issuance costs | | — |
| | (2,481 | ) |
| | | — |
| | 297,519 |
|
| | | | | |
| Total long-term debt | | $ | 1,507,308 |
| | $ | 1,243,912 |
|
Maturities of our long-term debt are as follows:
|
| | | | |
| Years Ending December 31, | | (In thousands) |
| 2018 | | $ | — |
|
| 2019 | | — |
|
| 2020 | | — |
|
| 2021 | | — |
|
| 2022 | | 1,012,000 |
|
| Thereafter | | 500,000 |
|
| Total | | $ | 1,512,000 |
|
Interest Rate 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 advances matured on July 31, 2017. The swaps effectively converted $150 million of our LIBOR based debt to fixed rate debt.
Additional information on our interest rate swaps is as follows:
|
| | | | | | | | | | | | |
| Derivative Instrument | | Balance Sheet Location | | Fair Value | | Location of Offsetting Balance | | Offsetting Amount |
| | | (In thousands) |
| December 31, 2016 | | | | | | | | |
| Interest rate swaps designated as cash flow hedging instrument: | | | | | | |
| Variable-to-fixed interest rate swap contract ($150 million of LIBOR based debt interest) | | Other current
assets | | $ | 91 |
| | Accumulated other comprehensive loss | | $ | 91 |
|
| | | | | $ | 91 |
| | | | $ | 91 |
|
| | | | | | | | | |
Interest Expense and Other Debt Information
Interest expense consists of the following components:
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In thousands) |
| Interest on outstanding debt: | | | | | | |
| Credit Agreement, net of interest on interest rate swaps | | $ | 28,928 |
| | $ | 17,621 |
| | $ | 16,107 |
|
| 6% Senior Notes | | 25,813 |
| | 10,811 |
| | — |
|
| 6.5% Senior Notes | | — |
| | 19,507 |
| | 19,507 |
|
| Amortization of discount and deferred debt issuance costs | | 3,063 |
| | 3,246 |
| | 1,928 |
|
| Commitment fees and other | | 1,648 |
| | 2,069 |
| | 638 |
|
| Total interest incurred | | 59,452 |
| | 53,254 |
| | 38,180 |
|
| Less capitalized interest | | 1,004 |
| | 702 |
| | 762 |
|
| Net interest expense | | $ | 58,448 |
| | $ | 52,552 |
| | $ | 37,418 |
|
| Cash paid for interest | | $ | 62,395 |
| | $ | 38,530 |
| | $ | 35,938 |
|
Capital Lease Obligations
Our capital lease obligations relate to vehicle leases with initial terms of 33 to 48 months. The total cost of assets under capital leases was $5.1 million and $4.9 millionfollows as of December 31, 2017 and 2016, respectively, with accumulated depreciation of $3.3 million and $2.4 million as of December 31, 2017 and 2016, respectively. We include depreciation of capital leases in depreciation and amortization in our consolidated statements of income.2021:
| | | | | | | | |
| Years Ending December 31, | | (In thousands) |
| 2022 | | $ | — | |
| 2023 | | — | |
| 2024 | | — | |
| 2025 | | 840,000 | |
| 2026 | | — | |
| Thereafter | | 500,000 | |
| Total | | $ | 1,340,000 | |
At December 31, 2017, future minimum annual lease payments, including interest, for the capital leases are as follows:
|
| | | |
| Years Ending December 31, | (in thousands) |
| 2018 | $ | 1,019 |
|
| 2019 | 765 |
|
| 2020 | 228 |
|
| 2021 | — |
|
| Total minimum lease payments | 2,012 |
|
| Less amount representing interest | (129 | ) |
| Capital lease obligations | $ | 1,883 |
|
| |
Note 8: | Commitments and Contingencies |
Note 11:Commitments and Contingencies
We lease certain facilities and pipelines under operating leases and finance leases, most of which contain renewal options. These operating leases have various termination dates through 2027.
2035. See Note 5 for a schedule of annual minimum undiscounted lease payments under our leases as of December 31, 2021. As of December 31, 2017, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year are as follows:
|
| | | |
| Years Ending December 31, | (In thousands) |
| 2018 | $ | 7,278 |
|
| 2019 | 6,861 |
|
| 2020 | 6,805 |
|
| 2021 | 6,755 |
|
| 2022 | 6,753 |
|
| Thereafter | 29,861 |
|
| Total | $ | 64,313 |
|
Rental expense charged to operations was $9.1 million, $8.5 million and $8.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017,2021, we expect to receive aggregate payments totaling $1.6$1.0 million over the life of our noncancelable sublease of office space, expiring in 2026.
We also have other long-term contractual obligations consisting of long-term 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 and renewable diesel 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.
In addition, we have long-term contractual obligations associated with rights-of-way agreements, which have various termination dates through 2061.2099. The related payments below include only obligations under the remaining non-cancelable terms of these agreements at December 31, 2017.2021.
At December 31, 2017,2021, these minimum future contractual obligations and other miscellaneous obligations having terms in excess of one year are as follows:
|
| | | |
| Years Ending December 31, | (In thousands) |
| 2018 | $ | 5,616 |
|
| 2019 | 5,559 |
|
| 2020 | 5,385 |
|
| 2021 | 5,380 |
|
| 2022 | 5,375 |
|
| Thereafter | 223,331 |
|
| Total | $ | 250,646 |
|
| | | | | |
| Years Ending December 31, | (In thousands) |
| 2022 | $ | 8,347 | |
| 2023 | 8,254 | |
| 2024 | 8,195 | |
| 2025 | 6,661 | |
| 2026 | 5,812 | |
| Thereafter | 218,941 | |
| Total | $ | 256,210 | |
We are a party to various legal and regulatory proceedings, none of which we believe will have a material adverse impact on our financial condition, results of operations or cash flows.
We filed a business interruption claim with our insurance carriers related to a loss at HFC's Woods Cross Refinery that occurred in the first quarter 2018. During the year ended December 31, 2020, we reached a final settlement agreement regarding the amounts owed to us pursuant to our business interruption coverage, and we recognized a gain of $7.3 million, which was included in gain on sale of assets and other on our income statement for the year ended December 31, 2020.
| |
Note 9: | Significant Customers |
All revenues are domestic revenues, of which 91% are currently generated from our two largest customers: HFC and Delek.
The following table presents the percentage of total revenues generated by each of these customers:
|
| | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| HFC | 83 | % | | 83 | % | | 81 | % |
| Delek | 8 | % | | 8 | % | | 10 | % |
| |
Note 10: | Related Party Transactions |
Note 12:Related Party Transactions
We serve HFC’s refineriesrefinery and renewable diesel facilities under long-term pipeline, terminal and tankage throughput agreements, and refinery processing unit tolling agreements expiring from 20192022 to 2036.2036, and revenues from these agreements accounted for approximately 79% of our total revenues for the year ended December 31, 2021. Under these agreements, HFC agrees to transport, store, and process throughput volumes of refined product, crude oil and feedstocks on our pipelines, terminals, tankage, loading rack facilities and refinery processing units that result in minimum annual payments to us. These minimum annual payments or revenues are generally subject to annual rate adjustments on July 1st each year based on increases or decreases in the Producer Price Index (“PPI”) or Federal Energy Regulatory Commission (“FERC”)FERC index. As of December 31, 2017,2021, these agreements with HFC require minimum annualized payments to us of $324$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 these agreements, a shortfall payment may be applied as a credit in the following four quarters after its minimum obligations are met.
Under certain provisions of an omnibus agreement we have with HFC (the “Omnibus Agreement”),the Omnibus Agreement, we pay HFC an annual administrative fee ($2.5 million in 2017)(currently $2.6 million) 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 charged to us separately by HFC. Also, we reimburse HFC and its affiliates for direct expenses they incur on our behalf.
Related party transactions with HFC are as follows:
•Revenues received from HFC were $377.1$390.8 million, $333.1$399.8 million and $292.2$411.8 million for the years ended December 31, 2017, 20162021, 2020 and 2015,2019, respectively.
•HFC charged us general and administrative services under the Omnibus Agreement of $2.5$2.6 million for each of the yearyears ended December 31, 2017, $2.5 million for the year ended December 31, 2016,2021, 2020 and $2.4 million for the year ended December 31, 2015.2019.
•We reimbursed HFC for costs of employees supporting our operations of $46.6$61.2 million, $40.9$55.8 million and $34.5$55.1 million for the years ended December 31, 2017, 20162021, 2020 and 2015,2019, respectively.
•HFC reimbursed us $7.2$7.9 million, $14.0$10.0 million and $13.5$13.9 million for the years ended December 31, 2017, 20162021, 2020 and 2015,2019, respectively, for expense and capital projects.
•We distributed $130.7$83.5 million, $105.2$95.2 million and $90.4$150.0 million, for in the years ended December 31, 2017, 20162021, 2020 and 2015,2019 respectively, to HFC as regular distributions on its common units and general partner interest, including general partner incentive distributions.
units.•Accounts receivable from HFC were $51.5$56.2 million and $42.6$48.0 million at December 31, 20172021 and 2016,2020, respectively.
•Accounts payable to HFC were $7.7$11.7 million and $16.4$18.1 million at December 31, 20172021 and 2016,2020, respectively.
•Revenues for the years ended December 31, 2017, 20162021, 2020 and 20152019 include $4.8$0.4 million, $6.1$0.5 million and $7.3$0.5 million,, respectively, of shortfall payments billed to HFC in 2016, 20152020, 2019 and 2014,2018, respectively. Deferred revenue in the consolidated balance sheets at December 31, 20172021 and 2016,2020, includes $4.4$4.1 million and $5.6$0.4 million,, respectively, relating to certain shortfall billings. It is possible that HFC may not exceed its minimum obligationsbillings to receive credit for any of the $4.4 million deferred as of December 31, 2017.
HFC.•We received operatingdirect financing lease payments from HFC for use of our Artesia and Tulsa railyards of $0.5$2.1 million for each of the years ended December 31, 2017, 20162021, 2020 and 2015.2019 .
In November 2015,•We recorded a gain on sales-type leases with HFC of $24.7 million and $35.2 million during the year ended December 31, 2021 and December 31, 2019, respectively, and we acquiredreceived sales-type lease payments of $28.9 million, $9.5 million and $4.8 million from HFC allthat were not included in revenues for the outstanding membership interestsyears ended December 31, 2021, 2020 and 2019, respectively.
•HEP and HFC reached an agreement to terminate the existing minimum volume commitments for HEP's Cheyenne assets and enter into new agreements, which were finalized and executed on February 8, 2021, with the following terms, in El Dorado Operating which ownseach 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 newly constructed naphtha fractionation 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 hydrogen generation units at HFC’s El Dorado refinery. SeeHFC 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 August 2, 2021, in connection with the Sinclair Transactions (described in Note 2 for a description of this transaction.
On February 22, 2016,above), HEP and HFC obtained a 50% membership interest in Osage in a non-monetary exchange, whereby a subsidiary of Magellan will provide terminalling services for all HFC products originating in Artesia, New Mexico that require terminalling in or through El Paso, Texas. Concurrent with this transaction, we entered into a non-monetary exchange withLetter Agreement (“Letter Agreement”) pursuant to which, among other things, HEP and HFC whereby we received HFC’s interestagreed, upon the consummation of the Sinclair Transactions, to enter into amendments to certain of the agreements by and among HEP and HFC, including the master throughput agreement, to include within the scope of such agreements the assets to be acquired by HEP pursuant to the Contribution Agreement (described in OsageNote 2 above).
In addition, the Letter Agreement provides that if, as a condition to obtaining antitrust clearance for the Sinclair Transactions, HFC enters into a definitive agreement to divest its refinery in Davis County, Utah (the “Woods Cross Refinery”), then HEP would sell certain assets located at, or relating to, the Woods Cross Refinery to HFC in exchange for our El Paso terminal. See Note 2 for a descriptioncash consideration equal to $232.5 million plus the certain accounts receivable of this transaction.
On March 31, 2016, we acquired crude oil tanks located at HFC’s Tulsa refinery from an affiliateHEP in respect of Plains for $39.5 million. See Note 2 for a descriptionsuch assets, with such sale to be effective immediately prior to the closing of this transaction.
Effective October 1, 2016, we acquired all the membership interestssale of the Woods Cross Operating, a wholly owned subsidiaryRefinery by HFC. The Letter Agreement also provides that HEP’s right to future revenues from HFC in respect of HFC, which owns the newly constructed atmospheric distillation tower, fluid catalytic cracking unit, and polymerization unit located at HFC’ssuch Woods Cross refinery, for cash considerationRefinery assets will terminate at the closing of $278 million. See Note 2 for a description of this transaction.such sale.
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.
| |
Note 11: | Partners’ Equity, Income Allocations and Cash Distributions |
Note 13: Partners’ Equity, Income Allocations and Cash Distributions
At December 31, 2017,2021, HFC held 59,630,030 of our common units, constituting a 59%57% limited partner interest in us and held the non-economic general partner interest. Additionally, HFC owned all incentive distribution rights through October 31, 2017, when an agreement was reached with HEP Logistics, our general partner, impacting its equity interest in HEP including canceling these incentive distribution rights. See Note 1 for a description of this equity restructuring transaction.
Common Unit Private Placements
On September 16, 2016, we entered into a common unit purchase agreement in which certain purchasers agreed to purchase in a private placement 3,420,000 common units representing limited partnership interests, at a price of $30.18 per common unit. The private placement closed on October 3, 2016, and we received proceeds of approximately $103 million, which were used to finance a portion of the Woods Cross acquisition discussed in Note 2.
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 partnership 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 Credit Agreement. After this common unit issuance, HFC owns a 57% limited partner interest in us.
Continuous Offering Program
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, 2017,2021, HEP hashad issued 2,241,9072,413,153 units under this program, providing $77.1$82.3 million in gross proceeds.
We intend to use our net proceeds for general partnership purposes, which may include funding working capital, repayment of debt, acquisitions and capital expenditures. Amounts repaid under our credit facility may be reborrowed from time to time.
Allocations of Net Income
Net income attributable to HEP is allocated between limitedthe partners and the general partner interest in accordance with the provisions of the partnership agreement. HEP net income allocated to the general partner includes incentive distributions that are declared subsequent to quarter end. After incentive distributions and other priority allocations are allocated to the general partner, the remaining net income attributable to HEP is allocated to the partners based on their weighted-average ownership percentage during the period.
See Note 1 for a description of the equity restructuring of the general partner interest owned by HEP Logistics, our general partner, and its IDRs that occurred on October 31, 2017. After this restructuring, the general partner interest is no longer entitled to any distributions. As a result of this transaction, no distributions will be made on the general partner interest and no net income will be allocated to the general partner after October 31, 2017.
The following table presents the allocation of the general partner interest in net income for the periods presented below:
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In thousands) |
| General partner interest in net income | | $ | 919 |
| | $ | 3,165 |
| | $ | 1,936 |
|
| General partner incentive distribution | | 34,128 |
| | 54,008 |
| | 40,401 |
|
| Net loss attributable to Predecessor | | — |
| | (10,657 | ) | | (2,702 | ) |
| Total general partner interest in net income | | $ | 35,047 |
| | $ | 46,516 |
| | $ | 39,635 |
|
Cash Distributions
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.
Within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the
quarter; less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, comply with applicable laws, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.
Prior to the equity restructuring transaction discussed in Note 1, we made distributions in the manner displayed in the table below. Subsequent to the financial restructuring, distributions are made equally to all common unit holders regardless of the amount of the distribution per unit.
|
| | | | | | |
| | | Total Quarterly Distribution | | Marginal Percentage Interest in Distributions |
| | | Target Amount | | Unitholders | | General Partner |
| Minimum quarterly distribution | | $0.25 | | 98% | | 2% |
| First target distribution | | Up to $0.275 | | 98% | | 2% |
| Second target distribution | | above $0.275 up to $0.3125 | | 85% | | 15% |
| Third target distribution | | above $0.3125 up to $0.375 | | 75% | | 25% |
| Thereafter | | Above $0.375 | | 50% | | 50% |
On January 26, 2018,21, 2022, we announced our cash distribution for the fourth quarter of 2017 2021 of $0.6500 per$0.35 per unit. The distribution iswas payable on all common units and was paid February 14, 2018,11, 2022, to all unitholders of record on February 5, 2018. However, HEP Logistics waived $2.5 million in limited partner1, 2022.
We paid cash distributions due to them as discussed in Note 1.
The following table presents the allocation of our regular quarterly cash distributions to the generaltotaling $149.4 million, $174.4 million and limited partners$273.2 million for the periods in which they apply. Our distributions are declared subsequent to quarter end; therefore, the amounts presented do not reflect distributions paid during the periods presented below.years ended December 31, 2021, 2020 and 2019, respectively.
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In thousands, except per unit data) |
| General partner interest in distribution | | $ | 2,335 |
| | $ | 4,088 |
| | $ | 3,563 |
|
| General partner incentive distribution | | 34,128 |
| | 54,008 |
| | 40,401 |
|
| Total general partner distribution | | 36,463 |
| | 58,096 |
| | 43,964 |
|
| Limited partner distribution | | 206,846 |
| | 143,796 |
| | 129,192 |
|
| Total regular quarterly cash distribution | | $ | 243,309 |
| | $ | 201,892 |
| | $ | 173,156 |
|
| Cash distribution per unit applicable to limited partners | | $ | 2.5475 |
| | $ | 2.3625 |
| | $ | 2.2025 |
|
As a master limited partnership, we distribute our available cash, which historically has exceeded our net income attributable to HEP because depreciation and amortization expense represents a non-cash charge against income. The result is a decline in our partners’ equity since our regular quarterly distributions have exceeded our quarterly net income attributable to HEP. Additionally, if the asset contributions and acquisitions from HFC had occurred while we were not a consolidated variable interest entity of HFC, our acquisition cost, in excess of HFC’s historical basis in the transferred assets, would have been recorded in our financial statements at the time of acquisition as increases to our properties and equipment and intangible assets instead of decreases to our partners’ equity.
| |
Note 12: | Net Income Per Limited Partner Unit |
Note 14: Net Income Per Limited Partner Unit
Net
Basic net income per unit applicable to the limited partners is computed usingcalculated as net income attributable to the two-class method since we had more than one classpartners, adjusted for participating securities’ share in earnings, divided by the weighted average limited partners’ units outstanding. Diluted net
income per unit assumes, when dilutive, the issuance of participating securities during the periodnet incremental units from January 1, 2017 through October 31, 2017. The classes of participating securities during this period included common units, general partnerphantom units and incentive distribution rights ("IDRs"). Due to the equity restructuring transaction described in Note 1, as of December 31, 2017, we had one class of security outstanding, commonperformance units. To the extent net income attributable to the partners exceeds or is less than cash distributions, this difference is allocated to the partners based on their weighted-average ownership percentage during the period, after consideration of any priority allocations of earnings. Theperiod. Our dilutive securities are immaterial for all periods presented.
See Note 1 for a description of the equity restructuring of the general partner interest owned by HEP Logistics, our general partner, and its IDRs that occurred on October 31, 2017. After this equity restructuring, the general partner interest is no longer entitled to any distributions and none were made on the general partner interest after October 31, 2017. In connection with this equity restructuring, HEP issued 37,250,000 of its common units to HEP Logistics on October 31, 2017.
When our financial statements are retrospectively adjusted after a dropdown transaction, the earnings of the acquired business, prior to the closing of the transaction, are allocated entirely to our general partner and presented as net income (loss) attributable to Predecessors. The earnings per unit of our limited partners prior to the close of the transaction do not change as a result of the dropdown. After the closing of a dropdown transaction, the earnings of the acquired business are allocated in accordance with our partnership agreement as previously described.
For purposes of applying the two-class method including the allocation of cash distributions in excess of earnings, netNet income per limited partner unit is computed as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| | (In thousands, except per unit data) |
| Net income attributable to the partners | | $ | 214,946 | | | $ | 170,483 | | | $ | 224,884 | |
| Less: Participating securities’ share in earnings | | (736) | | | (387) | | | — | |
| Net income attributable to common units | | 214,210 | | | 170,096 | | | 224,884 | |
| Weighted average limited partners' units outstanding | | 105,440 | | | 105,440 | | | 105,440 | |
| Limited partners' per unit interest in earnings - basic and diluted | | $ | 2.03 | | | $ | 1.61 | | | $ | 2.13 | |
Note 15:Environmental
|
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (in thousands) |
| Net income attributable to the partners | | $ | 195,040 |
| | $ | 158,241 |
| | $ | 137,208 |
|
| Less: General partner’s distribution declared (including IDRs) | | (36,463 | ) | | (58,096 | ) | | (43,964 | ) |
| Limited partner’s distribution declared on common units | | (206,846 | ) | | (143,796 | ) | | (129,192 | ) |
| Distributions in excess of net income attributable to the partners | | $ | (48,269 | ) | | $ | (43,651 | ) | | $ | (35,948 | ) |
|
| | | | | | | | | | | | |
| | | General Partner (including IDRs) | | Limited Partners’ Common Units | | Total |
| | | (In thousands, except per unit data) |
| Year Ended December 31, 2017 | | | | | | |
| Net income attributable to the partners: | | | | | | |
| Distributions declared | | $ | 36,463 |
| | $ | 206,846 |
| | $ | 243,309 |
|
| Distributions in excess of net income attributable to partnership | | (1,416 | ) | | (46,853 | ) | | (48,269 | ) |
| Net income attributable to the partners | | $ | 35,047 |
| | $ | 159,993 |
| | $ | 195,040 |
|
| Weighted average limited partners' units outstanding | | | | 70,291 |
| | |
| Limited partners' per unit interest in earnings - basic and diluted | | | | $ | 2.28 |
| | |
| | | | | | | |
| Year Ended December 31, 2016 | | | | | | |
| Net income attributable to the partners: | | | | | | |
| Distributions declared | | $ | 58,096 |
| | $ | 143,796 |
| | $ | 201,892 |
|
| Distributions in excess of net income attributable to partnership | | (873 | ) | | (42,778 | ) | | (43,651 | ) |
| Net income attributable to the partners | | $ | 57,223 |
| | $ | 101,018 |
| | $ | 158,241 |
|
| Weighted average limited partners' units outstanding | | | | 59,872 |
| | |
| Limited partners' per unit interest in earnings - basic and diluted | | | | $ | 1.69 |
| | |
| | | | | | | |
| Year Ended December 31, 2015 | | | | | | |
| Net income attributable to the partners: | | | | | | |
| Distributions declared | | $ | 43,964 |
| | $ | 129,192 |
| | $ | 173,156 |
|
| Distributions in excess of net income attributable to partnership | | (719 | ) | | (35,229 | ) | | (35,948 | ) |
| Net income attributable to the partners | | $ | 43,245 |
| | $ | 93,963 |
| | $ | 137,208 |
|
| Weighted average limited partners' units outstanding | | | | 58,657 |
| | |
| Limited partners' per unit interest in earnings - basic and diluted | | | | $ | 1.60 |
| | |
We expensed $0.5$1.9 million, $0.7$1.6 million and $3.6$0.5 million for the years ended December 31, 2017, 20162021, 2020 and 2015,2019, respectively, for environmental remediation obligations. The accrued environmental liability net of expected recoveries from indemnifying parties,related to environmental clean-up projects for which we have assumed liability or for which indemnity provided by HFC has expired reflected in our consolidated balance sheets was $6.5$3.9 million and $7.1$4.5 million atas of December 31, 20172021 and December 31, 2016,2020, respectively, of which $5.0$2.4 million and $5.4$2.5 million, respectively, were classified as other long-term liabilities. These accruals include remediation and monitoring costs expected to be incurred over an extended period of time.
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. As of December 31, 20172021 and December 31, 2016,2020, our consolidated balance sheets includeincluded additional accrued environmental liabilities of $0.8$0.3 million and $0.9$0.5 million respectively, for HFC indemnified liabilities, respectively, and other assets included equal and offsetting balances representing amounts due from HFC related to indemnifications for environmental remediation liabilities.
| |
Note 14: | Operating Segments |
Note 16:Operating Segments
Although financial information is reviewed by our chief operating decision makers from a variety of perspectives, they view the business in two2 reportable operating segments: (1) pipelines and terminals and (2) refinery processing units. These operating segments adhere to the accounting polices used for our consolidated financial statements. For a discussion of these accounting policies and a summary of our reportable operating segments' assets and derivation of revenue, see Note 1.
The pipelinesPipelines and terminals segment hashave been aggregated as one reportable segment as both pipelinepipelines and terminals (1) have similar economic characteristics, (2) similarly provide logistics services of transportation and storage of petroleum products, (3) similarly support the petroleum refining business, including distribution of its products, (4) have principally the same customers and (5) are subject to similar regulatory requirements.
We evaluate the performance of each segment based on its respective operating income. Certain general and administrative expenses and interest and financing costs are excluded from segment operating income as they are not directly attributable to a specific operatingreportable segment. Identifiable assets are those used by the segment, whereas other assets are principally equity method investments, cash, deposits and other assets that are not associated with a specific reportable operating segment.
| | | | | Years Ended December 31, | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2021 | | 2020 | | 2019 |
| | | (in thousands) | | (In thousands) |
| Revenues: | | | | | | | Revenues: | |
| Pipelines and terminals - affiliate | | $ | 300,232 |
| | $ | 300,072 |
| | $ | 289,258 |
| Pipelines and terminals - affiliate | | $ | 301,731 | | | $ | 319,487 | | | $ | 332,071 | |
| Pipelines and terminals - third-party | | 77,226 |
| | 68,927 |
| | 66,654 |
| Pipelines and terminals - third-party | | 103,646 | | | 98,039 | | | 121,027 | |
| Refinery processing units - affiliate | | 76,904 |
| | 33,044 |
| | 2,963 |
| Refinery processing units - affiliate | | 89,118 | | | 80,322 | | | 79,679 | |
| Total segment revenues | | $ | 454,362 |
| | $ | 402,043 |
| | $ | 358,875 |
| Total segment revenues | | $ | 494,495 | | | $ | 497,848 | | | $ | 532,777 | |
| | | | | | | | | | | | | |
| Segment operating income: | | | | | | | Segment operating income: | |
| Pipelines and terminals | | $ | 204,970 |
| | $ | 204,923 |
| | $ | 191,451 |
| |
Pipelines and terminals(1) | | Pipelines and terminals(1) | | $ | 180,965 | | | $ | 176,611 | | | $ | 241,843 | |
| Refinery processing units | | 32,509 |
| | 2,706 |
| | (1,438 | ) | Refinery processing units | | 38,172 | | | 38,314 | | | 32,233 | |
| Total segment operating income | | 237,479 |
| | 207,629 |
| | 190,013 |
| Total segment operating income | | 219,137 | | | 214,925 | | | 274,076 | |
| Unallocated general and administrative expenses | | (14,323 | ) | | (12,532 | ) | | (12,556 | ) | Unallocated general and administrative expenses | | (12,637) | | | (9,989) | | | (10,251) | |
| Interest and financing costs, net | | (57,957 | ) | | (52,112 | ) | | (36,892 | ) | Interest and financing costs, net | | (23,893) | | | (48,803) | | | (71,306) | |
| Loss on early extinguishment of debt | | (12,225 | ) | | — |
| | — |
| Loss on early extinguishment of debt | | — | | | (25,915) | | | — | |
| Equity in earnings of unconsolidated affiliates | | 12,510 |
| | 14,213 |
| | 4,803 |
| Equity in earnings of unconsolidated affiliates | | 12,432 | | | 6,647 | | | 5,180 | |
| Gain on sales-type leases | | Gain on sales-type leases | | 24,677 | | | 33,834 | | | 35,166 | |
| Gain on sale of assets and other | | 36,676 |
| | 677 |
| | 486 |
| Gain on sale of assets and other | | 6,179 | | | 8,691 | | | 272 | |
| Income before income taxes | | $ | 202,160 |
| | $ | 157,875 |
| | $ | 145,854 |
| Income before income taxes | | $ | 225,895 | | | $ | 179,390 | | | $ | 233,137 | |
| | | | | | | | | | | | | |
| Capital Expenditures: | | | | | | | Capital Expenditures: | |
| Pipelines and terminals | | $ | 289,993 |
| | $ | 59,704 |
| | $ | 67,406 |
| Pipelines and terminals | | $ | 87,756 | | | $ | 59,108 | | | $ | 28,743 | |
| Refinery processing units | | 263 |
| | 44,119 |
| | 125,715 |
| Refinery processing units | | 2,239 | | | 175 | | | 1,369 | |
| Total capital expenditures | | $ | 290,256 |
| | $ | 103,823 |
| | $ | 193,121 |
| Total capital expenditures | | $ | 89,995 | | | $ | 59,283 | | | $ | 30,112 | |
|
| | | | | | | | | | | | | | |
| | December 31, 2021 | | December 31, 2020 |
| | (In thousands) |
| Identifiable assets: | | | | |
Pipelines and terminals(2) | | $ | 1,737,388 | | | $ | 1,729,547 | |
| Refinery processing units | | 294,452 | | | 305,090 | |
| Other | | 134,027 | | | 132,928 | |
| Total identifiable assets | | $ | 2,165,867 | | | $ | 2,167,565 | |
(1)Pipelines and terminals segment operating income included goodwill impairment charges of $11.0 million and $35.7 million for the years ended December 31, 2021 and 2020, respectively.
(2)Includes goodwill of $223.7 million and $234.7 million as of December 31, 2021 and 2020, respectively.
Note 17: Supplemental Guarantor/Non-Guarantor Financial Information
|
| | | | | | | | |
| | | December 31, 2017 | | December 31, 2016 |
| | | (in thousands) |
| Identifiable assets: | | | | |
Pipelines and terminals(1) | | $ | 1,728,074 |
| | $ | 1,369,756 |
|
| Refinery processing units | | 328,585 |
| | 342,506 |
|
| Other | | 97,455 |
| | 171,975 |
|
| Total identifiable assets | | $ | 2,154,114 |
| | $ | 1,884,237 |
|
| |
(1) | Includes goodwill of $266.7 million and $256.5 million as of December 31, 2017 and December 31, 2016, respectively. |
| |
Note 15: | Quarterly Financial Data (Unaudited) |
Summarized quarterly financial data is as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| | | First | | Second | | Third | | Fourth | | Total |
| | | (In thousands, except per unit data) |
| Year Ended December 31, 2017 | | | | | | | | | | |
| Revenues | | $ | 105,634 |
| | $ | 109,143 |
| | $ | 110,364 |
| | $ | 129,221 |
| | $ | 454,362 |
|
| Operating income | | 51,734 |
| | 52,486 |
| | 51,736 |
| | 67,200 |
| | 223,156 |
|
| Income before income taxes | | 27,985 |
| | 42,983 |
| | 42,992 |
| | 88,200 |
| | 202,160 |
|
| Net income | | 27,879 |
| | 42,856 |
| | 43,061 |
| | 88,115 |
| | 201,911 |
|
| Net income attributable to Holly Energy Partners | | 25,563 |
| | 41,335 |
| | 42,071 |
| | 86,071 |
| | 195,040 |
|
| Limited partners’ per unit interest in net income – basic and diluted | | $ | 0.13 |
| | $ | 0.36 |
| | $ | 0.66 |
| | $ | 0.96 |
| | $ | 2.28 |
|
| Distributions per limited partner unit | | $ | 0.6200 |
| | $ | 0.6325 |
| | $ | 0.6450 |
| | $ | 0.6500 |
| | $ | 2.5475 |
|
| | | | | | | | | | | |
| Year Ended December 31, 2016 | | | | | | | | | | |
| Revenues | | $ | 102,010 |
| | $ | 94,897 |
| | $ | 92,610 |
| | $ | 112,526 |
| | $ | 402,043 |
|
| Operating income | | 54,513 |
| | 47,111 |
| | 38,924 |
| | 54,549 |
| | 195,097 |
|
| Income before income taxes | | 46,847 |
| | 39,569 |
| | 28,464 |
| | 42,995 |
| | 157,875 |
|
| Net income | | 46,751 |
| | 39,516 |
| | 28,404 |
| | 42,919 |
| | 157,590 |
|
| Net income attributable to Holly Energy Partners | | 42,975 |
| | 39,120 |
| | 34,785 |
| | 41,361 |
| | 158,241 |
|
| Limited partners’ per unit interest in net income – basic and diluted | | $ | 0.52 |
| | $ | 0.45 |
| | $ | 0.33 |
| | $ | 0.40 |
| | $ | 1.69 |
|
| Distributions per limited partner unit | | $ | 0.5750 |
| | $ | 0.5850 |
| | $ | 0.5950 |
| | $ | 0.6075 |
| | $ | 2.3625 |
|
| |
Note 16: | Supplemental Guarantor/Non-Guarantor Financial Information |
Obligations of HEP (“Parent”) under the 6%5% Senior Notes have been jointly and severally guaranteed by each of its direct and indirect 100% owned subsidiaries (“Guarantor Subsidiaries”). These guarantees are full and unconditional, subject to certain customary release provisions. These circumstances include (i) when a Guarantor Subsidiary is sold or sells all or substantially all of its assets, (ii) when a Guarantor Subsidiary is declared “unrestricted” for covenant purposes, (iii) when a Guarantor Subsidiary's guarantee of other indebtedness is terminated or released and (iv) when the requirements for legal defeasance or covenant defeasance or to discharge the senior notes have been satisfied.
The following financial information presents condensed consolidating balance sheets, statements of comprehensive income, and statements of cash flows of the Parent, the Guarantor Subsidiaries and the Non-Guarantor subsidiaries. The information has been presented as if the Parent accounted for its ownership in the Guarantor Subsidiaries and the Guarantor Restricted Subsidiaries accounted for the ownership of the Non-Guarantor Non-Restricted Subsidiaries, using the equity method of accounting.
In conjunction with the preparation of our Condensed Consolidating Balance Sheet and Statements of Comprehensive Income included below, we identified and corrected the presentation of noncontrolling interests presented in the eliminations column in prior periods to reflect such balances and activity within the respective guarantor and non-guarantor subsidiaries columns.
Condensed Consolidating Balance Sheet
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 | | Parent | | Guarantor
Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| ASSETS | | | | | | | | | | |
| Current assets: | | | | | | | | | | |
| Cash and cash equivalents | | $ | 1,273 | | | $ | (899) | | | $ | 14,007 | | | $ | — | | | $ | 14,381 | |
| Accounts receivable | | — | | | 60,418 | | | 8,816 | | | (335) | | | 68,899 | |
| | | | | | | | | | |
| Prepaid and other current assets | | 353 | | | 9,680 | | | 1,304 | | | (304) | | | 11,033 | |
| Total current assets | | 1,626 | | | 69,199 | | | 24,127 | | | (639) | | | 94,313 | |
| | | | | | | | | | |
| Properties and equipment, net | | — | | | 1,026,912 | | | 302,116 | | | — | | | 1,329,028 | |
| Operating lease right-of-use assets | | — | | | 2,189 | | | 86 | | | — | | | 2,275 | |
| Net investment in leases | | — | | | 309,301 | | | 100,032 | | | (100,030) | | | 309,303 | |
| Investment in subsidiaries | | 1,785,024 | | | 301,721 | | | — | | | (2,086,745) | | | — | |
| Intangible assets, net | | — | | | 73,307 | | | — | | | — | | | 73,307 | |
| Goodwill | | — | | | 223,650 | | | — | | | — | | | 223,650 | |
| Equity method investments | | — | | | 78,873 | | | 37,505 | | | — | | | 116,378 | |
| Other assets | | 8,118 | | | 9,495 | | | — | | | — | | | 17,613 | |
| Total assets | | $ | 1,794,768 | | | $ | 2,094,647 | | | $ | 463,866 | | | $ | (2,187,414) | | | $ | 2,165,867 | |
| | | | | | | | | | |
| LIABILITIES AND PARTNERS’ EQUITY | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | |
| Accounts payable | | $ | — | | | $ | 28,447 | | | $ | 12,168 | | | $ | (335) | | | $ | 40,280 | |
| | | | | | | | | | |
| Accrued interest | | 11,258 | | | — | | | — | | | — | | | 11,258 | |
| Deferred revenue | | — | | | 14,085 | | | 500 | | | — | | | 14,585 | |
| Accrued property taxes | | — | | | 3,364 | | | 1,178 | | | — | | | 4,542 | |
| Current operating lease liabilities | | — | | | 545 | | | 75 | | | — | | | 620 | |
| Current finance lease liabilities | | — | | | 5,566 | | | — | | | (1,780) | | | 3,786 | |
| Other current liabilities | | 3 | | | 1,513 | | | 265 | | | — | | | 1,781 | |
| Total current liabilities | | 11,261 | | | 53,520 | | | 14,186 | | | (2,115) | | | 76,852 | |
| | | | | | | | | | |
| Long-term debt | | 1,333,049 | | | — | | | — | | | — | | | 1,333,049 | |
| Noncurrent operating lease liabilities | | — | | | 2,030 | | | — | | | — | | | 2,030 | |
| Noncurrent finance lease liabilities | | — | | | 156,102 | | | — | | | (91,453) | | | 64,649 | |
| Other long-term liabilities | | 340 | | | 11,760 | | | 427 | | | — | | | 12,527 | |
| Deferred revenue | | — | | | 29,662 | | | — | | | — | | | 29,662 | |
| Class B unit | | — | | | 56,549 | | | — | | | — | | | 56,549 | |
| Equity - partners | | 450,118 | | | 1,785,024 | | | 301,721 | | | (2,093,846) | | | 443,017 | |
| Equity - noncontrolling interests | | — | | | — | | | 147,532 | | | — | | | 147,532 | |
| Total liabilities and partners’ equity | | $ | 1,794,768 | | | $ | 2,094,647 | | | $ | 463,866 | | | $ | (2,187,414) | | | $ | 2,165,867 | |
|
| | | | | | | | | | | | | | | | | | | | |
| December 31, 2017 | | Parent | | Guarantor Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| ASSETS | | | | | | | | | | |
| Current assets: | | | | | | | | | | |
| Cash and cash equivalents | | $ | 2 |
| | $ | 511 |
| | $ | 7,263 |
| | $ | — |
| | $ | 7,776 |
|
| Accounts receivable | | — |
| | 59,448 |
| | 5,038 |
| | (182 | ) | | 64,304 |
|
| Prepaid and other current assets | | 13 |
| | 2,016 |
| | 282 |
| | — |
| | 2,311 |
|
| Total current assets | | 15 |
| | 61,975 |
| | 12,583 |
| | (182 | ) | | 74,391 |
|
| | | | | | | | | | | |
| Properties and equipment, net | | — |
| | 1,213,626 |
| | 355,845 |
| | — |
| | 1,569,471 |
|
| Investment in subsidiaries | | 1,902,285 |
| | 273,319 |
| | — |
| | (2,175,604 | ) | | — |
|
| Intangible assets, net | | — |
| | 129,463 |
| | — |
| | — |
| | 129,463 |
|
| Goodwill | | — |
| | 266,716 |
| | — |
| | — |
| | 266,716 |
|
| Equity method investments | | — |
| | 85,279 |
| | — |
| | — |
| | 85,279 |
|
| Other assets | | 11,753 |
| | 17,041 |
| | — |
| | — |
| | 28,794 |
|
| Total assets | | $ | 1,914,053 |
| | $ | 2,047,419 |
| | $ | 368,428 |
| | $ | (2,175,786 | ) | | $ | 2,154,114 |
|
| | | | | | | | | | | |
| LIABILITIES AND PARTNERS’ EQUITY | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | |
| Accounts payable | | $ | — |
| | $ | 20,928 |
| | $ | 1,526 |
| | $ | (182 | ) | | $ | 22,272 |
|
| Accrued interest | | 12,500 |
| | 756 |
| | — |
| | — |
| | 13,256 |
|
| Deferred revenue | | — |
| | 8,540 |
| | 1,058 |
| | — |
| | 9,598 |
|
| Accrued property taxes | | — |
| | 3,431 |
| | 1,221 |
| | — |
| | 4,652 |
|
| Other current liabilities | | — |
| | 5,707 |
| | — |
| | — |
| | 5,707 |
|
| Total current liabilities | | 12,500 |
| | 39,362 |
| | 3,805 |
| | (182 | ) | | 55,485 |
|
| | | | | | | | | | | |
| Long-term debt | | 1,507,308 |
| | — |
| | — |
| | — |
| | 1,507,308 |
|
| Other long-term liabilities | | 286 |
| | 15,359 |
| | 198 |
| | — |
| | 15,843 |
|
| Deferred revenue | | — |
| | 47,272 |
| | — |
| | — |
| | 47,272 |
|
| Class B unit | | — |
| | 43,141 |
| | — |
| | — |
| | 43,141 |
|
| Equity - partners | | 393,959 |
| | 1,902,285 |
| | 273,319 |
| | (2,175,604 | ) | | 393,959 |
|
| Equity - noncontrolling interest | | — |
| | — |
| | 91,106 |
| | — |
| | 91,106 |
|
| Total liabilities and partners’ equity | | $ | 1,914,053 |
| | $ | 2,047,419 |
| | $ | 368,428 |
| | $ | (2,175,786 | ) | | $ | 2,154,114 |
|
Condensed Consolidating Balance Sheet
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | Parent | | Guarantor
Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| ASSETS | | | | | | | | | | |
| Current assets: | | | | | | | | | | |
| Cash and cash equivalents | | $ | 1,627 | | | $ | (987) | | | $ | 21,350 | | | $ | — | | | $ | 21,990 | |
| Accounts receivable | | — | | | 56,522 | | | 6,308 | | | (315) | | | 62,515 | |
| | | | | | | | | | |
| Prepaid and other current assets | | 349 | | | 8,366 | | | 772 | | | — | | | 9,487 | |
| Total current assets | | 1,976 | | | 63,901 | | | 28,430 | | | (315) | | | 93,992 | |
| | | | | | | | | | |
| Properties and equipment, net | | — | | | 1,087,184 | | | 363,501 | | | — | | | 1,450,685 | |
| Operating lease right-of-use assets | | — | | | 2,822 | | | 157 | | | — | | | 2,979 | |
| Net investment in leases | | — | | | 166,316 | | | — | | | — | | | 166,316 | |
| Investment in subsidiaries | | 1,789,808 | | | 286,883 | | | — | | | (2,076,691) | | | — | |
| Intangible assets, net | | — | | | 87,315 | | | — | | | — | | | 87,315 | |
| Goodwill | | — | | | 234,684 | | | — | | | — | | | 234,684 | |
| Equity method investments | | — | | | 81,089 | | | 39,455 | | | — | | | 120,544 | |
| Other assets | | 4,268 | | | 6,782 | | | — | | | — | | | 11,050 | |
| Total assets | | $ | 1,796,052 | | | $ | 2,016,976 | | | $ | 431,543 | | | $ | (2,077,006) | | | $ | 2,167,565 | |
| | | | | | | | | | |
| LIABILITIES AND PARTNERS’ EQUITY | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | |
| Accounts payable | | $ | — | | | $ | 30,252 | | | $ | 16,463 | | | $ | (315) | | | $ | 46,400 | |
| | | | | | | | | | |
| Accrued interest | | 10,892 | | | — | | | — | | | — | | | 10,892 | |
| Deferred revenue | | — | | | 10,868 | | | 500 | | | — | | | 11,368 | |
| Accrued property taxes | | — | | | 2,915 | | | 1,077 | | | — | | | 3,992 | |
| Current operating lease liabilities | | — | | | 804 | | | 71 | | | — | | | 875 | |
| Current finance lease liabilities | | — | | | 3,713 | | | — | | | — | | | 3,713 | |
| Other current liabilities | | 5 | | | 2,491 | | | 9 | | | — | | | 2,505 | |
| Total current liabilities | | 10,897 | | | 51,043 | | | 18,120 | | | (315) | | | 79,745 | |
| | | | | | | | | | |
| Long-term debt | | 1,405,603 | | | — | | | — | | | — | | | 1,405,603 | |
| Noncurrent operating lease liabilities | | — | | | 2,476 | | | — | | | — | | | 2,476 | |
| Noncurrent finance lease liabilities | | — | | | 68,047 | | | — | | | — | | | 68,047 | |
| Other long-term liabilities | | 260 | | | 12,171 | | | 474 | | | — | | | 12,905 | |
| Deferred revenue | | — | | | 40,581 | | | — | | | — | | | 40,581 | |
| Class B unit | | — | | | 52,850 | | | — | | | — | | | 52,850 | |
| Equity - partners | | 379,292 | | | 1,789,808 | | | 286,883 | | | (2,076,691) | | | 379,292 | |
| Equity - noncontrolling interests | | — | | | — | | | 126,066 | | | — | | | 126,066 | |
| Total liabilities and partners’ equity | | $ | 1,796,052 | | | $ | 2,016,976 | | | $ | 431,543 | | | $ | (2,077,006) | | | $ | 2,167,565 | |
|
| | | | | | | | | | | | | | | | | | | | |
| December 31, 2016 | | Parent | | Guarantor Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| ASSETS | | | | | | | | | | |
| Current assets: | | | | | | | | | | |
| Cash and cash equivalents | | $ | 2 |
| | $ | 301 |
| | $ | 3,354 |
| | $ | — |
| | $ | 3,657 |
|
| Accounts receivable | | — |
| | 45,056 |
| | 5,554 |
| | (202 | ) | | 50,408 |
|
| Prepaid and other current assets | | 11 |
| | 2,633 |
| | 244 |
| | — |
| | 2,888 |
|
| Total current assets | | 13 |
| | 47,990 |
| | 9,152 |
| | (202 | ) | | 56,953 |
|
| | | | | | | | | | | |
| Properties and equipment, net | | — |
| | 957,045 |
| | 371,350 |
| | — |
| | 1,328,395 |
|
| Investment in subsidiaries | | 1,086,008 |
| | 280,671 |
| | — |
| | (1,366,679 | ) | | — |
|
| Intangible assets, net | | — |
| | 66,856 |
| | — |
| | — |
| | 66,856 |
|
| Goodwill | | — |
| | 256,498 |
| | — |
| | — |
| | 256,498 |
|
| Equity method investments | | — |
| | 165,609 |
| | — |
| | — |
| | 165,609 |
|
| Other assets | | 725 |
| | 9,201 |
| | — |
| | — |
| | 9,926 |
|
| Total assets | | $ | 1,086,746 |
| | $ | 1,783,870 |
| | $ | 380,502 |
| | $ | (1,366,881 | ) | | $ | 1,884,237 |
|
| | | | | | | | | | | |
| LIABILITIES AND PARTNERS’ EQUITY | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | |
| Accounts payable | | $ | — |
| | $ | 24,245 |
| | $ | 2,899 |
| | $ | (202 | ) | | $ | 26,942 |
|
| Accrued interest | | 17,300 |
| | 769 |
| | — |
| | — |
| | 18,069 |
|
| Deferred revenue | | — |
| | 8,797 |
| | 2,305 |
| | — |
| | 11,102 |
|
| Accrued property taxes | | — |
| | 4,514 |
| | 883 |
| | — |
| | 5,397 |
|
| Other current liabilities | | 14 |
| | 3,208 |
| | 3 |
| | — |
| | 3,225 |
|
| Total current liabilities | | 17,314 |
| | 41,533 |
| | 6,090 |
| | (202 | ) | | 64,735 |
|
| | | | | | | | | | | |
| Long-term debt | | 690,912 |
| | 553,000 |
| | — |
| | — |
| | 1,243,912 |
|
| Other long-term liabilities | | 286 |
| | 15,975 |
| | 184 |
| | — |
| | 16,445 |
|
| Deferred revenue | | — |
| | 47,035 |
| | — |
| | — |
| | 47,035 |
|
| Class B unit | | — |
| | 40,319 |
| | — |
| | — |
| | 40,319 |
|
| Equity - partners | | 378,234 |
| | 1,086,008 |
| | 280,671 |
| | (1,366,679 | ) | | 378,234 |
|
| Equity - noncontrolling interest | | — |
| | — |
| | 93,557 |
| | — |
| | 93,557 |
|
| Total liabilities and partners’ equity | | $ | 1,086,746 |
| | $ | 1,783,870 |
| | $ | 380,502 |
| | $ | (1,366,881 | ) | | $ | 1,884,237 |
|
Condensed Consolidating Statement of Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2021 | | Parent | | Guarantor
Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| Revenues: | | | | | | | | | | |
| Affiliates | | $ | — | | | $ | 365,889 | | | $ | 24,960 | | | $ | — | | | $ | 390,849 | |
| Third parties | | — | | | 77,815 | | | 25,831 | | | — | | | 103,646 | |
| | — | | | 443,704 | | | 50,791 | | | — | | | 494,495 | |
| Operating costs and expenses: | | | | | | | | | | |
| Operations (exclusive of depreciation and amortization) | | — | | | 152,913 | | | 17,611 | | | — | | | 170,524 | |
| Depreciation and amortization | | — | | | 76,666 | | | 17,134 | | | — | | | 93,800 | |
| General and administrative | | 3,647 | | | 8,990 | | | — | | | — | | | 12,637 | |
| Goodwill impairment | | — | | | 11,034 | | | — | | | — | | | 11,034 | |
| | 3,647 | | | 249,603 | | | 34,745 | | | — | | | 287,995 | |
| Operating income (loss) | | (3,647) | | | 194,101 | | | 16,046 | | | — | | | 206,500 | |
| Equity in earnings of subsidiaries | | 275,558 | | | 16,589 | | | — | | | (292,147) | | | — | |
| Equity in earnings of equity method investments | | — | | | 8,897 | | | 3,535 | | | — | | | 12,432 | |
| Interest expense | | (49,864) | | | (8,174) | | | — | | | 4,220 | | | (53,818) | |
| Interest income | | — | | | 29,925 | | | 4,220 | | | (4,220) | | | 29,925 | |
| Gain on sales-type lease | | — | | | 31,778 | | | — | | | (7,101) | | | 24,677 | |
| | | | | | | | | | |
| Gain on sale of assets and other | | — | | | 6,174 | | | 5 | | | — | | | 6,179 | |
| | 225,694 | | | 85,189 | | | 7,760 | | | (299,248) | | | 19,395 | |
| Income (loss) before income taxes | | 222,047 | | | 279,290 | | | 23,806 | | | (299,248) | | | 225,895 | |
| State income tax expense | | — | | | (32) | | | — | | | — | | | (32) | |
| Net income (loss) | | 222,047 | | | 279,258 | | | 23,806 | | | (299,248) | | | 225,863 | |
| Allocation of net income attributable to noncontrolling interests | | — | | | (3,699) | | | (7,218) | | | — | | | (10,917) | |
| Net income (loss) attributable to the Partnership | | 222,047 | | | 275,559 | | | 16,588 | | | (299,248) | | | 214,946 | |
| Other comprehensive income (loss) | | — | | | — | | | — | | | — | | | — | |
| Comprehensive income (loss) attributable to the Partnership | | $ | 222,047 | | | $ | 275,559 | | | $ | 16,588 | | | $ | (299,248) | | | $ | 214,946 | |
|
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2017 | | Parent | | Guarantor Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| Revenues: | | | | | | | | | | |
| Affiliates | | $ | — |
| | $ | 351,395 |
| | $ | 25,741 |
| | $ | — |
| | $ | 377,136 |
|
| Third parties | | — |
| | 55,400 |
| | 21,826 |
| | — |
| | 77,226 |
|
| | | — |
| | 406,795 |
| | 47,567 |
| | — |
| | 454,362 |
|
| Operating costs and expenses: | | | | | | | | | | |
| Operations (exclusive of depreciation and amortization) | | — |
| | 122,619 |
| | 14,986 |
| | — |
| | 137,605 |
|
| Depreciation and amortization | | — |
| | 62,889 |
| | 16,389 |
| | — |
| | 79,278 |
|
| General and administrative | | 4,170 |
| | 10,153 |
| | — |
| | — |
| | 14,323 |
|
| | | 4,170 |
| | 195,661 |
| | 31,375 |
| | — |
| | 231,206 |
|
| Operating income (loss) | | (4,170 | ) | | 211,134 |
| | 16,192 |
| | — |
| | 223,156 |
|
| Equity in earnings of subsidiaries | | 254,695 |
| | 12,148 |
| | — |
| | (266,843 | ) | | — |
|
| Equity in earnings of equity method investments | | — |
| | 12,510 |
| | — |
| | — |
| | 12,510 |
|
| Interest income | | — |
| | 491 |
| | — |
| | — |
| | 491 |
|
| Interest expense | | (43,260 | ) | | (15,188 | ) | | — |
| | — |
| | (58,448 | ) |
| 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 | | — |
| | 417 |
| | 5 |
| | — |
| | 422 |
|
| | | 199,210 |
| | 46,632 |
| | 5 |
| | (266,843 | ) | | (20,996 | ) |
| Income (loss) before income taxes | | 195,040 |
| | 257,766 |
| | 16,197 |
| | (266,843 | ) | | 202,160 |
|
| State income tax expense | | — |
| | (249 | ) | | — |
| | — |
| | (249 | ) |
| Net income (loss) | | 195,040 |
| | 257,517 |
| | 16,197 |
| | (266,843 | ) | | 201,911 |
|
| Allocation of net loss applicable to Predecessor | | — |
| | — |
| | — |
| | — |
| | — |
|
| Allocation of net income attributable to noncontrolling interests | | — |
| | (2,822 | ) | | (4,049 | ) | | — |
| | (6,871 | ) |
| Net income (loss) attributable to the Partnership | | 195,040 |
| | 254,695 |
| | 12,148 |
| | (266,843 | ) | | 195,040 |
|
| Other comprehensive income (loss) | | (91 | ) | | (91 | ) | | — |
| | 91 |
| | (91 | ) |
| Comprehensive income (loss) attributable to the Partnership | | $ | 194,949 |
| | $ | 254,604 |
| | $ | 12,148 |
| | $ | (266,752 | ) | | $ | 194,949 |
|
Condensed Consolidating Statement of Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2020 | | Parent | | Guarantor
Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated | | |
| | | (In thousands) | | |
| Revenues: | | | | | | | | | | | | |
| Affiliates | | $ | — | | | $ | 374,108 | | | $ | 25,701 | | | $ | — | | | $ | 399,809 | | | |
| Third parties | | — | | | 77,039 | | | 21,000 | | | — | | | 98,039 | | | |
| | — | | | 451,147 | | | 46,701 | | | — | | | 497,848 | | | |
| Operating costs and expenses: | | | | | | | | | | | | |
| Operations (exclusive of depreciation and amortization) | | — | | | 132,393 | | | 15,299 | | | — | | | 147,692 | | | |
| Depreciation and amortization | | — | | | 82,442 | | | 17,136 | | | — | | | 99,578 | | | |
| General and administrative | | 3,227 | | | 6,762 | | | — | | | — | | | 9,989 | | | |
| Goodwill Impairment | | — | | | 35,653 | | | — | | | — | | | 35,653 | | | 35,653 | |
| | 3,227 | | | 257,250 | | | 32,435 | | | — | | | 292,912 | | | |
| Operating income (loss) | | (3,227) | | | 193,897 | | | 14,266 | | | — | | | 204,936 | | | |
| Equity in earnings of subsidiaries | | 254,608 | | | 15,409 | | | — | | | (270,017) | | | — | | | |
| Equity in earnings of equity method investments | | — | | | 5,105 | | | 1,542 | | | — | | | 6,647 | | | |
| Interest income | | 26 | | | 10,578 | | | 17 | | | — | | | 10,621 | | | |
| Interest expense | | (55,298) | | | (4,126) | | | — | | | — | | | (59,424) | | | |
| Gain on sales-type lease | | — | | | 33,834 | | | — | | | — | | | 33,834 | | | |
| Loss on early extinguishment of debt | | (25,915) | | | — | | | — | | | — | | | (25,915) | | | |
| Gain on sale of assets and other | | 289 | | | 3,535 | | | 4,867 | | | — | | | 8,691 | | | |
| | | | | | | | | | | | |
| | 173,710 | | | 64,335 | | | 6,426 | | | (270,017) | | | (25,546) | | | |
| Income (loss) before income taxes | | 170,483 | | | 258,232 | | | 20,692 | | | (270,017) | | | 179,390 | | | |
| State income tax expense | | — | | | (167) | | | — | | | — | | | (167) | | | |
| Net income (loss) | | 170,483 | | | 258,065 | | | 20,692 | | | (270,017) | | | 179,223 | | | |
| Allocation of net income attributable to noncontrolling interests | | — | | | (3,457) | | | (5,283) | | | — | | | (8,740) | | | |
| Net income (loss) attributable to the Partnership | | 170,483 | | | 254,608 | | | 15,409 | | | (270,017) | | | 170,483 | | | |
| Other comprehensive income (loss) | | — | | | — | | | — | | | — | | | — | | | |
| Comprehensive income (loss) attributable to the Partnership | | $ | 170,483 | | | $ | 254,608 | | | $ | 15,409 | | | $ | (270,017) | | | $ | 170,483 | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2016 | | Parent | | Guarantor Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| Revenues: | | | | | | | | | | |
| Affiliates | | $ | — |
| | $ | 307,049 |
| | $ | 26,067 |
| | $ | — |
| | $ | 333,116 |
|
| Third parties | | — |
| | 47,326 |
| | 21,601 |
| | — |
| | 68,927 |
|
| | | — |
| | 354,375 |
| | 47,668 |
| | — |
| | 402,043 |
|
| Operating costs and expenses: | | | | | | | | | | |
| Operations (exclusive of depreciation and amortization) | | — |
| | 111,181 |
| | 12,805 |
| | — |
| | 123,986 |
|
| Depreciation and amortization | | — |
| | 55,083 |
| | 15,345 |
| | — |
| | 70,428 |
|
| General and administrative | | 3,804 |
| | 8,728 |
| | — |
| | — |
| | 12,532 |
|
| | | 3,804 |
| | 174,992 |
| | 28,150 |
| | — |
| | 206,946 |
|
| Operating income (loss) | | (3,804 | ) | | 179,383 |
| | 19,518 |
| | — |
| | 195,097 |
|
| Equity in earnings of subsidiaries | | 193,432 |
| | 14,634 |
| | — |
| | (208,066 | ) | | — |
|
| Equity in earnings of equity method investments | | — |
| | 14,213 |
| | — |
| | — |
| | 14,213 |
|
| Interest income | | — |
| | 421 |
| | 19 |
| | — |
| | 440 |
|
| Interest expense | | (31,387 | ) | | (21,165 | ) | | — |
| | — |
| | (52,552 | ) |
| Gain on sale of assets and other | | — |
| | 702 |
| | (25 | ) | | — |
| | 677 |
|
| | | 162,045 |
| | 8,805 |
| | (6 | ) | | (208,066 | ) | | (37,222 | ) |
| Income (loss) before income taxes | | 158,241 |
| | 188,188 |
| | 19,512 |
| | (208,066 | ) | | 157,875 |
|
| State income tax expense | | — |
| | (285 | ) | | — |
| | — |
| | (285 | ) |
| Net income (loss) | | 158,241 |
| | 187,903 |
| | 19,512 |
| | (208,066 | ) | | 157,590 |
|
| Allocation of net loss applicable to Predecessor | | — |
| | 10,657 |
| | — |
| | — |
| | 10,657 |
|
| Allocation of net income attributable to noncontrolling interests | | — |
| | (5,128 | ) | | (4,878 | ) | | — |
| | (10,006 | ) |
| Net income (loss) attributable to the Partnership | | 158,241 |
| | 193,432 |
| | 14,634 |
| | (208,066 | ) | | 158,241 |
|
| Other comprehensive income (loss) | | (99 | ) | | (99 | ) | | — |
| | 99 |
| | (99 | ) |
| Comprehensive income (loss) attributable to the Partnership | | $ | 158,142 |
| | $ | 193,333 |
| | $ | 14,634 |
| | $ | (207,967 | ) | | $ | 158,142 |
|
Condensed Consolidating Statement of Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2019 | | Parent | | Guarantor
Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| Revenues: | | | | | | | | | | |
| Affiliates | | $ | — | | | $ | 386,517 | | | $ | 25,233 | | | $ | — | | | $ | 411,750 | |
| Third parties | | — | | | 94,083 | | | 26,944 | | | — | | | 121,027 | |
| | — | | | 480,600 | | | 52,177 | | | — | | | 532,777 | |
| Operating costs and expenses: | | | | | | | | | | |
| Operations (exclusive of depreciation and amortization) | | — | | | 147,387 | | | 14,609 | | | — | | | 161,996 | |
| Depreciation and amortization | | — | | | 79,516 | | | 17,189 | | | — | | | 96,705 | |
| General and administrative | | 3,184 | | | 7,067 | | | — | | | — | | | 10,251 | |
| | 3,184 | | | 233,970 | | | 31,798 | | | — | | | 268,952 | |
| Operating income (loss) | | (3,184) | | | 246,630 | | | 20,379 | | | — | | | 263,825 | |
| Equity in earnings (loss) of subsidiaries | | 302,148 | | | 15,351 | | | — | | | (317,499) | | | — | |
| Equity in earnings of equity method investments | | — | | | 5,320 | | | (140) | | | — | | | 5,180 | |
| Interest income | | — | | | 5,517 | | | — | | | — | | | 5,517 | |
| Interest expense | | (74,375) | | | (2,448) | | | — | | | — | | | (76,823) | |
| Gain on sales-type lease | | — | | | 35,166 | | | — | | | — | | | 35,166 | |
| | | | | | | | | | |
| Gain on sale of assets and other | | 295 | | | (116) | | | 93 | | | — | | | 272 | |
| | 228,068 | | | 58,790 | | | (47) | | | (317,499) | | | (30,688) | |
| Income (loss) before income taxes | | 224,884 | | | 305,420 | | | 20,332 | | | (317,499) | | | 233,137 | |
| State income tax expense | | — | | | (41) | | | — | | | — | | | (41) | |
| Net income (loss) | | 224,884 | | | 305,379 | | | 20,332 | | | (317,499) | | | 233,096 | |
| Allocation of net income attributable to noncontrolling interests | | — | | | (3,231) | | | (4,981) | | | — | | | (8,212) | |
| Net income (loss) attributable to the Partnership | | 224,884 | | | 302,148 | | | 15,351 | | | (317,499) | | | 224,884 | |
| Other comprehensive income (loss) | | — | | | — | | | — | | | — | | | — | |
| Comprehensive income (loss) attributable to the Partnership | | $ | 224,884 | | | $ | 302,148 | | | $ | 15,351 | | | $ | (317,499) | | | $ | 224,884 | |
|
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2015 | | Parent | | Guarantor Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| Revenues: | | | | | | | | | | |
| Affiliates | | $ | — |
| | $ | 269,277 |
| | $ | 22,944 |
| | $ | — |
| | $ | 292,221 |
|
| Third parties | | — |
| | 47,189 |
| | 19,465 |
| | — |
| | 66,654 |
|
| | | — |
| | 316,466 |
| | 42,409 |
| | — |
| | 358,875 |
|
| Operating costs and expenses: | | | | | | | | | | |
| Operations (exclusive of depreciation and amortization) | | — |
| | 94,087 |
| | 11,469 |
| | — |
| | 105,556 |
|
| Depreciation and amortization | | — |
| | 48,302 |
| | 15,004 |
| | — |
| | 63,306 |
|
| General and administrative | | 3,616 |
| | 8,940 |
| | — |
| | — |
| | 12,556 |
|
| | | 3,616 |
| | 151,329 |
| | 26,473 |
| | — |
| | 181,418 |
|
| Operating income (loss) | | (3,616 | ) | | 165,137 |
| | 15,936 |
| | — |
| | 177,457 |
|
| Equity in earnings (loss) of subsidiaries | | 161,097 |
| | 11,915 |
| | — |
| | (173,012 | ) | | — |
|
| Equity in earnings of equity method investments | | — |
| | 4,803 |
| | — |
| | — |
| | 4,803 |
|
| Interest income | | — |
| | 526 |
| | — |
| | — |
| | 526 |
|
| Interest expense | | (20,273 | ) | | (17,145 | ) | | — |
| | — |
| | (37,418 | ) |
| Gain on sale of assets and other | | — |
| | 535 |
| | (49 | ) | | — |
| | 486 |
|
| | | 140,824 |
| | 634 |
| | (49 | ) | | (173,012 | ) | | (31,603 | ) |
| Income (loss) before income taxes | | 137,208 |
| | 165,771 |
| | 15,887 |
| | (173,012 | ) | | 145,854 |
|
| State income tax expense | | — |
| | (228 | ) | | — |
| | — |
| | (228 | ) |
| Net income (loss) | | 137,208 |
| | 165,543 |
| | 15,887 |
| | (173,012 | ) | | 145,626 |
|
| Allocation of net loss applicable to Predecessors | | — |
| | 2,702 |
| | — |
| | — |
| | 2,702 |
|
| Allocation of net income attributable to noncontrolling interests | | — |
| | (7,148 | ) | | (3,972 | ) | | — |
| | (11,120 | ) |
| Net income (loss) attributable to the Partnership | | 137,208 |
| | 161,097 |
| | 11,915 |
| | (173,012 | ) | | 137,208 |
|
| Other comprehensive income (loss) | | 236 |
| | 236 |
| | — |
| | (236 | ) | | 236 |
|
| Comprehensive income (loss) attributable to the Partnership | | $ | 137,444 |
| | $ | 161,333 |
| | $ | 11,915 |
| | $ | (173,248 | ) | | $ | 137,444 |
|
Condensed Consolidating Statement of Cash Flows
|
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2017 | | Parent | | Guarantor Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| Cash flows from operating activities | | $ | (51,235 | ) | | $ | 268,978 |
| | $ | 32,892 |
| | $ | (12,148 | ) | | $ | 238,487 |
|
| | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | |
| Additions to properties and equipment | | — |
| | (41,827 | ) | | (2,983 | ) | | — |
| | (44,810 | ) |
| Purchase of controlling interests in SLC Pipeline and Frontier Aspen | | — |
| | (245,446 | ) | | — |
| | — |
| | (245,446 | ) |
| Proceeds from the sale of assets | | — |
| | 849 |
| | — |
| | — |
| | 849 |
|
| Distributions in excess of equity in earnings of equity method investments | | — |
| | 3,134 |
| | — |
| | — |
| | 3,134 |
|
| Distributions from UNEV in excess of earnings | | — |
| | 7,352 |
| | — |
| | (7,352 | ) | | — |
|
| | | — |
| | (275,938 | ) | | (2,983 | ) | | (7,352 | ) | | (286,273 | ) |
| Cash flows from financing activities | | | | | | | | | | |
| Net repayments under credit agreement | | 1,012,000 |
| | (553,000 | ) | | — |
| | — |
| | 459,000 |
|
| Net intercompany financing activities | | (561,675 | ) | | 561,675 |
| | — |
| | — |
| | — |
|
| Redemption of notes | | (309,750 | ) | | — |
| | — |
| | — |
| | (309,750 | ) |
| Proceeds from issuance of 6% Senior Notes | | 101,750 |
| | — |
| | — |
| | — |
| | 101,750 |
|
| Proceeds from issuance of common units | | 52,100 |
| | 10 |
| | — |
| | — |
| | 52,110 |
|
| Contributions from general partner | | 1,440 |
| | (368 | ) | | — |
| | — |
| | 1,072 |
|
| Distributions to HEP unitholders | | (234,575 | ) | | — |
| | — |
| | — |
| | (234,575 | ) |
| Distributions to noncontrolling interest | | — |
| | — |
| | (26,000 | ) | | 19,500 |
| | (6,500 | ) |
| Contributions to HFC for El Dorado Operating Tanks | | (103 | ) | | — |
| | — |
| | — |
| | (103 | ) |
| Deferred financing costs | | (9,347 | ) | | (35 | ) | | — |
| | — |
| | (9,382 | ) |
| Units withheld for tax withholding obligations | | (605 | ) | | — |
| | — |
| | — |
| | (605 | ) |
| Other | | — |
| | (1,112 | ) | | — |
| | — |
| | (1,112 | ) |
| | | 51,235 |
| | 7,170 |
| | (26,000 | ) | | 19,500 |
| | 51,905 |
|
| Cash and cash equivalents | | | | | | | | | | |
| Increase for the period | | — |
| | 210 |
| | 3,909 |
| | — |
| | 4,119 |
|
| Beginning of period | | 2 |
| | 301 |
| | 3,354 |
| | — |
| | 3,657 |
|
| End of period | | $ | 2 |
| | $ | 511 |
| | $ | 7,263 |
| | $ | — |
| | $ | 7,776 |
|
Condensed Consolidating Statement of Cash Flows |
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2016 | | Parent | | Guarantor Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| Cash flows from operating activities | | $ | (19,641 | ) | | $ | 245,771 |
| | $ | 32,052 |
| | $ | (14,634 | ) | | $ | 243,548 |
|
| | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | |
| Additions to properties and equipment | | — |
| | (44,447 | ) | | (15,257 | ) | | — |
| | (59,704 | ) |
| Acquisition of tanks and refinery processing units | | — |
| | (44,119 | ) | | — |
| | — |
| | (44,119 | ) |
| Purchase of interest in Cheyenne Pipeline | | — |
| | (42,627 | ) | | — |
| | — |
| | (42,627 | ) |
| Proceeds from sale of assets | | — |
| | 427 |
| | — |
| | — |
| | 427 |
|
| Distributions from UNEV in excess of earnings | | — |
| | 2,616 |
| | — |
| | (2,616 | ) | | — |
|
| Distribution in excess of equity in earnings in equity investments | | — |
| | 2,993 |
| | — |
| | — |
| | 2,993 |
|
| | | — |
| | (125,157 | ) | | (15,257 | ) | | (2,616 | ) | | (143,030 | ) |
| | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | |
| Net borrowings under credit agreement | | — |
| | (159,000 | ) | | — |
| | — |
| | (159,000 | ) |
| Net intercompany financing activities | | (302,600 | ) | | 302,600 |
| | — |
| | — |
| | — |
|
| Proceeds from issuance of 6% Senior Notes | | 394,000 |
| | — |
| | — |
| | — |
| | 394,000 |
|
| Proceeds from issuance of common units | | 125,870 |
| | — |
| | — |
| | — |
| | 125,870 |
|
| Contributions from General partner | | 2,577 |
| | — |
| | — |
| | — |
| | 2,577 |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | (23,000 | ) | | 17,250 |
| | (5,750 | ) |
| Distributions to HEP unitholders | | (192,037 | ) | | — |
| | — |
| | — |
| | (192,037 | ) |
| Distributions to HFC for acquisitions | | (30,378 | ) | | (287,122 | ) | | — |
| | — |
| | (317,500 | ) |
| Contributions from HFC for acquisitions | | (3,397 | ) | | 54,659 |
| | — |
| | — |
| | 51,262 |
|
| Distributions to HFC for acquisitions | | 31,287 |
| | (31,287 | ) | | — |
| | — |
| | — |
|
| Distribution to HFC for Osage acquisition | | — |
| | (1,245 | ) | | — |
| | — |
| | (1,245 | ) |
| Deferred financing costs | | (910 | ) | | (3,085 | ) | | — |
| | — |
| | (3,995 | ) |
| Purchase of units for incentive grants | | (3,521 | ) | | — |
| | — |
| | — |
| | (3,521 | ) |
| Units withheld for tax withholding obligations | | (800 | ) | | — |
| | — |
| | — |
| | (800 | ) |
| Other | | (450 | ) | | (1,285 | ) | | — |
| | — |
| | (1,735 | ) |
| | | 19,641 |
| | (125,765 | ) | | (23,000 | ) | | 17,250 |
| | (111,874 | ) |
| Cash and cash equivalents | | | | | | | | | | |
| Increase (decrease) for the period | | — |
| | (5,151 | ) | | (6,205 | ) | | — |
| | (11,356 | ) |
| Beginning of period | | 2 |
| | 5,452 |
| | 9,559 |
| | — |
| | 15,013 |
|
| End of period | | $ | 2 |
| | $ | 301 |
| | $ | 3,354 |
| | $ | — |
| | $ | 3,657 |
|
Condensed Consolidating Statement of Cash Flows
|
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2015 | | Parent | | Guarantor Restricted Subsidiaries | | Non-Guarantor Non-Restricted Subsidiaries | | Eliminations | | Consolidated |
| | | (In thousands) |
| Cash flows from operating activities | | $ | (18,794 | ) | | $ | 232,650 |
| | $ | 29,501 |
| | $ | (11,915 | ) | | $ | 231,442 |
|
| | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | |
| Additions to properties and equipment | | — |
| | (37,951 | ) | | (1,442 | ) | | — |
| | (39,393 | ) |
| Acquisition of tanks and operating units | | — |
| | (153,728 | ) | | — |
| | — |
| | (153,728 | ) |
| Purchase of investment in Frontier Pipeline | | — |
| | (55,032 | ) | | — |
| | — |
| | (55,032 | ) |
| Proceeds from sale of assets | | — |
| | 1,279 |
| | — |
| | — |
| | 1,279 |
|
| Distributions from UNEV in excess of earnings | | — |
| | 1,960 |
| | — |
| | (1,960 | ) | | — |
|
| Distributions in excess of equity in earnings in equity investments | | — |
| | 194 |
| | — |
| | — |
| | 194 |
|
| | | — |
| | (243,278 | ) | | (1,442 | ) | | (1,960 | ) | | (246,680 | ) |
| | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | |
| Net borrowings under credit agreement | | — |
| | 141,000 |
| | — |
| | — |
| | 141,000 |
|
| Net intercompany financing activities | | 192,108 |
| | (192,108 | ) | | — |
| | — |
| | — |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | (18,500 | ) | | 13,875 |
| | (4,625 | ) |
| Distributions to HEP unitholders | | (169,063 | ) | | — |
| | — |
| | — |
| | (169,063 | ) |
| Contributions from HFC for acquisitions | | — |
| | 128,476 |
| | — |
| | — |
| | 128,476 |
|
| Distributions to HFC for acquisitions | | — |
| | (62,000 | ) | | — |
| | — |
| | (62,000 | ) |
| Purchase of units for incentive grants | | (3,555 | ) | | — |
| | — |
| | — |
| | (3,555 | ) |
| Deferred financing costs | | — |
| | (962 | ) | | — |
| | — |
| | (962 | ) |
| Units withheld for tax withholding obligations | | (696 | ) | | — |
| | — |
| | — |
| | (696 | ) |
| Other | | — |
| | (1,154 | ) | | — |
| | — |
| | (1,154 | ) |
| | | 18,794 |
| | 13,252 |
| | (18,500 | ) | | 13,875 |
| | 27,421 |
|
| Cash and cash equivalents | | | | | | | | | | |
| Increase for the period | | — |
| | 2,624 |
| | 9,559 |
| | — |
| | 12,183 |
|
| Beginning of period | | 2 |
| | 2,828 |
| | — |
| | — |
| | 2,830 |
|
| End of period | | $ | 2 |
| | $ | 5,452 |
| | $ | 9,559 |
| | $ | — |
| | $ | 15,013 |
|
| |
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
We have had no change in, or disagreement with, our independent registered public accounting firm on matters involving accounting and financial disclosure.
| |
Item 9A. | Controls and Procedures |
Item 9A.Controls and Procedures
(a) Evaluation of disclosure controls and procedures
Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this annual report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2017,2021, at a reasonable level of assurance.
(b) Changes in internal control over financial reporting
We acquired additional equity interests in SLC Pipeline and Frontier Aspen from Plains effective October 31, 2017, and we accounted for their acquisition as a business combination achieved in stages. We have included SLC Pipeline and Frontier Aspen’s operating results, assets and liabilities in our consolidated financial statements as of December 31, 2017, and for the two months then ended. Pursuant to a Transition Service Agreement with Plains, Plains provides certain accounting support services for SLC Pipeline and Frontier Aspen. Other than internal controls for SLC Pipeline and Frontier Aspen, thereThere have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
See Item 8 for “Management’s Report on its Assessment of the Partnership’s Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm.”
| |
Item 9B. | Other Information |
Item 9B.Other Information
There have been no events that occurred in the fourth quarter of 20172021 that would need to be reported on Form 8-K that have not been previously reported.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Holly Logistic Services, L.L.C. (“HLS”), the general partner of HEP Logistics Holdings, L.P. (“HEP Logistics”), our general partner, manages our operations and activities. Neither our general partner nor our directors are elected by our unitholders. Unitholders are not entitled to directly or indirectly participate in our management or operations. The sole member of HLS, which is a subsidiary of HFC, appoints the directors of HLS to serve until their death, resignation or removal.
Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are non-recourse.
Executive Officers
The following sets forth information regarding the executive officers of HLS as of February 14, 2018:21, 2022:
|
| | | | | | | |
| Name | Age | Position with HLS |
George J. DamirisMichael C. Jennings | 5756 | Chief Executive Officer and President |
| Richard L. Voliva III | 4044 | Executive Vice President and Chief Financial Officer |
Mark T. CunninghamJohn Harrison | 5843 | Senior Vice President, OperationsChief Financial Officer and EngineeringTreasurer |
Denise C. McWattersVaishali S. Bhatia | 5839 | Senior Vice President, General Counsel and Secretary |
On October 27, 2021, Mark T. Cunningham, Senior Vice President, Operations and Engineering of HLS, notified the Board of Directors of HLS (the “Board”) that he was retiring from all officer positions and as an employee at HLS and its subsidiaries, effective February 18, 2022. In preparation for Mr. Cunningham’s retirement, his responsibilities were transferred to four different individuals at HLS, effective January 1, 2022, rather than replacing his role with a single individual. To assist with the transition of his responsibilities, Mr. Cunningham has agreed to serve as a consultant to HLS and its subsidiaries for a twelve-month period following his retirement. Information regarding Mr. Cunningham’s consulting arrangement with HLS and its subsidiaries can be found below under “Retirement Arrangements with Mark T. Cunningham.”
During 2017,2021, Mr. Cunningham was the only HLS executive officer who spent all of his professional time managing our business and affairs. The other executive officers listed above are also executive officers of HFC and devote as much of their professional time as is necessary to oversee the management of our business and affairs.
Information regarding Mr. DamirisJennings is included below under “Directors.”
Richard L. Voliva III was appointed has served as President of HLS since January 2020. He previously served as Executive Vice President and Chief Financial Officer of HLS infrom March 2017.2017 to January 2020, as Senior Vice President and Chief Financial Officer of HLS from July 2016 to March 2017, as Vice President and Chief Financial Officer of HLS from October 2015 to July 2016, as Vice President, Corporate Development of HLS from February 2015 to October 2015 and as Senior Director, Business Development of HLS from April 2014 to February 2015. He has also served as Executive Vice President and Chief Financial Officer of HFC since March 2017. Mr. Voliva served as Senior Vice President, and Chief Financial OfficerStrategy of HLS from July 2016 to March 2017, Vice President and Chief Financial Officer of HLS from October 2015 until July 2016, Vice President, Corporate Development of HLS from February 2015 until October 2015 and Senior Director, Business Development of HLS from April 2014 until February 2015. Mr. Voliva also served as Senior Vice President, Strategy for HFC from June 2016 to March 2017. Prior to joining HLS, Mr. Voliva was an analyst at Millennium Management LLC, an institutional asset manager, from April 2011 until April 2014, an analyst at Partner Fund Management, L.P., a hedge fund, from March 2008 untilto March 2011 and Vice President, Equity Research at Deutsche Bank from June 2005 to March 2008. Mr. Voliva is a CFA Charterholder.
Mark T. Cunningham was appointed Senior Vice President, Operations and Engineering in January 2018. He previouslyJohn Harrison has served as Senior Vice President, EngineeringChief Financial Officer and Technical ServicesTreasurer of HLS since January 2020. Mr. Harrison previously served as Vice President, Finance, Investor Relations and Treasurer of HLS from July 2016October 2018 to January 2018, Senior2020. He has served as Vice President, OperationsFinance, Strategy and Treasurer of HFC since September 2020. Mr. Harrison previously served as Vice President, Finance, Investor Relations and Treasurer of HFC from September 2018 to September 2020. He previously served as Vice President and Treasurer of HLS and HFC from January 2017 to October 2018, Business Development Representative of HLS and HFC from April 2013 to JulyDecember 2016, Assistant Treasurer of HLS and Vice President, OperationsHFC from JulyAugust 2012 to March 2013, Manager, Credit & Collections of HLS and HFC from March 2010 to August 2012, Supervisor, Credit & Collections of HLS and HFC from January 2007 to January 2013. He served Holly Corporation as Senior ManagerFebruary 2010 and Financial Analyst of Special ProjectsHLS and HFC from December 2006 through June 2007 and as Senior Manager of Integrity Management and Environmental, Health and Safety from July 2004 through December 2006.October 2005 to February 2007. Prior to joining Holly Corporation, Mr. CunninghamHarrison worked in the Planning & Financial Management group at JPMorgan Chase & Co.
Vaishali S. Bhatia has served Diamond Shamrock/Ultramar Diamond Shamrock for 20 years in several engineering and pipeline operations capacities.
Denise C. McWatters was appointedas Senior Vice President, General Counsel and Secretary in January 2013. Ms. McWatters also serves in a similar capacity for HFC. Ms. McWatters previouslyof HLS since November 2019. She served as Vice President,Chief Compliance Officer of HLS from August 2019 to January 2020, Acting General Counsel and Secretary of HLS
from April 2008 until January 2013. She joined Holly Corporation in October 2007 with more than 20 years of legal experience and served as DeputyAugust 2019 to November 2019, Assistant General Counsel of Holly Corporation until April 2008HLS from May 2017 to August 2019, Assistant Secretary of HLS from January 2013 to August 2019 and Counsel of HLS from October 2011 to May 2017. Ms. Bhatia has also served as Senior Vice President, General Counsel and Secretary of HFC (formerly Holly Corporation) from April 2008 until January 2013. Ms. McWatterssince November 2019. She served as theChief Compliance Officer of HFC from August 2019 to January 2020, Acting General Counsel and Secretary of HFC from August 2019 to November 2019, Assistant General Counsel of The Beck GroupHFC from 2005 through 2007.May 2017 to August 2019, Assistant Secretary of HFC from May 2012 to August 2019 and Counsel of HFC from October 2011 to May 2017. Prior to joining The Beck Group,HFC, Ms. McWatters practiced law in various capacitiesBhatia was an associate at the predecessor firm to Locke Lord Bissell & Liddell LLP, the Law Offices of Denise McWatters, the legal department at Citigroup, N.A., and the law firm of Cox Smith Matthews Incorporated.Jones Day.
Board Leadership Structure
The Board of Directors of HLS (the “Board”) is responsible for selecting the Board leadership structure that is in the best interest of HLS and HEP. At this time, the Board believes that separating the positions of Chairman and Chief Executive Officer is in the best interest of HLS and HEP. Currently, Mr. Michael C. Jennings serves as ChairmanChairperson of the Board in a non-employee capacity, and Mr. Damiris serves as the Chief Executive Officer of HLS. Independent directors and management have different perspectives and roles in strategy development. The independent directors on the Board bring experience, oversight and expertise from outside HLS, HEP and the industry, while the Chief Executive Officer brings HLS and HEP experience and expertise. The Board believes thatthe combined role of Chairperson of the Board and Chief Executive Officer working with the lead independent director (the “Presiding Director”), is in the best interest of unitholders at this time because the separation of these positions enhances thecombined role for HLS provides balance between strategy development and independent oversight of management, by the Board andboth of which are particularly useful in HLS’s and HEP’s overall leadership structure. In addition, as a result of his former role as HFC’s and HLS’s Chief Executive Officer, Mr. Jennings has company-specific experience and expertise and as Chairmangeneral partner.
None of the Board can identify strategic priorities, lead the discussion and executionour directors reported any litigation that is required to be reported in this Annual Report on Form 10-K. There are no family relationships among any of strategy, and facilitate the flow of information between management and the Board.our directors or executive officers.
ChairmanChairperson of the Board
Mr. Jennings was selected by the directors of HLS to serve as the ChairmanChairperson of the Board. The ChairmanChairperson has the following responsibilities:
•designating and calling meetings of the Board;
•presiding at all Board meetings;
•consulting with management on Board and committee meeting agendas;
•facilitating teamwork and communication between the Board and management; and
•acting as a liaison between management and the Board.
Since Mr. Jennings is notPresiding Director
Larry R. Baldwin, an employeeindependent director, was appointed by the non-management directors of HLS or HEP, he also presidesto serve as the Presiding Director of the Board. The Presiding Director has the following responsibilities:
•presiding at all executive sessions of the non-employeenon-management directors of the Board.Board;
•consulting with management on Board and committee meeting agendas;
•facilitating teamwork and communication between the non-management directors and management; and
•acting as a liaison in appropriate instances between management and the non-management directors, including advising the Chairperson of the Board and Chief Executive Officer on the efficiency of the Board meetings
Persons wishing to communicate with the non-employee directors are invited to email the ChairmanPresiding Director at presiding.director.HEP@hollyenergy.com or write to: Michael C. Jennings, Chairman,Larry R. Baldwin, Presiding Director, c/o Secretary, Holly Logistic Services, L.L.C., 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507. Communications to the Board generally may be sent by certified mail to Holly Logistic Services, L.L.C., 2828 N. Harwood, Suite 1300, Dallas, Texas 75201-1507, Attention: Secretary. The Secretary will forward all communication to the appropriate director or directors, other than those communications that are merely solicitations for products or services or relate to matters that are of a type that are clearly improper or irrelevant to the functioning of the Board or the business and affairs of HLS and HEP.
Risk Management
The Board has an active role in overseeing management of the risks affecting HLS and HEP. The Board regularly reviews information regarding HLS and HEP’s credit, liquidity, business, operations and business and operations,cybersecurity, as well as the risks associated with each. The Board committees are also engaged in overseeing risk associated with HLS and HEP.
•The Compensation Committee oversees the management of risks relating to HLS’s executive compensation plans and arrangements.
•The Audit Committee oversees management of financial reporting and controls risks.
•The Conflicts Committee oversees specific matters that the Boardit or the Conflicts CommitteeBoard believes may involve conflicts of interest with HFC.
While each committee is responsible for evaluating certain risks and overseeing the management of such risks, the entire Board is ultimately responsible for the risk management of HLS and HEP and is regularly informed on these matters through committee reports about such risks.and senior management presentations.
The sole member of HLS manages risks associated with the independence of the Board. The Audit Committee and the Board also receivereceives input and reports from HLS’s risk management oversight committee on management’s views of the risks facing HLS and HEP. The risk management oversight committee is made up of management personnel, none of whom serve on the Board and all of whom have a range of different backgrounds, skills and experiences with regard to the operational, financial and strategic risk
profile of HLS and HEP. The risk management oversight committee monitorssupports the efforts of the Board and the Board committees to monitor and evaluate guidelines and policies governing HLS’s and HEP’s risk environment for HLSassessment and HEP as a whole, and reviews the activities that mitigate risks to an achievable and acceptable level.management.
Director Qualifications
The Board believes that it is necessary for each of HLS’s directors to possess a variety of qualities and skills. When searching for new candidates, the sole member of HLS considers the evolving needs of the Board and searches for candidates that fill any current or anticipated future needs. The Board also believes that all directors must possess a considerable amount of business management, business leadership and educational experience. When considering director candidates, the sole member of HLS first considers a candidate’s management experience and then considers issues of judgment, background, stature, conflicts of interest, integrity, ethics, industry knowledge, ability to commit adequate time to the Board, and commitment to the goal of maximizing unitholder value. The sole member of HLS also focuses on issues of diversity, such as diversity of education, professional experiencerace, gender, age, culture, thought and differences in viewpoints and skills. The sole member of HLS does not have a formal policy with respect to diversity; however, the Board and the sole member of HLS believe that it is essential that the Board members represent diverse viewpoints.geography. In considering candidates for the Board, the sole member of HLS considers the entirety of each candidate’s credentials in the context of these standards. All our directors bring to the Board executive leadership experience derived from their service in many areas.
Pursuant to the Governance Guidelines of HLS and HEP, a director must submit his or her resignation to the Board in the first quarter of the calendar year in which the director will attain the age of 75 or greater. If the resignation is accepted by the Board, the resignation will be effective on December 31 of the year in which the resignation was accepted by the Board. In the first quarter of 2016, Mr. Jerry W. Pinkerton submitted his resignation in accordance with the policy. His resignation was not accepted by the Board at that time. In the fourth quarter of 2016, the Board reconsidered his resignation, but decided to not accept his resignation at that time. In the first quarter of 2017, the Board again reconsidered his resignation and accepted his resignation effective June 30, 2017.
On February 7, 2018, the sole member of HLS appointed Christine B. LaFollette and Eric L. Mattson to the Board effective March 1, 2018. In addition, on February 7, 2018, Mr. R. Kevin Hardage notified the Board that he will resign from the Board effective February 28, 2018.
Director Independence
The Board has determined that Messrs. Larry R. Baldwin, R. Kevin Hardage andChristine B. LaFollete, James H. Lee and Eric L. Mattson meet the applicable criteria for independence under the currently applicable rules of the New York Stock Exchange (“NYSE”). The Board previously determined that Matthew P. Clifton, Charles M. Darling IV, Jerry W. Pinkerton, William P. StengelMr. Jennings is not independent because he is an officer of HLS and James G. Townsend were “independent” as defined by the NYSE listing standards during the time they served on the Board. Messrs. Clifton, Darling, Stengel and Townsend retired from the Board effective November 2017, and, as previously discussed, the Board accepted Mr. Pinkerton’s resignation pursuant to the Board retirement policy effective June 2017. The Board has also determined that Ms. LaFollette and Mr. Mattson meet the applicable criteria for independence under the current applicable rulesan employee of NYSE.HFC.
Audit Committee. The Audit Committee of HLS is currently composed of three directors, Messrs. Baldwin, HardageLee and Lee.Mattson. The Board has determined that each member of the Audit Committee is “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Securities Exchange Act of 1934 (the “Exchange Act”). The Board previously determined that Messrs. Clifton, Pinkerton and Darling were “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Exchange Act during the time they served on the Audit Committee. Mr. Hardage notified the Board that he will resign from the Board on February 28, 2018. The Board has appointed Mr. Mattson to the Audit Committee effective March 1, 2018. The Board has determined that Mr. Mattson is “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Exchange Act.
Conflicts Committee. The Conflicts Committee of HLS is currently composed of Mr. Baldwin.three directors, Messrs. Baldwin and Mattson and Ms. LaFollette. The Board has determined that heeach member of the Conflicts Committee is “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Exchange Act, as required by the Conflicts Committee Charter. The Board previously determined that Messrs. Clifton, Stengel, Pinkerton and Townsend were “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Exchange Act during the time they served on the Conflicts Committee. The Board has appointed Ms. LaFollette and Mr. Mattson to the Conflicts Committee effective March 1, 2018. The Board has determined that Ms. LaFollette and Mr. Mattson are “independent” as defined by the NYSE listing standards and Rule 10A-3 of the Exchange Act.
Compensation Committee. The Compensation Committee of HLS is currently composed of three directors, Messrs. Jennings Damiris and Lee.Lee and Ms. LaFollette. The Board has determined that Mr. Lee isand Ms. LaFollette are “independent” as defined by the NYSE listing standards. Because we are a master limited partnership, Rule 303A.05 of the NYSE Listed Company
Manual, which requires a publicly traded company to have a compensation committee composed entirely of independent directors, does not apply to us. The Board
previously determined that Messrs. Darling, Stengel and Townsend were “independent” as defined by the NYSE listing standards during the time they served on the Compensation Committee. The Board has appointed Ms. LaFollette to the Compensation Committee effective March 1, 2018. The Board has determined that Mr. LaFollette is “independent” as defined by the NYSE listing standards.
Independence Determinations. In making its independence determinations, the Board considered certain transactions, relationships and arrangements. In determining Mr. Townsend’s independence during the time he served on the Board, the Board considered that Mr. Townsend has not been employed by HFC or HLS since 2011 and has not received compensation in excess of $120,000 since 2011. In determining Mr. Clifton’s independence during the time he served on the Board, the Board considered that Mr. Clifton has not been employed by HFC or HLS since 2014 and has not received compensation in excess of $120,000 since 2013. In determining Ms. LaFollette’s independence, the Board considered that during fiscal year 2017, Akin Gump Strauss Hauer & Feld LLP served as outside counsel to the Conflicts Committee. Ms. LaFollette did not represent the Conflicts Committee of the Board on any matters, and Akin Gump Strauss Hauer & Feld LLP will no longer represent the Conflicts Committee of the Board in light of Ms. LaFollette’s appointment to the Board.
Code of Business Conduct and Ethics
HLS has adopted a Code of Business Conduct and Ethics (the “Code”) that applies to all of its officers, directors and employees, including HLS’s principal executive officer, principal financial officer, and principal accounting officer. The purpose of the Code of Business Conduct and Ethics is to, among other things, affirm HLS’s and HEP’s commitment to a high standard of integrity and ethics. The Code sets forth a common set of values and standards to which all of HLS’s officers, directors and employees must adhere. We will post information regarding an amendment to, or a waiver from, the Code of Business Conduct and Ethics on our website.
Copies of our Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, and the Code of Business Conduct and Ethics are available on our website at www.hollyenergy.com. Copies of these documents may also be obtained free of charge upon written request to Holly Energy Partners, L.P., Attention: Director,Vice President, Investor Relations, 2828 N. Harwood, Suite 1300, Dallas, Texas, 75201-1507.
The Board, Its Committees and Director Compensation
Directors
The following individuals currently serve as directorsCurrently, the Board consists of HLS:five directors.
Michael C. Jennings Director since October 2011. Age 52.56.
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Principal Occupation:Principal Occupation: Chief Executive Officer of HLS and Chief Executive Officer of HFC
Business Experience: Mr. Jennings has served as Chief Executive Officer of HLS since January 2020 and as the Chairperson of the Board of HLS since November 2017.Mr. Jennings previously served as Chief Executive Officer of HLS from January 2014 to November 2016 and as President of HLS from October 2015 to February 2016.Mr. Jennings has served as Chief Executive Officer of HFC since January 2020.Mr. Jennings also served as President of HFC from January 2020 to November 2021, as Executive Vice President of HFC from November 2019 to January 2020, as Executive Chairman of HFC from January 2016 to January 2017 and as the Chief Executive Officer and President of HFC from the merger of Holly Corporation and Frontier Oil Corporation in July 2011 to January 2016.Mr. Jennings previously served as the President and Chief Executive Officer of Frontier Oil Corporation from 2009 until the merger in July 2011 and as the Executive Vice President and Chief Financial Officer of Frontier Oil Corporation from 2005 to 2009.
Additional Directorships: Mr. Jennings currently serves as a director of HFC. Mr. Jennings served as Chairperson of the Board of HFC from January 2017 to February 2019 and January 2013 to January 2016. Mr. Jennings served as a director of FTS International, Inc. from January 2019 to November 2020, as a director and Chairman of the Board of Montage Resources and its predecessor entities from May 2016 to November 2019, and as a director of ION Geophysical Corporation from December 2010 until February 2019. He served as a director of Frontier Oil Corporation from 2008 until the merger in July 2011 and as Chairman of the board of directors of Frontier Oil Corporation from 2010 until the merger in July 2011.
Qualifications: Mr. Jennings provides valuable and extensive industry knowledge and experience. His knowledge of the day-to-day operations of HFC is a significant resource for the Board and facilitates discussions between the Board and HFC management. | Chairman of the Board of HLS and Chairman of the Board of HFC |
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Business Experience:
| Mr. Jennings has served as Chairman of the Board of HLS since November 2017 and Chairman of the Board of HFC since January 2017, a position he previously held from January 2013 until January 2016. Mr. Jennings served as Chief Executive Officer of HLS from January 2014 to November 2016 and as President of HLS from October 2015 to February 2016. Mr. Jennings served as Executive Chairman of HFC from January 2016 until January 2017 and as the Chief Executive Officer and President of HFC from the merger of Holly Corporation and Frontier Oil Corporation in July 2011 until January 2016. Mr. Jennings previously served as the President and Chief Executive Officer of Frontier Oil Corporation from 2009 until the merger in July 2011 and as the Executive Vice President and Chief Financial Officer of Frontier Oil Corporation from 2005 until 2009. |
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Additional Directorships: | Mr. Jennings currently serves as the Chairman and a director of HFC and a director of ION Geophysical Corporation. Mr. Jennings served as a director of Frontier Oil Corporation from 2008 until the merger in July 2011 and as Chairman of the board of directors of Frontier Oil Corporation from 2010 until the merger in July 2011. |
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Qualifications:
| Mr. Jennings provides valuable and extensive industry knowledge and experience. His knowledge of the day-to-day operations of HFC provides a significant resource for the Board and facilitates discussions between the Board and HFC management. |
George J. Damiris Director since February 2016. Age 57.
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Principal Occupation:
| Chief Executive Officer and President of HFC and Chief Executive Officer and President of HLS |
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Business Experience:
| Mr. Damiris has served as the Chief Executive Officer of HLS since November 2016, as President of HLS since February 2017 and as Chief Executive Officer and President of HFC since January 2016. He previously served as Executive Vice President and Chief Operating Officer of HFC from September 2014 until January 2016 and as Senior Vice President, Supply and Marketing of HFC from January 2008 until September 2014. Mr. Damiris joined HFC in 2007 as Vice President, Corporate Development after an 18-year career with Koch Industries, where he was responsible for managing various refining, chemical, trading, and financial businesses. |
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Additional Directorships: | Mr. Damiris currently serves as a director of Eagle Materials Inc. and of HFC. |
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Qualifications:
| Mr. Damiris has extensive industry experience and significant insight into issues facing the industry. His knowledge of the day-to-day operations of HFC provides a significant resource for the Board and facilitates discussions between the Board and HFC management. |
Larry R. Baldwin Director since May 2016. Age 65.69.
Principal Occupation: Former Partner at Deloitte LLP.
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Business Experience:
Business Experience: Mr. Baldwin was employed for 41 years as an auditor by Deloitte LLP and predecessor firms, including 31 years as a partner, prior to retiring from such position in May 2015. While he was a partner at Deloitte LLP, Mr. Baldwin held a number of practice management positions.
Qualifications: Mr. Baldwin brings to the Board his audit, accounting and financial reporting expertise, which also qualify him as an audit committee financial expert. Due to his audit and practice management experience with Deloitte LLP, Mr. Baldwin possesses business, industry and management expertise that provide valuable insight to the Board and the management of HEP. | Mr. Baldwin was employed for 41 years as an auditor by Deloitte LLP and predecessor firms, including 31 years as a partner, prior to retiring from such position in May 2015. While he was a partner at Deloitte LLP, Mr. Baldwin held a number of practice management positions. |
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Qualifications:
| Mr. Baldwin brings to the Board his audit, accounting and financial reporting expertise, which also qualify him as an audit committee financial expert. Due to his audit and practice management experience with Deloitte LLP, Mr. Baldwin possesses business, industry and management expertise that provide valuable insight to the Board and the management of the Company. |
R. Kevin HardageChristine B. LaFollette Director since March 2018. Age 69.
Principal Occupation: Partner Emeritus at Akin Gump Strauss Hauer & Feld LLP
Business Experience: Ms. LaFollette served as Partner at Akin Gump Strauss Hauer & Feld LLP from June 2004 until her retirement in December 2020. Beginning in January 2021, Ms. LaFollette was named Partner Emeritus at Akin Gump Strauss Hauer & Feld LLP. Prior to that, Ms. LaFollette served as a Partner at King & Spalding LLP from 1997 to June 2004, as a Partner at Andrews & Kurth LLP from 1987 to 1997 and as an associate at Andrews & Kurth LLP from 1980 to 1987.
Qualifications: Ms. LaFollette’s experience as a transactional and securities attorney provides her with valuable insight into corporate finance, global compliance, and governance matters. In addition, Ms. LaFollette brings to the Board a broad range of experiences and skills as a result of her involvement in numerous charitable, community and civic activities.
_____________________________________________________________________________________________
James H. Lee Director since November 2017. Age 56.73.
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Principal Occupation:
| Chief Executive Officer of Turtle Creek Trust Company, Co-founder, President and Portfolio Manager of Turtle Creek Management, LLC and a non-controlling manager and member of TCTC Holdings, LLC |
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Business Experience:
| Mr. Hardage has served as Chief Executive Officer of Turtle Creek Trust Company, a private trust and investment management firm, since 2009 and has served as President and Portfolio Manager of Turtle Creek Management, a registered investment advisory firm, since 2006. In addition, Mr. Hardage serves as a non-controlling manager and member of TCTC Holdings, LLC, a bank holding company that is a banking, securities and investment management firm. |
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Additional Directorships: | Mr. Hardage currently serves as a director of HFC. |
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Qualifications:
| Mr. Hardage brings to the Board executive and general management experience as well as significant financial expertise. |
_____________________________________________________________________________________________
Principal Occupation: Managing General Partner and Principal Owner of Lee, Hite & Wisda Ltd.
James H.
Business Experience: Mr. Lee Director has served as the Managing General Partner of Lee, Hite & Wisda Ltd., a private company with investments in oil and gas working, royalty and mineral interests, since November 2017. Age 69.founding the firm in 1984.
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Principal Occupation:
| Managing General Partner and Principal Owner of Lee, Hite & Wisda Ltd. |
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Business Experience:
| Mr. Lee has served as the Managing General Partner of Lee, Hite & Wisda Ltd., a private company with investments in oil and gas working, royalty and mineral interests, since founding the firm in 1984. |
Additional Directorships: Mr. Lee currently serves as a director of HFC. He served as a director of Frontier Oil Corporation from 2000 until July 2011.
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Additional Directorships: | Mr. Lee currently serves as a director of HFC. He served as a director of Frontier Oil Corporation from 2000 until July 2011 and as a director of Forest Oil Corporation from 1991 until December 2014. |
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Qualifications:
| Qualifications: Mr. Lee brings to the Board his extensive experience as a consultant and investor in the oil and gas industry, which provides him with significant insights into relevant industry issues. |
The following directors are appointed to the Board effectivehis extensive experience as a consultant and investor in the oil and gas industry, which provides him with significant insights into relevant industry issues.
Eric L. Mattson Director since March 1, 2018:
Christine B. LaFollette Director effective March 1, 2018. Age 65.70.
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Principal Occupation:Principal Occupation: Former Executive Vice President, Finance of Select Energy Services, Inc.
Business Experience: Mr. Mattson served as Executive Vice President, Finance of Select Energy Services, Inc., a provider of total water solutions to the U.S. unconventional oil and gas industry, from November 2016 until his retirement in March 2018 and served as Executive Vice President and Chief Financial Officer of Select Energy Services, Inc. from November 2008 through January 2016. Prior to that, Mr. Mattson served as Senior Vice President and Chief Financial Officer of VeriCenter, Inc., a private provider of managed hosting services, from 2003 until its acquisition in August, 2007. Mr. Mattson worked as an independent consultant from November 2002 to October 2003. Mr. Mattson served as the Chief Financial Officer of Netrail, Inc., a private Internet backbone and broadband service provider, from September 1999 until November 2002. From July 1993 until May 1999, Mr. Mattson served as Senior Vice President and Chief Financial Officer of Baker Hughes Incorporated, a provider of products and services to the oil, gas and process industries. Mr. Mattson joined Baker International, Inc. in 1980, and served in a number of capacities, including Treasurer, prior to the merger of Baker International, Inc. and Hughes Tool
Company in 1987, at which time he became Vice President and Treasurer of Baker Hughes, Inc., a position he held until 1993.
Additional Directorships: Mr. Mattson has served as a director of National Oilwell Varco, Inc. since March 2005 (having served as a director of Varco (and its predecessor, Tuboscope Inc.) from January 1994 until its merger with National Oilwell Varco in March 2005). He served as a director of Rex Energy Corporation from April 2010 until November 2018.
Qualifications: Mr. Mattson brings strong executive leadership skills and financial and risk management experience to the Board. His knowledge of the oil industry as well as the financial and capital markets enables him to provide critical insight to the Board. | Partner at Akin Gump Strauss Hauer & Feld LLP |
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Business Experience:
| Ms. LaFollette has served as a partner at Akin Gump Strauss Hauer & Feld LLP since June 2004. Prior to that, Ms. LaFollette served as a partner at King & Spalding LLP from 1997 to June 2004, as a partner at Andrews & Kurth LLP from 1987 to 1997 and as an associate at Andrews & Kurth LLP from 1980 to 1987. |
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Qualifications:
| Ms. LaFollette’s experience as a transactional and securities attorney provides her with valuable insight into corporate finance, global compliance, and governance matters. In addition, Ms. LaFollette brings to the Board a broad range of experiences and skills as a result of her involvement in numerous charitable, community and civic activities. |
Eric L. Mattson Director effective March 1, 2018. Age 66.
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Principal Occupation:
| Executive Vice President, Finance of Select Energy Services, Inc. |
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Business Experience:
| Mr. Mattson has served as Executive Vice President, Finance of Select Energy Services, Inc., a provider of total water solutions to the U.S. unconventional oil and gas industry, since November 2016 and served as Executive Vice President and Chief Financial Officer of Select Energy Services, Inc. from November 2008 through January 2016. Prior to that, Mr. Mattson served as Senior Vice President and Chief Financial Officer of VeriCenter, Inc., a private provider of managed hosting services, from 2003 until its acquisition in August, 2007. Mr. Mattson worked as an independent consultant from November 2002 to October 2003. Mr. Mattson served as the Chief Financial Officer of Netrail, Inc., a private Internet backbone and broadband service provider, from September 1999 until November 2002. From July 1993 until May 1999, Mr. Mattson served as Senior Vice President and Chief Financial Officer of Baker Hughes Incorporated, a provider of products and services to the oil, gas and process industries. Mr. Mattson joined Baker International, Inc. in 1980, and served in a number of capacities, including Treasurer, prior to the merger of Baker International, Inc. and Hughes Tool Company in 1987, at which time he became Vice President and Treasurer of Baker Hughes, Inc., a position he held until 1993. |
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Additional Directorships: | Mr. Mattson has served as a director of National Oilwell Varco, Inc. since March 2005 (having served as a director of Varco (and its predecessor, Tuboscope Inc.) from January 1994 until its merger with National Oilwell Varco in March 2005) and as a director of Rex Energy Corporation since April 2010. |
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Qualifications:
| Mr. Mattson brings strong executive leadership skills and financial and risk management experience to the Board. His knowledge of the oil industry as well as the financial and capital markets enables him to provide critical insight to the Board. |
None of our directors reported any litigation for the period from 20082012 to 20182022 that is required to be reported in this Annual Report on Form 10-K. There are no family relationships among any of our directors or executive officers.
The Board
Under the Company’s Governance Guidelines, Board members are expected to prepare for, attend and participate in all meetings of the Board and Board committees on which they serve. During 2017,2021, the Board held 17eleven meetings. Each director attended at least 75% of the total number of meetings of the Board and committees on which he or she served.
Board Committees
The Board currently has three standing committees:
•an Audit Committee;
•a Compensation Committee; and
•a Conflicts Committee.
Each of these committees operates under a written charter adopted by the Board.
During 2017,2021, the Audit Committee held nineeight meetings, the Conflicts Committee held 16twenty-six meetings, and the Compensation Committee held four meetings.
The Board appoints committee members annually.The following table sets forth the current composition of our committees:
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| | | | | | | | | | |
Name (1) | Audit
Committee
| Compensation
Committee
| Conflicts
Committee
|
| Larry R. Baldwin | x (Chair) | | x |
George J. Damiris | | x | |
R. Kevin Hardage | x | | |
| Michael C. Jennings | | x (Chair) | |
James H. Lee | x | x | |
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(1)Christine B. LaFollette | Effective February 28, 2018, Mr. Hardage will resign from the Board. Effective March 1, 2018, Ms. LaFollette will serve on the Compensation Committee and the Conflicts Committee, and Mr. | x | x |
| James H. Lee | x | x | |
Eric L. Mattson will serve on the Conflicts Committee, as Chairman, and the Audit Committee. | x | | x (Chair) |
Audit Committee
The functions of the Audit Committee pursuant to its charter include the following:
•selecting, compensating, retaining and overseeing our independent registered public accounting firm and conducting an annual review of the independence and performance of that firm;
•confirming with the independent registered public accounting firm its compliance with the partner rotation requirements established by the SEC;
•reviewing and evaluating the lead partner of the independent registered public accounting firm;
•reviewing the scope and the planning of the annual audit performed by the independent registered public accounting firm;
•overseeing matters related to the internal audit function;
•reviewing and discussing with the internal auditor any significant reports to management prepared by the internal auditor and any responses from management;
•reviewing the audit report issued by the independent registered public accounting firm;
•reviewing HEP’s annual and quarterly financial statements with management and the independent registered public accounting firm;
•discussing with management HEP’s significant financial risk exposures and the actions management has taken to monitor and control such exposures;
•reviewing and, if appropriate, approving transactions involving conflicts of interest, including related party transactions, when required by HEP’sconsistent with the Code of Business Conduct and Ethics;Related Party Transaction Policy;
•reviewing the Related Party Transaction Policy on an annual basis;
•reviewing and discussing HEP’s internal controls over financial reporting with management and the independent registered public accounting firm;
•establishing procedures for the receipt, retention and treatment of complaints received by HEP regarding accounting, internal accounting controls or accounting matters, potential violations of applicable laws, rules and regulations or of our codes, policies and procedures;
•reviewing the type and extent of any non-audit work to be performed by the independent registered public accounting firm and its compatibility with their continued objectivity and independence, and to the extent consistent, pre-approving all non-audit services to be performed;
•reviewing and approving the Audit Committee Report to be included in the Annual Report ofon Form 10-K; and
•reviewing the adequacy of the Audit Committee charter on an annual basis.
Each current member of the Audit Committee and Mr. Mattson havehas the ability to read and understand fundamental financial statements. The Board has determined that Mr. Baldwin meets the requirements of an “audit committee financial expert”as defined by the rules of the SEC.
Conflicts Committee
The functions of the Conflicts Committee include reviewing specific matters that the Board or the Conflicts Committee believes may involve conflicts of interest with HFC. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to HEP. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, the Conflicts Committee reviews the adequacy of the Conflicts Committee charter on an annual basis.
Compensation Committee
The functions of the Compensation Committee pursuant to its charter include:
•reviewing and approving the goals and objectives of HLS and HEP relevant to the compensation of the officers of HLS for whom the Compensation Committee determines compensation;
•determining compensation for the officers of HLS for whom the Compensation Committee determines compensation;
•reviewing director compensation and making recommendations to the Board regarding the same;
•overseeing the preparation of the Compensation Discussion and Analysis to be included in the Annual Report and preparing the Compensation Committee Report to be included in the Annual Report;
•reviewing the Company’s executive compensation plans with respect to behavioral, operational and other risks;
•administering and making recommendations to the Board with respect to HEP’s equity plan and HLS’s annual incentive plan; and
•reviewing the adequacy of the Compensation Committee charter on an annual basisbasis.
During 2017,Since the Compensation Committee had a subcommitteeis not comprised of Mr. Lee, who is “independent” as defined by the NYSE listing standards, for purposes of approvingall independent directors, equity awards, including performance goals applicable to such awards, if applicable, and any other matters that are within the responsibilities of the Compensation Committee requiring approval solely by independent members of the Board. During 2017, the subcommittee of the Compensation Committee held two meetings. Messrs. Darling, Stengel and Townsend served on the subcommittee prior to their retirement from the Board. Effective February 2018, equity awards, including performance goals applicable to such awards, if applicable, will be approved by the full Board. As a result, the subcommittee is no longer needed.
During 2017,
In January 2018, the Compensation Committee had engaged Frederic W. Cook & Co. (the “Compensation Consultant” or “FWC”Meridian Compensation Partners, LLC (“Meridian”), an executive compensation consulting firm, to advise it regardingas the compensation consultant, to provide advice relating to executive, non-management director compensation, including benchmarking of HLS’s officersthe compensation peer group for non-management director compensation, and directors. In selecting FWCemployee long-term equity incentive awards.At the time the Compensation Committee selected Meridian as its independent compensation consultant, and during the first quarter of every year since engaging Meridian, the Compensation Committee has assessed the independence of FWCMeridian pursuant to SEC rules and considered, among other things, whether FWCMeridian provides any other services to HLS or us, the fees paid by us to FWCMeridian as a percentage of FWC’sMeridian’s total revenues, the policies of FWCMeridian that are designed to prevent any conflict of interest between
FWC, Meridian, the Compensation Committee, HLS and us, any personal or business relationship between FWCMeridian and a member of the Compensation Committee or one of HLS’s executive officers and whether FWCMeridian owned any of our common units. In addition to the foregoing, the Compensation Committee receivedannually receives an independence letter from FWC,Meridian, as well as other documentation addressing the firm’s independence. FWCMeridian reports exclusively to the Compensation Committee and does not provide any additional services to HLS or us.The Compensation Committee has discussed these considerations and has concluded that FWCMeridian is independent and that neither we nor HLS have any conflicts of interest with FWC.Meridian.
In January 2018, the Compensation Committee engaged Meridian Compensation Partners, LLC (“Meridian”) to provide advice relating to non-management director compensation matters beginning with the 2018 fiscal year. Meridian did not provide any information or advice to the Compensation Committee with respect to matters related to executive and non-management director compensation in 2017.
Compensation Committee Interlocks and Insider Participation
The members of the Compensation Committee of the Board at year-end 2017 were Messrs. Jennings, Damiris and Lee. Messrs. Darling, Stengel and Townsend also served as Compensation Committee members until their retirement in November 2017. During his service as a member of the Compensation Committee, Mr. Damiris also served as the Chief Executive Officer and President of HLS. None of the members who served on the Compensation Committee at any time during 2017 had any relationship requiring disclosure under Item 13 of this annual report on Form 10-K entitled “Certain Relationships and Related Transactions, and Director Independence.” No executive officer of HLS served as a member of the compensation committee of another entity that had an executive officer serving as a member of our Board or our Compensation Committee. No executive officer of HLS served as a member of the board of another entity that had an executive officer serving as a member of our Compensation Committee, except that Mr. Damiris, the Chief Executive Officer and President of HLS, also served as the Chief Executive Officer and President of HFC.
Report of the Audit Committee for the Year Ended December 31, 20172021
Management of Holly Logistic Services, L.L.C. is responsible for Holly Energy Partners, L.P.’s system of internal controls over financial reporting. The Audit Committee selected, and the Board approved the selection of, Ernst & Young LLP as Holly Energy Partners, L.P.’s independent registered public accounting firm to audit the books, records and accounts of Holly Energy Partners, L.P. for the year ended December 31, 2017.2021.Ernst & Young LLP is responsible for performing an independent audit of Holly Energy Partners, L.P.’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (“PCAOB”) and to issue a report thereon. The Audit Committee also is responsible for selecting, engaging and overseeing the work of the independent registered public accounting firm, which reports directly to the Audit Committee, and evaluating its qualifications and performance. Among other things, to fulfill its responsibilities, the Audit Committee:
•reviewed and discussed Holly Energy Partners, L.P.’s quarterly unaudited consolidated financial statements and its audited annual consolidated financial statements for the year ended December 31, 20172021 with management and Ernst & Young LLP, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements, including those in management’s discussion and analysis thereof;
•discussed with Ernst & Young LLP the matters required to be discussed by Auditing Standard No. 16, Communications with Audit Committees, as adopted by the Public Company Accounting Oversight Board;applicable requirements of the PCAOB, the SEC and the NYSE;
•discussed with Ernst & Young LLP matters relating to its independence and received the written disclosures and letter from Ernst & Young LLP required by applicable requirements of the PCAOB regarding the independent accountant’s communications with the Audit Committee concerning the firm’s independence;
•discussed with Holly Energy Partners, L.P.’s internal auditors and Ernst & Young LLP the overall scope and plans for their respective audits and met with the internal auditors and Ernst & Young LLP, with and without management
present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of Holly Energy Partners, L.P.’s financial reporting; and
•considered whether Ernst & Young LLP’s provision of non-audit services to Holly Energy Partners, L.P. is compatible with the auditor’s independenceindependence.
The Audit Committee charter requires the Audit Committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All fees for audit, audit-related and tax services as well as all other fees
presented under Item 14 “Principal Accountant Fees and Services” were approved by the Audit Committee in accordance with its charter.
Based on the foregoing review and discussions and such other matters the Audit Committee deemed relevant and appropriate, the Audit Committee recommended to the Board that the audited consolidated financial statements of Holly Energy Partners, L.P. for the year ended December 31, 20172021 be included in Holly Energy Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 20172021 for filing with the SEC.
Members of the Audit Committee:
Larry R. Baldwin, Chairman
R. Kevin HardageChairperson
James H. Lee
Eric L. Mattson
Director Compensation
The Compensation Committee annually evaluates the compensation program for members of the Board who are not officers or employees of HLS or HFC (“non-employee directors”). Directors who also serve as officers or employees of HLS or HFC do not receive additional compensation for serving on the Board. We reimburse directors for all reasonable expenses incurred in attending Board and Board committee meetings and director continuing education sessions upon submission of appropriate documentation. No meeting fees are paid for Board or Board committee meetings.
For 2017,2021, non-employee directors were entitled to receive aan annual cash retainer, and meeting fees payable in cash, in addition to an annual equity awardsretainer in the form of an award of phantom units described in the following table.table below.
Larry R. Baldwin has served as Presiding Director of HLS since February 2020 when Mr. Jennings, Chairperson of the Board of HLS, became an executive officer of HFC and HLS. As an executive officer of HFC and HLS, Mr. Jennings does not receive any compensation for his service on the Board.
In November 2017,October 2021, the Board approved non-employee director compensation for 2018. For 2018, the Board eliminated meeting fees until the thirteenth meeting of the Board or the Committee. As2022. The only change from 2021 was a result, several changes were made to the equity and cash payments received by the non-employee directors, which are reflected$10,000 increase in the table below.annual equity retainer from $105,000 to $115,000.The awards that were granted in October 2021 (for 2022 services) were in the form of phantom units.
|
| | |
| | Compensation in 2017 (1) | Compensation in 2018 (1) |
| Annual cash retainer | $60,000 | $100,000 |
| Meeting fee (also paid to non-members of committees who are invited to attend by such committee’s chairman) (2) | $1,500 | $1,500 |
| Annual equity retainer of restricted units (3) | $80,000 | $90,000 |
| Annual cash retainer for the Chairman of the Board | $100,000 | $75,000 |
| Annual cash retainer for Chairmen of committees and subcommittees | $15,000 | $25,000 (4) |
| | | | | | | | | | | |
| Compensation in 2021 | | Compensation in 2022 |
| Annual cash retainer | $ | 100,000 | | | $ | 100,000 | |
| Annual cash retainer for the Presiding Director | $ | 25,000 | | | $ | 25,000 | |
Annual equity retainer (1) | $ | 105,000 | | | $ | 115,000 | |
Annual cash retainer for the Chairperson of the Board (2) | $ | 75,000 | | | $ | 75,000 | |
Annual cash retainer for Chairperson of committees (2) | $ | 25,000 | | | $ | 25,000 | |
__________________
|
| | | | |
| (1) | Because Mr. Hardage was appointed to fill a temporary vacancy on the HLS Board, Mr. Hardage did not participate in the non-employee director compensation program. Instead, he received cash compensation of $18,000 per month for his service on the Board. |
(2) | Represents fees paid for meetings attended in person or telephonically. Beginning in 2018, no meeting fees will be paid for the first 12 Board or Committee meetings. Meeting fees will be paid beginning with the thirteenth meeting of the Board or Committee. |
(3) | The annual award is comprised of a number of restrictedphantom units equal to the annual equity retainer divided by the closing price of a common unit on the date of grant, with the number of restrictedphantom units rounded up in the case of fractional shares. |
(4)(2) | Beginning in 2018, no cash retainer will be paid toAs an executive officer of HFC and HLS, Mr. Jennings does not receive any compensation for serving as Chairperson of the ChairmanBoard or Chairperson of the Compensation Committee since he also serves as Chairman of the Board.HLS. |
Annual Equity Awards
Non-employee directors receive an annual equity award grant under the Holly Energy Partners, L.P. Amended and Restated Long-Term Incentive Plan (“Long-Term(the “Long-Term Incentive Plan”) in the form of restrictedphantom units, with the number of restricted unitsawards calculated as described above. Continued service on the Board through the vesting date, which is approximately one year following the date of grant, is required for the restricted unitsawards to vest. Vesting of all unvested units will accelerate upon a change in control of HFC, HLS, HEP or HEP Logistics. In addition, vesting of unvested units will accelerate on a pro-rata basis upon the director’s death, total and permanent disability or retirement. Directors are entitled to receive all distributionsdistribution equivalents paid with respect to outstanding
restricted awards, and these distribution equivalents are paid at approximately the same time as distributions are paid on our common units. The distributionsdistribution equivalents are not subject to forfeiture. The directors also have a right to vote with respect to the restricted units.
Non-Qualified Deferred Compensation
Non-employee directors are eligible to participate in the HollyFrontier Corporation Executive Nonqualified Deferred Compensation Plan, which is not tax-qualified under Section 401 of the Internal Revenue Code and allows participants to defer receipt of certain compensation (the “NQDC Plan”). The NQDC Plan allows non-employee directors the ability to defer up to 100% of their cash retainers and meeting fees for a calendar year. Participating directors have full discretion over how their contributions to the NQDC Plan are invested among the investment options. Earnings on amounts contributed to the NQDC Plan are calculated in the same manner and at the same rate as earnings on actual investments. Neither HLS nor HFC subsidizes a participant’s earnings under the NQDC Plan.
None of our non-employee directors participated in the NQDC Plan in 2017.2021. For additional information on the NQDC Plan, see “Compensation Discussion and Analysis-OverviewAnalysis–Overview of 20172021 Executive Compensation Components and Decisions-RetirementDecisions–Retirement and Benefit Plans-DeferredPlans–Deferred Compensation Plan” and thenarrative preceding the “Nonqualified Deferred Compensation Table.”
Unit Ownership and Retention Policy for Directors
Effective October 2013, ourOur directors, becameother than those who serve as officers of HLS, are subject to a newthe HEP unit ownership and retention policy. Pursuant to the policy, each director is required to hold during service on the Board common units equal in value to at least twothree times the annual equity retainer paid to non-employee directors. As of January 1, 2017, each non-employee director was required to hold common units equal in value to $160,000. Beginning in November 2017, each non-employee director was required to hold common units equal in value to $180,000. Each subject director is required to meet the applicable requirements within five years of first being subject to the policy.
Directors are also required to continuously own sufficient units to meet the unit ownership and retention requirements once attained. Until directors meet the requirements, they will be required to hold 25% of the units received from any equity award. If a director attains compliance with the policy and subsequently falls below the requirement because of a decrease in the price of our common units, the director will be deemed in compliance provided that the director retains the units then held.
As of December 31, 2017,2021, all of our then-current directors were in compliance with the unit ownership and retention policy or were within the five-year grace period provided in the policy.
Anti-Hedging and Anti-Pledging Policy
MembersAll of the Boardour directors are subject to the HEPour Insider Trading Policy, which, among other things, prohibits such directors from entering into short sales or hedging or pledging our common units and HFC common stock. The anti-hedging policy contained in our Insider Trading Policy specifically prohibits directors and their designees from purchasing financial instruments or otherwise engaging in transactions that hedge or offset or are designed to hedge or offset any decrease in the market value of HEP or HFC securities (or derivatives thereof), including through, among other mechanisms, the purchase of financial instruments (such as prepaid variable forward contracts, equity swaps, collars, and exchange funds) or other transactions that are designed to hedge or offset any decrease in the market value of shares of our common stock, regardless of how the securities (or derivatives thereof) were acquired. Additionally, all employees, including our named executive officers, are prohibited from holding shares of our common stock in a margin account or otherwise pledging shares of our common stock as collateral for a loan.
Director Compensation Table
The table below sets forth the compensation earned in 20172021 by each of the non-employee directors of HLS:
|
| | | | | | | | |
| Name (1) | Fees Earned or Paid in Cash | Unit Awards (2) | All Other Compensation | Total |
| Larry R. Baldwin | $138,000 | $90,026 | — |
| $228,026 |
| Matthew P. Clifton (3) | 218,500 |
| 80,003 |
| $160,705 (4) |
| 459,208 |
|
| Charles M. Darling, IV (3) | 133,500 |
| 80,003 |
| 160,705 (4) |
| 374,208 |
|
| R. Kevin Hardage (5)(6) | 28,200 |
| — |
| — |
| 28,200 |
|
| Michael C. Jennings | 120,630 |
| 90,026 |
| — |
| 210,656 |
|
| James H. Lee (5) | 12,978 |
| 90,032 |
| — |
| 103,010 |
|
| Jerry W. Pinkerton (3) | 49,500 |
| — |
| — |
| 49,500 |
|
| William P. Stengel (3) | 126,000 |
| 80,003 |
| 160,705 (4) |
| 366,708 |
|
| James G. Townsend (3) | 106,500 |
| 80,003 |
| 160,705 (4) |
| 347,208 |
|
| | | | | | | | | | | |
Name (1) | Fees Earned or Paid in Cash | Unit Awards (2) | Total |
| Larry R. Baldwin | $ | 150,000 | | $ | 115,019 | | $ | 265,019 | |
| Christine B. LaFollette | $ | 100,000 | | $ | 115,019 | | $ | 215,019 | |
| James H. Lee | $ | 100,000 | | $ | 115,019 | | $ | 215,019 | |
| Eric L. Mattson | $ | 125,000 | | $ | 115,019 | | $ | 240,019 | |
__________________
| |
(1) | Mr. Damiris is not included in this table because he received no additional compensation for his service on the Board since, during 2017, Mr. Damiris was an executive officer of HFC and HLS. The compensation paid by HFC to Mr. Damiris in 2017 will be shown in HFC’s 2018 Proxy Statement. A portion of the compensation paid to Mr. Damiris by HFC in 2017(1) Mr. Jennings is not included in this table because he received no additional compensation for his service on the Board during 2021, since he was an executive officer of HFC and HLS. The compensation paid by HFC to Mr. Jennings in 2021 will be shown in HFC’s 2022 Proxy Statement. A portion of the compensation paid to Mr. Jennings by HFC in 2021 is allocated to the services he performed for us in his capacity as an executive officer of HLS and is disclosed in the “Summary Compensation Table” below.
(2) Reflects the aggregate grant date fair value of phantom units granted to non-employee directors, computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”), determined without regard to forfeitures. See Note 9 to our consolidated financial statements for the fiscal year ended December 31, 2021, for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards.
On October 27, 2021, Messrs. Baldwin, Lee and Mattson and Ms. LaFollette and Mr. Mattson are not included in the table because they did not serve as directors in 2017. |
| |
(2) | Reflects the aggregate grant date fair value of restricted units granted to non-employee directors, computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”), determined without regard to forfeitures. See Note 6 to our consolidated financial statements for the fiscal year ended December 31, 2017, for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards. |
On November 1, 2017, Messrs. Baldwin, Clifton, Darling, Jennings, Stengel and Townsend received an award of 2,246 restricted6,076 phantom units that vests on December 1, 2018,2022, subject to continued service on the Board. Messrs. Clifton, Darling, Stengel and Townsend forfeited these restricted units in connection with their retirement from the Board on November 9, 2017. On November 10, 2017, Mr. Lee received an award of 2,443 restricted units that vests on December 1, 2018, subject to continued service on the Board, in connection with his appointment to the Board. On November 15, 2017, the Board approved an increase in the director equity retainer for 2018 from $80,000 to $90,000. As a result, on November 15, 2017, Messrs. Baldwin, Jennings and Lee received an additional award of 311 restricted units that vests on December 1, 2018, subject to continued service on the Board, since their prior awards in 2017 were based on a grant value of $80,000. As of December 31, 2017, Messrs. Baldwin and Jennings2021, these are the only phantom units held 2,557 restricted units and Mr. Lee held 2,754 restricted units. Mr. Hardage was not eligible to receive a grant of equity awards.by our current non-employee directors. For additional information regarding the annual restrictedphantom unit grants, please refer to the “Director Compensation” narrative above.
| |
(3) | In accordance with our director retirement policy, Mr. Pinkerton resigned from the Board effective June 30, 2017. On November 9, 2017, Messrs. Clifton, Darling, Stengel and Townsend retired from the Board. Each of them is included in the table since he served as a non-employee director during 2017. |
| |
(4) | Represents cash payment made to the director at the time of retirement as compensation for forfeited restricted units as a result of his retirement. |
| |
(5) | Mr. Lee was appointed to the Board effective November 10, 2017. Mr. Hardage was appointed to the Board effective November 14, 2017. |
| |
(6) | Because Mr. Hardage was appointed to fill a temporary vacancy on the HLS Board, he did not participate in the director compensation program and instead received $18,000 per month for his service on the Board. |
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires directors, executive officers and persons who beneficially own more than 10% of HEP’s units to file certain reports with the SEC and New York Stock Exchange concerning their beneficial ownership of HEP’s equity securities. Based on a review of these reports, other information available to us and written representations from reporting persons indicating that no other reports were required, all such reports concerning beneficial ownership were filed in a timely manner by reporting persons during the year ended December 31, 2017.
Item 11. Executive Compensation
Compensation Discussion and Analysis
This Compensation Discussion and Analysis provides information about our compensation objectives and policies for the HLS executive officers who are our “Named Executive Officers” for 20172021 to the extent the Compensation Committee and the Board, or our Chief Executive Officer determines the compensation of these individuals and about the compensation for our other Named Executive Officers that is allocated to us pursuant to Compensation Committee action or SEC rules. In addition, the Compensation Discussion and Analysis is intended to place in perspective the information contained in the executive compensation tables that follow this discussion and provide a description of our policies relating to reimbursement to HFC and HLS for compensation expenses.
Overview
We are managed by HLS, the general partner of HEP Logistics, our general partner. HLS is a subsidiary of HFC. The employees providing services to us are either provided by HLS, which utilizes people employed by HFC to perform services for us, or seconded to us by subsidiaries of HFC, as we do not have any employees.
For 2017,2021, our “Named Executive Officers” were:
|
| | | | |
| Name | Position with HLS in 20172021 |
George J. DamirisMichael C. Jennings | Chief Executive Officer and President |
| John Harrison | Senior Vice President, Chief Financial Officer and Treasurer |
| Richard L. Voliva III | Executive Vice President and Chief Financial Officer |
| Mark T. Cunningham | Senior Vice President, EngineeringOperations and Technical Services (1)Engineering |
Denise C. McWattersVaishali S. Bhatia | Senior Vice President, General Counsel and Secretary |
_______________
| |
(1) | Mr. Cunningham was appointed Senior Vice President, Operations and Engineering in January 2018. |
In October 2021, Mr. Cunningham announced his future retirement from all officer and employee positions, to be effective February 18, 2022. In preparation for his retirement, his responsibilities were transferred to four other individuals at HLS, effective January 1, 2022.
Certain of our Named Executive Officers are also officers of HFC or provide services to HFC. During 2017:2021:
•Mr. Cunningham spent all of his professional time managing our business and affairs and did not provide any services to HFC.
•Messrs. Damiris andJennings, Voliva and Harrison and Ms. McWatters,Bhatia, who we generally refer to as the “HFC Shared Officers,” also served as executive officers of HFC and devoted as much of their professional time as was necessary to oversee the management of our business and affairs. All compensation paid to such executive officers by HFC is paid and determined by HFC, without input from the Compensation Committee.
Compensation Committee Interlocks and Insider Participation
The members of the Compensation Committee of the Board are Messrs. Jennings and Lee and Ms. LaFollette. Mr. Jennings also serves as the Chief Executive Officer of HLS.None of the members who served on the Compensation Committee at any time during 2021 had any relationship requiring disclosure under Item 13 of this annual report on Form 10-K entitled “Certain Relationships and Related Transactions, and Director Independence.” No executive officer of HLS served as a member of the compensation committee of another entity that had an executive officer serving as a member of our Board or our Compensation Committee. No executive officer of HLS served as a member of the board of another entity that had an executive officer serving as a member of our Compensation Committee, except that Mr. Jennings also serves as the Chief Executive Officer of HFC.
Fees and Reimbursements for Compensation of Named Executive Officers
•Administrative Fee Covers HFC Shared Officers. Under the terms of the Omnibus Agreement we pay an annual administrative fee to HFC (currently $2.5$2.6 million) for the provision of general and administrative services for our benefit, which may be increased or decreased as permitted under the Omnibus Agreement. The administrative services covered by the Omnibus Agreement include, without limitation, the costs of corporate services provided to us by HFC such as accounting, tax, information technology, human resources, in-house legal support and office space, furnishings and equipment. None of the services covered by the administrative fee isare assigned any particular value individually. Although the administrative fee covers the services provided to us by the Named Executive Officers who are HFC Shared Officers, no portion of the administrative fee is specifically allocated to services provided by those Named Executive Officers to us. Rather, the administrative fee generally covers services provided to us by HFC and, except as described below, there is no reimbursement by us for the specific costs of such services. Typically we reflect our allocated amounts into cash compensation columns of the Summary Compensation Table, namely within the Base Salary column. For the 2021 year, the portion of compensation for certain Named Executive Officers exceeded base salaries, so there was a portion of compensation allocations that were reported in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table reflecting amounts earned pursuant to the HFC annual incentive bonus plan. A discussion of the non-equity incentive compensation payable by HFC will be disclosed in HFC’s 2022 Proxy Statement. See Item 13, “Certain Relationships and Related Transactions, and Director Independence” of this Annual Report on Form 10-K for additional discussion of our relationships and transactions with HFC.
•Reimbursements for Compensation of Dedicated HLS Officers. Under the Omnibus Agreement, we also reimburse HFC for certain expenses incurred on our behalf, such as for salaries and employee benefits for certain personnel employed by HFC who perform services for us on behalf of HLS, including the dedicated HLS officers, as described in greater detail below. The partnership agreement provides that our general partner will determine the expenses that
are allocable to us. In 2017,2021, we reimbursed HFC for 100% of the compensation expenses incurred by HFC for salary, bonus, retirement and other benefits provided to Mr. Cunningham. With respect to equity compensation paid by us to Mr. Cunningham, HLS purchases the units delivered pursuant to awards under our Long-Term Incentive Plan, and we reimburse HLS for the purchase price of the units.
CompensatoryCompensation Decisions for Dedicated HLS Officers
•Generally. The Compensation Committee, generally makespursuant to its charter, determines cash and bonus compensation decisionsonly for HLS’s Chief Executive Officer, President or Chief Financial Officer if such officers are solely dedicated to HLS and are not HFC Shared Officers. During 2021, HLS’s Chief Executive Officer, President and Chief Financial Officer were HFC Shared Officers, and as a result, the Compensation Committee did not set cash and bonus compensation for any executive officer. For 2021, the Compensation Committee made compensation recommendations, which were subsequently approved by the Board, for Mr. Cunningham only with respect to long-term equity incentive awards. All other compensation provided to Mr. Cunningham for 2021, other than with respect to pension and retirement benefits as described below. All compensation provided to Mr. Cunningham for 2017below, was determined by the Chief Executive Officer and President of HLS and is discussed and reported, in accordance with SEC rules, in the narratives and tables that follow.
•Pension and Retirement Benefits. The Compensation Committee does not review or approve pension or retirement benefits for any of the Named Executive Officers. Rather, all pension and retirement benefits provided to the executives are the same pension and retirement benefits that are provided to employees of HFC generally, and such benefits are sponsored and administered entirely by HFC without input from HLS or the Compensation Committee. The pension and retirement benefits provided to Mr. Cunningham in 20172021 are described below and were charged to us monthly in accordance with the Omnibus Agreement.
Allocation of Compensation and CompensatoryCompensation Decisions for HFC Shared Officers
•Generally. HFC makes all decisions regarding the compensation paid to the HFC Shared Officers, which compensation is covered by the administrative fee under the Omnibus Agreement (and therefore not subject to reimbursement by us); however, in accordance with SEC rules, for purposes of these disclosures, a portion of the compensation paid by HFC to the HFC Shared Officers for 20172021 is allocated to the services they performed for us during 2017.2021. The allocation was made based on the assumption that each of Messrs. Damiris andJennings, Voliva and Harrison and Ms. McWattersBhatia spent, in the aggregate, the following percentage of his or her professional time on our business and affairs in 2017:
2021:
|
| | | | |
| Name | Percentage of Time |
George J. DamirisMichael C. Jennings | 20% |
| John Harrison | 25% |
| Richard L. Voliva III | 20%30% |
Denise C. McWattersVaishali S. Bhatia | 30%25% |
Because HFC made all decisions regarding the compensation paid to Messrs. Damiris andJennings, Voliva, Harrison and Ms. McWattersBhatia for 2017,2021, those decisions are not discussed in this Compensation Discussion and Analysis. The total compensation paid by HFC to Messrs. DamirisJennings and Voliva and Ms. McWattersBhatia in 20172021 will be disclosed in HFC’s 20182022 Proxy Statement. The compensation paid by HFC to Mr. Harrison is discussed and disclosed in the tables that follow.
Objectives of Compensation Program
Our compensation program is designed to attract and retain talented and productive executives who are motivated to protect and enhance our long-term value for the benefit of our unitholders. Our objective is to be competitive with our industry and encourage high levels of performance from our executives.
In supporting our objectives, in applicable years, the Compensation Committee balancesconsiders the use of cash andcompensation to be received by the dedicated HLS officers when determining equity compensation in the total direct compensation package provided tofor the dedicated HLS officers; however, the Compensation Committee has not adopted any formal policies for allocating their compensation among salary, bonus and long-term equity compensation.
In the fourth quarter of 2016,2020, the Compensation Committee, with the assistance of the Chief Executive Officer and President, reviewed the mix and level of cash and long-term equity incentive compensation for Mr. Cunningham with a goal of providing competitive compensation for 20172021 to retain him, while at the same time providing him incentives to maximize long-term value for us and our unitholders. After reviewing internal evaluations, input by management, and market data provided by the Compensation Consultant, the Compensation Committee believes that the 2017 compensation paid to Mr. Cunningham reflects an appropriate allocation of compensation between salary, bonus and equity compensation.
Role of the Compensation Consultant and the CompensationCommittee in the Compensation Setting Process
In 2017,Since 2018, the Compensation Committee has retained Frederic W. Cook & Co. (the “Compensation Consultant” or “FWC”),Meridian, a consulting firm specializing in executive compensation, to advise the Compensation Committee on matters related to executive and non-employee director compensation, including benchmarking of the compensation peer group for non-employee director compensation, and long-term equity incentive awards. The Compensation Consultant provided the Compensation Committee with market data, updates on related trends and developments, advice on program design, and input on compensation decisions for executive officers and non-employee directors.As discussed above under “-The“The Board, Its Committees and Director Compensation-Board Committees-CompensationCompensation–Board Committees–Compensation Committee,” the Compensation Committee has concluded that we do not have any conflicts of interest with FWC.Meridian.
The Compensation Committee generally makes compensation decisions for a given fiscal year in the fourth quarter of the prior year.The Compensation Consultant does not have authority to determine the ultimate compensation paid to executive officers or non-employee directors, and the Compensation Committee is under no obligation to utilize the information provided by the Compensation Consultant when making compensation decisions.The Compensation Consultant provides external context and
other input to the Compensation Committee prior to the Compensation Committee approving salaries and fees, awarding bonuses and equity compensation or establishing awards for the upcoming year.
In January 2018, the Compensation Committee engaged Meridian Compensation Partners, LLC (“Meridian”). Meridian did not provide anyprovided information orand advice to the Compensation Committee in 2020 with respect to 2017 executivematters related to non-management director compensation, including benchmarking of the compensation peer group for non-employee director compensation, and employee long-term equity incentive awards for 2021. The Compensation Committee is aware that Meridian is also providing similar services to the compensation committee at HFC but our Compensation Committee manages its relationship with Meridian independently of the relationship that Meridian has with the HFC compensation committee.The aggregate amount of fees HLS paid to Meridian for the services it engaged Meridian to perform during the 2021 fiscal year was approximately $19,907. The aggregate amount of fees HFC paid to Meridian for the services it engaged Meridian to perform during the 2021 fiscal year was approximately $263,000.
The Compensation Committee, pursuant to its charter, determines cash and annual incentive compensation for only HLS’s Chief Executive Officer, President or Chief Financial Officer, if such officers are solely dedicated to HLS and are not HFC Shared Officers. For all HLS officers who are eligible to receive equity awards under HEP’s equity plans, the Compensation Committee will review and recommend to the Board for approval, long-term equity incentive compensation.
Review of Market Data
Market pay levels are one of many factors considered by the Compensation Committee in setting equity compensation for the Named Executive Officers. TheIn 2020, the Compensation Committee regularly reviewsreviewed comparison data provided by the Compensation Consultant with respect to salary, annual incentive levels and long-term incentive levels as one point of reference in evaluating the reasonableness and competitiveness of the incentive compensation paid to our executive officers as compared to companies with which we compete for executive talent. In addition, the Compensation Committee reviewsreviewed such data to evaluate whether our incentive compensation reflects practices of comparable companies of generally similar size and scope of operations. The Compensation Consultant obtainsobtained market information primarily from SEC filings of publicly traded companies that the Compensation Consultant and the Compensation Committee consider appropriate peer group companies and, from time to time, from published compensation surveys (such asthe Liquid Pipeline Roundtable Compensation Survey). The purpose of the peer group is to provide a frame of reference with respect to executive equity compensation at companies of generally comparable size and scope of operations, rather than to set specific benchmarks for the compensation provided to the Named Executive Officers. We select peer group companies that we believe provide relevant data points for our consideration.
The peer group used in determining 20172021 equity compensation included the following publicly traded master limited partnerships,companies, which are representative of the companies with which we compete for executives:talent:
|
| | | | |
Boardwalk PipelineAntero Midstream Corporation | Enable Midstream Partners, LP |
| Black Stone Minerals, L.P. | NGL EnergyEnLink Midstream Partners, LP |
Calumet Specialty ProductsCallon Petroleum Company | Phillips 66 Partners LP | NuStar Energy LP |
| Centennial Resource Development, Inc. | Shell Midstream Partners, L.P. |
| Crestwood Equity Partners LP | Rose Rock Midstream LP |
DCP Midstream Partners LP | Summit Midstream Partners, LP |
EnLink MidstreamDelek Logistics Partners, LP | Targa Resources PartnersTC Pipelines, LP |
Genesis Energy LP | USA Compression Partners LP |
The peer group used in 2017for 2021 compensation was changedadjusted from the peer group used in 2016with respect to 2020 compensation due to merger activity.consolidation and simplification across the midstream industry sector and recommendations from the Compensation Consultant.
OurFor years in which we make the compensation decisions for our executive officers, our objective generally is to position pay at levels approximately in the middle range of market practice, taking into account median levels derived from our peer group analysis. Following advice from the Compensation Consultant, we consider our salary and non-salary compensation components relative to the median compensation levels generally within the peer group rather than to an exact percentile above or below the median. For these purposes, if compensation is generally within plus or minus 20% of the market median, it is considered to be in the middle range of the market.
In 2017, the total direct compensation paid to Mr. Cunningham was generally in the middle range of the market. As noted, however, this market analysis is just one of many factors considered when making overall compensation decisions for our executives.
Role of Named Executive Officers in Determining Executive Compensation
In making executive equity compensation decisions for 2021 for Mr. Cunningham, the Compensation Committee reviewsreviewed the total compensation provided to each executivehim in the prior year, the executive’shis overall performance and market data provided by the Compensation Consultant. The Compensation Committee also considersconsidered recommendations by the Chief Executive Officer and President and other factors in determining the appropriate final equity compensation amounts.amounts to recommend to the Board.
Various members of management facilitatefacilitated the Compensation Committee’s consideration of equity compensation for Named Executive Officers by providing data for the Compensation Committee’s review. This data includes, but is not limited to, performance evaluations, performance-based compensation provided to the Named Executive Officers in previous years, tax-related considerations and accounting-related considerations. Management provides the Compensation Committee with guidance as to how such data impacts performance goals set by the Compensation Committee during the previous year. Given the day-to-day familiarity that management has with the work performed, the Compensation Committee values management’s recommendations, although no Named Executive Officer has authority to determine or comment on compensation decisions directly related to himself.himself or herself. As described above, the Compensation Committee makesreviewed and made a recommendation to the final decisionBoard as to the long-term equity compensation of Mr. Cunningham.Cunningham for 2021.
In the fourth quarter of 2020, the Chief Executive Officer and President reviewed information similar to that provided to the Compensation Committee for purposes of determining salary and bonus compensation for Mr. Cunningham for 2021. The Chief Executive Officer sets compensation for his direct reports who are solely dedicated to HLS and who do not serve as President of HLS, and the President sets compensation for his direct reports who are solely dedicated to HLS and who do not serve as Chief Financial Officer of HLS.
Overview of 20172021 Executive Compensation Components and Decisions
In 2017, the Compensation Committee made compensation decisions for Mr. Cunningham. The components of compensation received by Mr. Cunningham in 20172021 are as follows:
•base salary;
•annual incentive cash bonus compensation;
•long-term equity incentive compensation;
•severance and change in control benefits;
•health and retirement benefits; and
•perquisites.
Each of these components is described in further detail in the narrativenarratives and/or tables that follows.follow.
Base Salary
The Compensation Committee conducted its annual review of baseBase salary for Mr. Cunningham for 2021 was determined by the President of HLS in the fourth quarter of 2016.2020. The Compensation CommitteePresident considered hisMr. Cunningham’s position, level of responsibility and performance in 2016, where applicable.2020. The Compensation CommitteePresident also reviewed competitive market data relevant to his position provided by the Compensation Consultant.position. Following a review of the various factors listed above, the Compensation Committee determined the following 2017Mr. Cunningham’s 2021 base salary forwas $342,505, which was effective January 1, 2021 and which represented a 2.7% increase from Mr. Cunningham:Cunningham’s 2020 base salary of $333,500.
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| | | |
| Name | 2016 Base Salary | 2017 Base Salary (1) | Percentage Increase from 2016 |
| Mark T. Cunningham | $300,000 | $303,000 | 1% |
______________________
| |
(1) | Represents salary effective January 1, 2017. |
Annual Incentive Cash Bonus Compensation
The Board adopted the HLS Annual Incentive Plan (the “Annual Incentive Plan”) in August 2004 to motivate eligible employees to produce outstanding results, encourage growthTarget awards and superior performance, increase productivity, contribute to health and safety goals, and aid in attracting and retaining key employees. The Compensation Committee oversees the administration of the Annual Incentive Plan, and any potential awards granted pursuant to the plan are subject to final determination by the Compensation Committee of achievement of the performance metrics for the applicable performance periods.
In2021 annual incentive plan for Mr. Cunningham were determined by the fourth quarterPresident of 2016, the Compensation Committee approved target awards under the Annual Incentive Plan for 2017 based on a pre-established percentage of Mr. Cunningham’s base salary and determined that the applicable performance period for the Annual Incentive Plan awards would be the 12-month period beginning October 1, 2016 and ending September 30, 2017, with determination and payment of the cash bonus amounts occurringHLS in the fourth quarter of 2017.2020.
The 2017 Annual Incentive Plan award for Mr. Cunningham was subject to achievement of the following metrics:
Actual Distributable Cash Flow vs. Budget: Half of the target award may be earned based upon our actual distributable cash flow during the performance period compared to the budgeted distributable cash flow for the performance period, adjusted for differences in estimated and actual Producers Price Index adjustments and differences in the timing of known acquisitions.
The payout on this metric is based on the following:
|
| |
| Actual Distributable Cash Flow vs. Budget | Bonus Achievement (1) |
| Less than 100% | Actual Distributable Cash Flow as Percentage of Budget |
| 100% | 100% |
| Greater than 100% | 100% plus 3% for each 1% Actual Distributable Cash Flow exceeds Budget |
_________________________
| |
(1) | The percentages are interpolated between percentage points and rounded to the nearest hundredth percent. |
The performance metric of actual distributable cash flow is used because it is a widely accepted financial indicator for comparing partnership performance. We believe that this measure provides an enhanced perspective of the operating performance of our assets and the cash our business is generating, and is therefore a useful criterion in evaluating management’s performance and in linking the payout of the award to our performance.
Individual Performance: The other half of the target award may be earned based on the employee’s individual performance during the performance period, as determined in the discretion of the employee’s immediate supervisor. The employee’s individual performance is evaluated through a performance review by the employee’s immediate supervisor, which includes a written assessment. The assessment reviews several criteria, including how well the employee performed his or her pre-established individual goals during the performance period and the employee’s interpersonal effectiveness, integrity, and business conduct.
The Compensation Committee also has discretion to approve an increase or a decrease in the bonus amount an executive officer would otherwise earn. Any increases or decreases are determined based on a variety of factors, including performance with respect to the pre-defined performance metrics as well as environmental, health and safety and conditions outside the control of the executive that could have affected the performance metrics. If the Compensation Committee believes additional compensation is warranted to reward an executive for outstanding performance, the Compensation Committee may increase the executive’s bonus amount in its discretion. Alternatively, poor results could, in the discretion of the Compensation Committee, result in a decrease in a bonus. In making the determination as to whether such discretion should be applied (either to decrease or increase a bonus), the Compensation Committee reviews recommendations from management.
The following table sets forth the minimum, target and maximum award opportunities (as a percentage of annual base salary) for Mr. Cunningham for 2017,2021, and the portion of hisMr. Cunningham’s target award opportunity that is allocated to each performance metric. measure (as a percentage of his annual base salary). These target percentages were unchanged from the 2020 year.
| | | | | | | | | | | | | | | | | | | | |
| | Award Opportunities | Allocation Among Performance Measures
(as a percentage of annual base salary) |
| Name | Minimum | Target | Maximum | Financial
Measures | Operational Measures | Strategic and Individual Measures |
| Mark T. Cunningham | 22.5% | 45.0% | 90.0% | 18% | 18% | 9% |
The financial measures are weighted equally with the operational measures. Awards are capped to avoid encouraging an excessive short-term focus, potentially at the expense of long-term performance.
To facilitate timely determination of award opportunity amounts and allocations were not changed from 2016payouts, the measurement period for Mr. Cunningham.
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| | | | |
| | Allocation Between Performance Metrics | Award Opportunities |
| Name | Actual vs. Budgeted DCF | Individual | Target | Maximum |
| Mark T. Cunningham | 20.0% | 20.0% | 40.0% | 80.0% |
Following the endeach of the performance period,above metrics covers four consecutive quarters starting with the Chief Executive Officer evaluates the extent to which the applicable performance metrics have been achieved and recommends a bonus amount for the executive officer to the Compensation Committee. The Compensation Committee then determines the actual amountfourth quarter of the bonus award earned bypreceding year (2020) and payable toending with the executive officer. Pursuantthird quarter of the following year (2021).
These awards were subject to our Annual Incentive Plan, the Compensation Committee determines actual achievement of eachspecified levels of performance metric individually and the percentages determined with respect to the twofinancial, operational and strategic and individual performance metrics are then added together and multiplied by the individual’s base salary to calculate the bonus amount.
For the 2017 performance period, the actual distributable cash flow ($238.9 million) exceeded the budgeted distributable cash flow ($232.0 million) by approximately 2.9%. As a result, the payout on this metric was approximately 110% of the portion of the target award related to this metric.measures. The following table sets forth the various components for each measure.
| | | | | | | | |
| Performance Measure (percentage of the annual bonus awards) | Components (percentage of each performance measure) | How It’s Measured (percentage of each component) |
| Financial (40%) | EBITDA | Cumulative EBITDA performance of HEP vs. Cumulative Target for HEP |
| Operational (40%) | • Environmental, Health and Safety (40%)(1)
• Reliability (40%) (2)
• Operating Expense vs. Budget (20%) (3)
| • Recordable Injury Rate
• Lost Time Injuries
• Vehicle Incidents
• Employee Based Environmental Releases
• Solomon Liquid Pipeline Availability
|
| Strategic and Individual (20%) | Relevant individual metrics for each named executive officer | Mark T. Cunningham
• Safety and environmental
• Capital project management |
(1)The EHS metric is divided into the following four equally weighted measures:
•Recordable Injury Rate, which is based on the number of employees out of 100 that have been involved in a recordable event.
•Lost Time Injury, which is based on the number of injuries causing an employee to miss work.
•Vehicle Incidents, which is based on the number of incidents generating greater than $5,000 of property damage per 1,000,000 miles driven by HEP employees.
•Employee Based Environmental Releases, which is based on loss of containment caused by an employee that is reportable to either a state or federal agency.
(2)The reliability metric is based on the weighted average Solomon Liquid Pipeline Availability.
(3)Operating Expense includes all direct and controllable cash operating costs, which includes Selling, General and Administrative (SG&A) costs. Budgeted costs exclude asset write-downs, impairments, inventory valuation charges, unbudgeted litigation and legal settlement costs, environmental charges resulting from events which occurred prior to the beginning of the performance period, variable energy and utility costs, and unbudgeted bonus expenses and costs related to unbudgeted new capital assets brought online and acquisitions made during the period. The metric is based on the actual payoutcash operating expense of each segment versus the budgeted cash operating expense for 2017each segment.
Financial Measures
The table below sets forth the threshold, target and maximum performance levels for each financial measure and the actual results for the financial measures in 2021:
| | | | | | | | | | | | | | | | | |
| Metric | Threshold (50%) | Target
(100%) | Maximum (200%) | Actual for 2021 | Percent of
Target Bonus
Achievement |
| EBITDA (in millions) | $330 | $348 | $365 | $351 | 120% |
________________________
Payouts are interpolated between threshold and target and target and maximum.
Operational Measures
The table below sets forth the threshold, target and maximum performance levels for each operational measures and the actual results for the operational measures in 2021:
| | | | | | | | | | | | | | | | | | | | |
| Metric | Threshold (50%) | Target
(100%) | (200)% | Maximum (250%) | Actual for
2021 | Percent of
Target Bonus
Achievement |
| EH&S | | | | | | 238% |
| Recordable Injury Rate | 1.0 | 0.80 | 0.60 | 0 | 0 | 250% |
| Lost Time Injuries | 2 | 1 | n/a | 0 | 0 | 250% |
| Vehicle Incidents | 1.8 | 1.4 | 1.0 | 0 | 0.65 | 200% |
| Employee Based Environmental Releases | 3 | 2 | 1 | 0 | 0 | 250% |
______________________
Payouts are interpolated between thresholds and targets and target up to a 200% payout. To achieve a maximum payouts, no incidents are allowed.
| | | | | | | | | | | | | | | | | |
| Metric | Threshold (50%) | Target (100%) | Maximum (200%) | Actual for 2021 | Percent of
Target Bonus
Achievement |
| Reliability | 98.0% Available | 98.75% Available | ≥ 99.5% Available | 99.86% | 200% |
| Operating Expense | 5% over Budget | Budget | 5% or more under Budget | 4.7% under Budget | 194% |
_________________________
Payouts are interpolated between threshold and target and target and maximum.
The total percent of target bonus achieved for the operational measures was 214%.
Strategic and Individual Performance Measures
In addition to the measures mentioned above, a portion of the award for Mr. Cunningham was based on the President’s evaluation of Mr. Cunningham’s strategic and individual performance during the year. Mr. Cunningham achieved 100% of his target bonus for the strategic and individual performance measures.
2021 Performance
The following table sets forth Mr. Cunningham’s target bonus as a percentage of base salary including payments made based onand the actual distributable cash flow versus budget and discretionary bonuses awardedpayouts to Mr. Cunningham for individual performance.
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| | | |
| Name | Actual vs. Budgeted DCF | Individual | Total |
| Mark T. Cunningham | 22.0% | 20.0% | 42.0% |
| | | | | | | | | | | | | | | | | | | | |
| Name | Target Bonus | Financial Measures | Operational Measures | Strategic and Individual Measures | Percentage of Base Salary Earned | Percentage of Target Bonus Earned |
| Mark T. Cunningham | 45% | 21.6% | 38.5% | 11.3% | 71.3% | 158.4% |
Long-Term Equity Incentive Compensation
The Long-Term Incentive Plan was adopted by the Board in August 2004 with the objective of:
•promoting our interests by providing equity incentive compensation awards to eligible individuals,individuals;
•enhancing our ability to attract and retain the services of individuals who are essential for our growth and profitability,profitability;
•encouraging those individuals to devote their best efforts to advancing our business,business; and
•aligning the interests of those individuals with the interests of our unitholders.
The Compensation Committee and the Board typically grantsgrant long-term equity incentive awards to dedicated HLS officers on an annual basis. The Compensation Committee makes annualAnnual long-term equity incentive award grants are made in the fourth quarter of the year preceding the year to which the award relates, in order to align the timing of the long-term equity incentive award grants with the timing of the other compensation decisions made for the dedicated HLS officers.As a result, annual long-term equity incentive awards for the 20172021 year were granted in October 20162020 to the individuals who were dedicated HLS officers at that time.Pursuant to SEC rules, the long-term equity incentive awards granted in October 20162020 for the 20172021 year are disclosed as 20162020 compensation in the Summary Compensation Table (with respect to those Named Executive Officers who received long-term equity incentive awards from us in October 2016 and who were Named Executive Officers for 2016)2020) and are not included in the 20172021 Grants of Plan-Based Awards table; however, because these awards relate to the 20172021 year, they are described in greater detail below.
In determining the appropriate amount and type of long-term equity incentive awards to be granted each year, the Compensation Committee considersand the Board consider the executive’s position, scope of responsibility, base salary and available compensation information for executives in comparable positions in similar companies.Our goal is to reward the creation of value and strong performance with variable compensation dependent on that performance.
For the 20172021 year, the Compensation CommitteeBoard awarded both restrictedphantom units and performance units to Mr. Cunningham.Due to SEC rules regarding the timing of disclosures, Mr. Cunningham’s awards with respect to the 2021 year are reflected in the Executive Compensation Tables below as awards granted in the 2020 year.It is generally our practice not to make long-term equity incentive award grants to the HFC Shared Officers.Any equity compensation awards granted by HFC for 20172021 to any of the HFC Shared Officers will be disclosed in HFC’s 20182022 Proxy Statement.Statement to the extent such individuals are “named executive officers” of HFC for the 2021 year.
Restricted
Phantom Unit Awards
In October 2016,2020, Mr. Cunningham was granted restricted units. phantom units with respect to 2021 services.The number of restrictedphantom units awarded iswas initially approvedrecommended by the Compensation Committee, and approved by the Board. Mr. Cunningham’s award was in a dollar amountsamount established according to thehis pay grade of the executive officer. grade.The award is then converted to a number of units by dividing the targeted dollar amount by the closing price of our common units on the grant date of the award.The following table sets forth the number of restrictedphantom units awarded to Mr. Cunningham in October 20162020 for the 20172021 fiscal year:
|
| | | | |
| Name | Number of RestrictedPhantom Units |
| Mark T. Cunningham | 4,12813,635 |
RestrictedPhantom unitholders have all the rights of a unitholder with respect to the restricted units, including the right to receive alldistribution equivalents and other distributions paid with respect to such restrictedphantom units, (atand these distribution equivalents are paid at approximately the same ratetime as distributions are paid on our common units) and any right to vote with respect to the restricted units, subject to limitations on transfer and disposition of the units during the restricted period.units. The distributionsdistribution equivalents are not subject to forfeiture.
The restrictedphantom units granted to Mr. Cunningham in October 20162020 vest in three equal annual installments as noted inaccording to the following table and will be fully vested and nonforfeitable after December 15, 2019.schedule below, subject to continued employment by the unitholder.
|
| | | | |
RestrictedPhantom Unit Vesting Criteria |
Vesting Date (1) | Cumulative Amount of RestrictedPhantom Units Vested |
Immediately following December 15, 20171, 2021 | 1/3 |
Immediately following December 15, 20181, 2022 | 2/3 |
Immediately following December 15, 20191, 2023 | All |
(1) Vesting will occur on the first business day following December 15the vesting date set forth above if December 15the vesting date falls on a Saturday or a Sunday. The provisions affecting the vesting of these awards upon a change in control or certain terminations of employment are described in greater detail below in the section titled “Potential Payments upon Termination and Change in Control.”
In connection with Mr. Cunningham's retirement on February 18, 2022, 2,092 phantom units granted under his 2020 phantom unit award described above vested on a pro rata basis in an amount attributable to the portion of the period of service Mr. Cunningham completed during the applicable vesting period and the remainder of the unvested phantom unit award was forfeited.
Performance Unit Awards
A performance unit is a notational phantom unit that entitles the grantee to receive a common unit upon the attainment of pre-established performance targets over a specified performance period, which may include the achievement of specified financial objectives determined by the Compensation Committee and the Board, and satisfaction of certain continued service conditions.
In October 2016,2020, Mr. Cunningham was granted performance units with a performance period that began on January 1, 20172021 and ends on December 31, 2019.2023. An executive officer generally must remain employed through the end of the performance period to be eligible to earn any of the performance units. The provisions affecting the vesting of these awards upon a change in control or certain terminations of employment are described below in the section titled “Potential Payments upon Termination and Change in Control.”
With respect to the performance unit awards for the 20172021 year, Mr. Cunningham was granted a target number of performance units. The target number iswas initially recommended by the Compensation Committee, and approved by the Compensation CommitteeBoard, in dollar amounts established according to the pay grade of the executive officer. The target award is then converted to a number of units by dividing the targeted dollar amount by the closing price of our common units on the grant date of the award. The
following table sets forth the target number of performance units granted to Mr. Cunningham in October 20162020 for the 20172021 year:
|
| | | | |
| Name | Target Number of Performance Units |
| Mark T. Cunningham | 4,12813,635 |
The Compensation CommitteeBoard determined that performance metrics for the increase in distributable cash flow per common unitOctober 2020 grants would consist of (a) actual EBITDA compared to target EBITDA and (b) total unitholder return during the performance period should be used as measured against that of the performance objective forfollowing incentive peer group:
| | | | | |
| Archrock Partners, L.P. | PBF Logistics LP |
| Crestwood Equity Partners LP | Phillips 66 Partners LP |
| Delek Logistics Partners, LP | Shell Midstream Partners, L.P. |
| Enable Midstream Partners, LP | Summit Midstream Partners, LP |
| EnLink Midstream Partners, LP | TC Pipelines, LP |
| MPLX LP | |
For the performance unit awards granted in October 2016. The actual number2020 for the 2021 fiscal year:
•“EBITDA,” which determines 50% of the units earned at the end of the performance period, is baseddefined as our earnings before interest, taxes, depreciation and amortization for each calendar year during the performance period. The Board believes EBITDA is an appropriate metric because it measures HEP’s profitability before the effects of items such as financings, capital expenditures and taxes.
•“total unitholder return,” which determines 50% of the units earned at the end of the performance period, is defined as (a) the appreciation in our unit price during the performance period (in dollars) plus cumulative distributions paid during the performance period plus any additional value or compensation received by unitholders such as units received from spinoffs, divided by (b) the closing price of our common units on the “Achieved Distributable Cash Flow/Unit” as comparedfirst business day of the performance period. The Compensation Committee believes total unitholder return is an appropriate metric because it (i) aligns the interests of management with the interests of unitholders and (ii) provides a useful means of comparing our overall performance relative to the “Base Distributable Cash Flow/Unit,” “Target Distributable Cash Flow/Unit” and “Incentive Distributable Cash Flow/Unit.” Specifically, theoverall performance of our incentive peer group.
The actual number of performance units earned at the end of the performance period will be determined by multiplyingequal to (a) the target number of performance units awardedgranted multiplied by (b) our average performance unit payout with respect to the applicable performance metrics. The average performance unit payout is determined by adding our performance unit payout percentage as follows:with respect to each performance metric and dividing the sum by two.
For the EBITDA metric, actual aggregate EBITDA achieved during the performance period is compared to the aggregate Target EBITDA during the performance period and payout is determined in accordance with the following table:
Each Change in Control Agreement under our Change in Control Policy terminates on the day prior to the three-year anniversary of its effective date, and thereafter automatically renews for successive one-year terms (on each anniversary date thereafter) unless a cancellation notice is given by us 60 days prior to the automatic extension date. The Change in Control Agreements provide that if, in connection with or within two years after a “Change in Control” of HFC, HLS, HEP Logistics or HEP (1) the executive’s employment is terminated by HFC, HLS, HEP Logistics or HEP without “Cause,” by the employee for “Good Reason,” or as a condition of the occurrence of the transaction constituting the “Change in Control,” or (2) the executive does not remain employed by HFC, HLS, HEP Logistics or HEP or any of their respective affiliates or the executive is not offered employment with HFC, HLS, HEP, HEP Logistics or any of their affiliates on substantially the same terms in the aggregate as his previous employment within 30 days after the termination, then the executive will receive the following cash severance amounts paid by us:
The executive will also receive continued participation by the executive and his or her dependents in medical and dental benefits for the number of years equal to the executive’s designated severance multiplier, which, in the case of Mr. Cunningham, is one year.
For purposes of the Change in Control Agreements, a “Change in Control” occurs if:
For purposes of the Change in Control Agreements, “Good Reason” is defined as, without the express written consent of the executive:
All payments and benefits due under the Change in Control Agreements will be conditioned on the execution and non-revocation by the executive of a release of claims for the benefit of HFC, HLS, HEP and HEP Logistics and their related entities and agents. The Change in Control Agreements also contain confidentiality provisions pursuant to which each executive agrees not to disclose or otherwise use the confidential information of HFC, HLS, HEP or HEP Logistics. Violation of the confidentiality provisions entitles HFC, HLS, HEP or HEP Logistics to complete relief, including injunctive relief. Further, in the event of a breach of the confidentiality covenants, the executive could be terminated for Cause (provided the breach constituted willful gross negligence or misconduct on the executive’s part that is not inconsequential). The agreements do not prohibit the waiver of a breach of these covenants.
If amounts payable to an executive under a Change in Control Agreement (together with any other amounts that are payable by HFC, HLS, HEP or HEP Logistics as a result of a change in ownership or control) exceed the amount allowed under Section 280G of the Internal Revenue Code for such executive by 10% or more, we will pay the executive an amount necessary to allow the executive to retain a net amount equal to the total present value of the payments on the date they are to be paid. Conversely, if the payments exceed the 280G limit for the executive by less than 10%, the payments will be reduced to the level at which no excise tax applies.
The outstanding long-term equity incentive awards granted under the Long-Term Incentive Plan to our Named Executive Officers vest upon a “Special Involuntary Termination,” which occurs when, within 60 days prior to or at any time after a “Change in Control”: